10-Q

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, 2014
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 incorporation or organization)	(I.R.S. Employer Identification No.)
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	¨		Accelerated filer	þ
Non-accelerated filer	¨	(Do not check if a smaller reporting company)	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, 2014
Common Stock, $0.01 par value	179,983,515 shares

DEFINITIONS

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

“ABR” means alternate base rate

“AECO” is a reference, in U.S. dollars per MMbtu, for gas delivered at a trading hub on the NOVA Gas Transmission Ltd. System in Alberta, Canada

“AOCI” means accumulated other comprehensive income

“Bbl” or “Bbls” means barrel or barrels

“Bbld” means barrel or barrels per day

“Boed” means barrels of oil equivalent per day, calculated as six Mcf of gas equaling one Bbl of oil

“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 thousand barrels per day

“MMBtu” means million BTUs

“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

“NYMEX” means New York Mercantile Exchange

“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:

“Alliance Asset” means all of our natural gas leasehold and royalty interests in northern Tarrant and southern Denton counties

“Amended and Restated Canadian Credit Facility” means our Canadian senior secured revolving credit facility which was amended and restated, effective December 22, 2011, and as further amended, restated, supplemented or otherwise modified from time to time

“Amended and Restated U.S. Credit Facility” means our U.S. senior secured revolving credit facility which was amended and restated, effective December 22, 2011, and as further amended, restated, supplemented or otherwise modified from time to time

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

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

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

“Eni Transaction” means the 2009 conveyance to Eni of 27.5% of Quicksilver's interest in our Alliance Asset

“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 with KKR and dedicated to the construction and operation of natural gas midstream services within the Horn River basin of northeast British Columbia

“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

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

“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

“Niobrara Asset” means our operations and our assets in the Niobrara formation in northwest Colorado, which we were jointly developing with SWEPI LP and which were sold in the Southwestern Transaction

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

“Second Lien Notes” means our senior secured second lien notes issued June 21, 2013

“Second Lien Term Loan” means our senior secured second lien term loan agreement, effective June 21, 2013

“Southern Alberta Basin Asset” means our operations and our assets in the Southern Alberta basin of northern Wyoming and Montana, including our Cutbank field operations and assets, which were sold in the Synergy Transaction

“Southwestern Transaction” means the sale of our Niobrara Asset to Southwestern Energy Company

“SWEPI” means SWEPI LP, a subsidiary of Royal Dutch Shell plc

“Synergy” means Synergy Offshore LLC

“Synergy Transaction” means the sale of our Southern Alberta Basin Asset to Synergy

“Tokyo Gas Transaction” means the sale of an undivided 25% of our Barnett Shale Asset to TGBR

“TGBR” means TG Barnett Resources LP, a wholly-owned U.S. subsidiary of Tokyo Gas Co., Ltd.

“VIE” means variable interest entity

“West Texas Asset” means our operations and our assets in the Delaware basin in West Texas, which we believe is prospective for the Bone Springs and Wolfcamp formations, principally concentrated in Pecos County, Texas

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INDEX TO QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2014

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	31
Item 3. Quantitative and Qualitative Disclosures About Market Risk	54
Item 4. Controls and Procedures	56
PART II. OTHER INFORMATION	58
Item 1. Legal Proceedings	58
Item 1A. Risk Factors	58
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	58
Item 3. Defaults Upon Senior Securities	58
Item 4. Mine Safety Disclosures	58
Item 5. Other Information	59
Item 6. Exhibits	60
Signature	61

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.

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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,” “contemplate,” “estimate,” “anticipate,” “believe,” “project,” “target,” “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;

• failure to satisfy our short- or long-term liquidity needs, including the ability to access necessary capital resources and address near-term debt maturities;

• fluctuations in natural gas, NGL and oil prices;

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

• our ability to achieve anticipated cost savings and other spending reductions and operational efficiencies;

• failure to comply with covenants under our Combined Credit Agreements and other indebtedness, the resulting acceleration of debt thereunder and the inability to make necessary repayments or to make additional borrowings;

• uncertainties inherent in estimates of natural gas, NGL and oil reserves and predicting natural gas, NGL and oil production and 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, particularly in completing a transaction involving the sale of any or all of our assets, including our Horn River Asset;

• failure to make the necessary expenditures under or related to our contractual commitments, including our spending requirement pursuant to Fortune Creek;

• the effects of existing or future litigation; 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, including any amendments thereto. 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.

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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,
	2014			2013			2014			2013
Revenue
Production	$	102,615		$	104,546		$	332,187		$	358,281
Sales of purchased natural gas	16,660			15,130			53,401			50,373
Net derivative gains (losses)	43,310			32,733			(15,080		)	36,202
Other	913			707			2,808			2,462
Total revenue	163,498			153,116			373,316			447,318
Operating expense
Lease operating	17,176			18,591			54,622			63,699
Gathering, processing and transportation	34,807			35,567			102,511			112,064
Production and ad valorem taxes	4,067			4,678			12,557			15,462
Costs of purchased natural gas	16,599			15,114			53,305			50,311
Depletion, depreciation and accretion	13,969			14,390			42,584			47,911
Impairment	135			—			135			—
General and administrative	11,310			10,471			38,115			43,509
Other operating	651			2,230			2,221			4,435
Total expense	98,714			101,041			306,050			337,391
Gain on Tokyo Gas Transaction	—			7,974			—			341,146
Operating income	64,784			60,049			67,266			451,073
Other income (expense) - net	(2,465		)	667			(3,824		)	(14,588		)
Fortune Creek accretion	(3,602		)	(4,818		)	(11,605		)	(14,490		)
Interest expense	(39,899		)	(39,355		)	(121,927		)	(210,535		)
Income (loss) before income taxes	18,818			16,543			(70,090		)	211,460
Income tax benefit (expense)	4,939			(5,966		)	(1,081		)	(18,063		)
Net income (loss)	$	23,757		$	10,577		$	(71,171	)	$	193,397
Reclassification adjustments related to settlements of derivative contracts into production revenue- net of income tax	(7,968		)	(11,139		)	(20,939		)	(37,181		)
Foreign currency translation adjustment	(6,921		)	2,345			(6,162		)	(933		)
Other comprehensive loss	(14,889		)	(8,794		)	(27,101		)	(38,114		)
Comprehensive income (loss)	$	8,868		$	1,783		$	(98,272	)	$	155,283
Earnings (loss) per common share - basic	$	0.13		$	0.06		$	(0.41	)	$	1.10
Earnings (loss) per common share - diluted	$	0.13		$	0.06		$	(0.41	)	$	1.10

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

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data – Unaudited

	September 30, 2014			December 31, 2013
ASSETS
Current assets
Cash and cash equivalents	$	248,325		$	89,103
Marketable securities	—			166,343
Total cash, cash equivalents and marketable securities	248,325			255,446
Accounts receivable - net of allowance for doubtful accounts	59,491			58,645
Derivative assets at fair value	66,098			57,523
Other current assets	22,386			22,346
Total current assets	396,300			393,960
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $218,398 and $221,605, respectively)	608,572			640,443
Other property and equipment	203,908			220,362
Property, plant and equipment - net	812,480			860,805
Derivative assets at fair value	25,968			73,357
Other assets	33,509			41,604
	$	1,268,257		$	1,369,726
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	13,587		$	28,822
Accrued liabilities	94,091			102,850
Derivative liabilities at fair value	846			3,125
Total current liabilities	108,524			134,797
Long-term debt	2,037,844			1,988,946
Partnership liability	94,651			126,132
Asset retirement obligations	105,480			106,256
Derivative liabilities at fair value	—			323
Other liabilities	19,242			19,242
Commitments and contingencies (Note 7)
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 187,222,654 and 183,994,879 shares issued, respectively	1,872			1,840
Additional paid in capital	779,206			770,092
Treasury stock of 7,444,372 and 6,698,640 shares, respectively	(53,810		)	(51,422		)
Accumulated other comprehensive income	82,780			109,881
Retained deficit	(1,907,532		)	(1,836,361		)
Total stockholders' equity	(1,097,484		)	(1,005,970		)
	$	1,268,257		$	1,369,726

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

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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, 2012	$	1,790	$	751,394	$	(49,495	)	$	161,493		$	(1,997,979	)	$	(1,132,797	)
Net income	—		—		—			—			193,397			193,397
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $17,833	—		—		—			(37,181		)	—			(37,181		)
Foreign currency translation adjustment	—		—		—			(933		)	—			(933		)
Issuance and vesting of stock compensation	47		14,421		(1,472		)	—			—			12,996
Balances at September 30, 2013	$	1,837	$	765,815	$	(50,967	)	$	123,379		$	(1,804,582	)	$	(964,518	)
Balances at December 31, 2013	$	1,840	$	770,092	$	(51,422	)	$	109,881		$	(1,836,361	)	$	(1,005,970	)
Net loss	—		—		—			—			(71,171		)	(71,171		)
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $8,455	—		—		—			(20,939		)	—			(20,939		)
Foreign currency translation adjustment	—		—		—			(6,162		)	—			(6,162		)
Issuance and vesting of stock compensation	32		9,114		(2,388		)	—			—			6,758
Balances at September 30, 2014	$	1,872	$	779,206	$	(53,810	)	$	82,780		$	(1,907,532	)	$	(1,097,484	)

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

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

In thousands – Unaudited

	For the Nine Months Ended September 30,
	2014			2013
Operating activities:
Net income (loss)	$	(71,171	)	$	193,397
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depletion, depreciation and accretion	42,584			47,911
Impairment expense	135			—
Gain on Tokyo Gas Transaction	—			(341,146		)
Deferred income tax expense	8,455			17,833
Non-cash (gain) loss from hedging and derivative activities	6,731			(12,223		)
Stock-based compensation	9,146			13,699
Non-cash interest expense	8,441			23,643
Fortune Creek accretion	11,605			14,490
Other	(347		)	3,622
Changes in assets and liabilities
Accounts receivable	(1,936		)	7,398
Prepaid expenses and other assets	1,747			344
Accounts payable	(12,472		)	(17,973		)
Income taxes	(432		)	(148		)
Accrued and other liabilities	(7,469		)	(31,950		)
Net cash used in operating activities	(4,983		)	(81,103		)
Investing activities:
Capital expenditures	(111,444		)	(78,549		)
Proceeds from Southwestern Transaction	95,587			—
Proceeds from Tokyo Gas Transaction	—			463,418
Proceeds from Synergy Transaction	—			42,297
Proceeds from sale of properties and equipment	1,942			2,994
Purchases of marketable securities	(55,890		)	(142,823		)
Maturities and sales of marketable securities	222,025			13,178
Net cash provided by investing activities	152,220			300,515
Financing activities:
Issuance of debt	243,184			1,173,306
Repayments of debt	(193,689		)	(1,308,382		)
Debt issuance costs paid	(225		)	(25,868		)
Distribution of Fortune Creek Partnership funds	(37,113		)	(8,079		)
Purchase of treasury stock	(2,388		)	(1,472		)
Net cash provided by (used in) financing activities	9,769			(170,495		)
Effect of exchange rate changes in cash	2,216			2,610
Net change in cash and cash equivalents	159,222			51,527
Cash and cash equivalents at beginning of period	89,103			4,951
Cash and cash equivalents at end of period	$	248,325		$	56,478

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

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QUICKSILVER RESOURCES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited

1. ACCOUNTING POLICIES, DISCLOSURES AND NATURE OF OPERATIONS

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, 2014 and our results of operations and cash flows for the periods presented. All such adjustments are of a normal recurring nature unless otherwise noted. 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 2013 Annual Report on Form 10-K.

Our ability to borrow under our Combined Credit Agreements depends on our global borrowing base, which is scheduled to be redetermined twice each year. A reduction to the global borrowing base during the spring or autumn redetermination, or upon a special redetermination requested by our administrative agent under the Combined Credit Agreements, would adversely impact our liquidity and ability to meet our future obligations. Our derivatives contribute to the global borrowing base. Most of our derivative positions expire at year-end 2015. The expiration of these derivatives will adversely affect our global borrowing base, and absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing, significant cost savings through avoidance or deferral, or operational efficiencies, we expect to need additional sources of liquidity, including additional debt or equity financing or proceeds from asset sales, at the beginning of 2016 assuming no material debt maturities prior to that date. In addition, we are exploring potential transactions involving any and all of our assets, including our Horn River Asset. If successful, a sale of our Horn River Asset could eliminate or defray our need to make or fund significant capital investments in the Horn River Asset but would also reduce our global borrowing base if not offset by the effects of any related debt reduction. A sale of our other assets could also enhance liquidity if the sale proceeds exceed the associated decrease to the global borrowing base, if any.

In November 2014, the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. While we believe with these amendments we will be able to comply with the financial covenants contained in our Combined Credit Agreements through the end of 2015, we do not expect to exceed the required levels by a significant margin, particularly the minimum EBITDAX covenant under our Combined Credit Agreements. Accordingly, even a modest decline in prices for natural gas and NGLs, our failure to achieve anticipated cost savings through avoidance or deferral or operational efficiencies, our failure to execute certain asset purchases or the inaccuracy in any material respect of any of the other assumptions underlying our forecast could cause us to fall short of the financial covenants contained in the Combined Credit Agreements. Absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing, significant cost savings through avoidance or deferral, or operational efficiencies, we do not expect to comply with our interest coverage ratio covenant under our Combined Credit Agreements beginning in the first quarter of 2016 and expect that we would need to seek additional covenant relief under the Combined Credit Agreements at that time. In addition, we have benefitted from our natural gas derivatives, which have resulted in cash proceeds being greater than the prevailing price for natural gas. Without the benefit of these derivatives, most of which expire at year-end 2015, our earnings would be reduced and our cash interest expense would exceed our resulting EBITDAX. Any inability to comply with the financial covenants contained in our Combined Credit Agreements, unless waived or amended by the requisite

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lenders, could materially and adversely affect our liquidity by precluding further borrowings under our credit facilities and by accelerating the maturity of our debt. We may be unsuccessful in obtaining the necessary waivers or amendments.

In addition, we have significant fixed and springing debt maturities in 2015 and 2016, including the Combined Credit Agreements, the Second Lien Term Loan, the Second Lien Notes and the Senior Subordinated Notes. Note 5 contains a more complete description of our long-term debt, including springing maturities, which could occur as early as October 1, 2015. We do not expect to be able to satisfy these obligations with our cash on hand, committed financing or cash flow from operations. In order to satisfy these obligations we will need to obtain additional debt or equity financing or to sell assets, which we may not be able to do on satisfactory terms, or at all. We are limited in our ability to incur additional debt by the indenture restrictions. We may also seek to address the springing maturities by extending the maturity of or refinancing all or a portion of our Senior Subordinated Notes. If we are unsuccessful in extending or refinancing, we may not be able to satisfy such obligations when they mature.

Although we have been in discussions on a potential transaction involving our Horn River Asset and have proposed transaction terms, we reached no agreement on any material terms, including structure or valuation. Accordingly, we developed a formalized marketing process for this asset, along with any and all of our assets. We may be unsuccessful in consummating a transaction involving our Horn River Asset or any of our other assets being marketed on acceptable terms, or at all.

We have retained Houlihan Lokey Capital, Inc., Deloitte Transactions and Business Analytics LLP and other advisors to assist us in one or more of the following exercises:

• evaluation of options to address near-term debt maturities;

• enhancement of our liquidity position;

• evaluation of various strategic alternatives, including the acquisition or monetization of any and all assets or the Company; and

• employee retention.

Recently Issued Accounting Standards

In May 2014, the FASB issued accounting guidance, “Revenue from Contracts with Customers,” requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for us in the first quarter of 2017. We have not yet selected a transition method and we are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.

No other pronouncements materially affecting our financial statements have been issued since the filing of our 2013 Annual Report on Form 10-K.

2. DIVESTITURES

In May 2014, we completed the sale of our Niobrara Asset to Southwestern Energy Company. The purchase price was subject to customary purchase price adjustments, which resulted in Southwestern paying us $95.6 million. We determined that the Southwestern Transaction did not represent a significant disposal of reserves under GAAP, therefore we reduced the balance of U.S. oil and gas properties by the amount of these proceeds and we did not recognize a gain or loss.

In August 2013, we completed the sale of our Southern Alberta Asset to Synergy. The purchase price was $46.0 million, which was subject to customary purchase price adjustments, resulting in a final purchase price of $42.3 million. We determined that the Synergy Transaction did not represent a significant disposal of reserves, therefore our U.S. oil and gas properties were reduced by these proceeds and we did not recognize a gain or a loss.

In April 2013, we sold an undivided 25% interest in our Barnett Shale Asset to TGBR for a purchase price of $485 million. The effective date of the transaction was September 1, 2012. The purchase price was subject to customary price adjustments, which resulted in a final purchase price of $464.0 million. We recognized a gain of $341.1 million, which was subsequently adjusted in the second half of 2013 to $339.3 million, including a revision of the gain calculation in the third quarter of 2013 of $8.0 million, before consideration of income taxes

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based on our determination that the Tokyo Gas Transaction represented a significant disposal of reserves under GAAP. Our U.S. oil and gas properties were ultimately reduced through December 31, 2013 by $110.7 million as a result of the Tokyo Gas Transaction.

Note 3 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains additional information on other divestitures.

3. DERIVATIVES, MARKETABLE SECURITIES AND FAIR VALUE MEASUREMENTS

The following table categorizes our commodity derivative instruments based upon the level of the inputs used in estimating the fair value:

	Asset Derivatives				Liability Derivatives
	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
	(in thousands)				(in thousands)
Level 2 derivative instruments	$	74,312	$	107,395	$	846	$	3,448
Level 3 derivative instruments	17,754		23,485		—		—
Total	$	92,066	$	130,880	$	846	$	3,448

The fair value of “Level 2” derivative instruments included in these disclosures was estimated using inputs quoted in active markets for the periods covered by the derivatives. The fair value of derivative instruments designated as “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 the derivatives, and the credit adjusted risk-free interest rates. The “Level 3” unobservable input is the market prices for natural gas for the period from 2018 to 2021, as there is not an active market for that period of time. These unobservable inputs included within the fair value calculation range from $3.85 to $4.90 and are based upon prices quoted in active markets for the period of time available. A decrease of these unobservable inputs would increase the fair value, while an increase would decrease the fair value.

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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,
	2014			2013
	(in thousands)
Balance at beginning of period	$	(5,533	)	$	(9,873	)
Total gains (losses) for the period:
Unrealized gain (loss) on derivatives	24,829			24,080
Settlements in net derivative gains (losses)	(1,542		)	(3,302		)
Balance at end of period	$	17,754		$	10,905
Total gains (losses) included in net derivative gains (losses) attributable to the change in unrealized gains (losses) related to assets still held at the reporting date	$	24,485		$	24,026

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
Balance at beginning of period	$	23,485		$	(4,931	)
Total gains (losses) for the period:
Unrealized gain (loss) on derivatives	(6,488		)	24,618
Settlements in net derivative gains (losses)	757			(8,782		)
Balance at end of period	$	17,754		$	10,905
Total gains (losses) included in net derivative gains (losses) attributable to the change in unrealized gains (losses) related to assets still held at the reporting date	$	(2,476	)	$	26,788

Commodity Price Derivatives

As of September 30, 2014, we had natural gas swaps as follows:

Production Year	Daily Production Volume
	Natural Gas	Natural Gas Basis Swaps
	MMcfd	MMcfd
Remaining 2014 (1)	170	40
2015	150	—
2016-2021	40	—

⁽¹⁾  Our natural gas basis swaps economically hedge the AECO basis adjustment from NYMEX.

Effective December 31, 2012, we discontinued the use of hedge accounting. Changes in value subsequent to this date are recognized in net derivative gains (losses) in the period in which they occur. The net deferred hedge gain that was included in AOCI as of December 31, 2012 is being released into revenue from natural gas, NGL and oil production over the original term of the hedging relationship (through 2021). Gains from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months will result in production revenue of $22.7 million net of income taxes.

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Interest Rate Derivatives

In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges. Upon the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain as a reduction of interest expense over the lives of the respective notes. During the nine months endedSeptember 30, 2014 and 2013, we recognized $1.5 million and $11.5 million, respectively, of those deferred gains as a reduction of interest expense. Gains from the effective portion of these interest rate swaps expected to reduce interest expense during the following twelve months are $2.2 million.

Fair Value Disclosures

The estimated fair value of our derivative instruments at September 30, 2014 and December 31, 2013 were as follows:

	Asset Derivatives				Liability Derivatives
	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
	(in thousands)				(in thousands)
Derivatives not designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	66,278	$	60,063	$	180	$	2,540
Noncurrent derivative assets	75,911		105,315		49,943		31,958
Current derivative liabilities	—		—		846		3,125
Noncurrent derivative liabilities	—		—		—		323
Total derivatives not designated as hedges	$	142,189	$	165,378	$	50,969	$	37,946

Derivative assets and liabilities shown in the table above are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in the accompanying condensed consolidated balance sheets. The change in carrying value of our commodity price derivatives since December 31, 2013 principally resulted from the overall increase in market prices for natural gas relative to the prices in our open derivative instruments, offset by settlements during the period.

Financial instruments not carried at fair value

Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets as of September 30, 2014 and December 31, 2013 are included in Note 5.

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Investments

We hold certain short-term marketable securities related to interest bearing time deposits and commercial paper. These marketable securities are included in Cash and Cash Equivalents if the maturities at the time we made the investment were three months or less. For maturities greater than three months but less than a year, the marketable securities are included in current Marketable Securities. During June 2014, we sold $10.0 million and transferred $10.0 million of held-to-maturity marketable securities to available-for-sale. Proceeds from these sales were used to reduce the outstanding balance on the Combined Credit Agreements. The estimated fair value of available-for-sale marketable securities is determined using market quotations based on recent trade activity (“Level 2” inputs). At September 30, 2014 we did not own any marketable securities. At December 31, 2013, we had the following marketable securities:

	December 31, 2013
	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Market Value
	(in thousands)
Marketable securities (held-to-maturity)
Time deposits	$	29,419	$	—	$	(22	)	$	29,397
Commercial paper	136,924		27		(25		)	136,926
Marketable securities	$	166,343	$	27	$	(47	)	$	166,323

4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	September 30, 2014			December 31, 2013
	(in thousands)
Oil and gas properties
Subject to depletion	$	5,635,307		$	5,687,557
Unevaluated costs	218,398			221,605
Accumulated depletion	(5,245,133		)	(5,268,719		)
Net oil and gas properties	608,572			640,443
Other property and equipment
Pipelines and processing facilities	332,710			347,093
General properties	71,049			72,125
Accumulated depreciation	(199,851		)	(198,856		)
Net other property and equipment	203,908			220,362
Property, plant and equipment, net of accumulated depletion and depreciation	$	812,480		$	860,805

We recognized other property and equipment impairment charges of $0.1 million in 2014 for pipeline in Texas.

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5. LONG-TERM DEBT

Long-term debt consisted of the following:

	September 30, 2014		December 31, 2013
	(in thousands)
Combined Credit Agreements	$	275,966	$	211,200
Second Lien Term Loan, net of unamortized discount	609,555		607,572
Second Lien Notes due 2019, net of unamortized discount	195,058		194,423
Senior notes due 2015, net of unamortized discount	—		10,472
Senior notes due 2016, net of unamortized discount	—		8,044
Senior notes due 2019, net of unamortized discount	293,744		293,243
Senior notes due 2021, net of unamortized discount	310,229		309,190
Senior subordinated notes due 2016	350,000		350,000
Total debt	2,034,552		1,984,144
Unamortized deferred gain-terminated interest rate swaps	3,292		4,802
Long-term debt	$	2,037,844	$	1,988,946

Combined Credit Agreements

The Combined Credit Agreements’ global borrowing base was $325 million and the global letter of credit capacity was $280 million as of September 30, 2014. At September 30, 2014, we had $6.7 million available under the Combined Credit Agreements.

In November 2014, the Combined Credit Agreements' global borrowing base was reaffirmed at $325 million and the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:

	Minimum EBITDAX Covenant
	(in millions)
Three months ending December 31, 2014	$	30.0
Six months ending March 31, 2015	59.0
Nine months ending June 30, 2015	87.25
Twelve months ending September 30, 2015	120.5
Twelve months ending December 31, 2015	122.0

Additionally, the Combined Credit Agreements were amended changing certain definitions that impact the calculation of EBITDAX in both the November 2014 amendment and the April 2014 amendment and we permanently reduced the aggregate maximum credit amounts under the Combined Credit Agreements from $1.75 billion to $650 million in April 2014 and to $450 million in November 2014.

Senior Notes due 2015 and Senior Notes due 2016

In April 2014, we redeemed all remaining outstanding notes under our Senior Notes due 2015 and Senior Notes due 2016. Our Senior Notes due 2015 were redeemed at 101.938% of the principal amount plus accrued and unpaid interest representing a total payment of $10.9 million and our Senior Notes due 2016 were redeemed at 105.875% of the principal amount plus accrued and unpaid interest representing a total payment of $8.9 million.

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Indenture Restrictions

We have an incurrence test under our indentures applicable to debt, restricted payments, mergers and consolidations and designation of unrestricted subsidiaries that requires EBITDA to exceed interest expense by 2.25 times. At September 30, 2014, we did not meet this test and, as a result, we are limited in our ability to, among other things, incur additional debt, except for specific baskets. We do retain, however, the ability to utilize the full borrowing capacity under our Combined Credit Agreements and to refinance existing debt. Not meeting this ratio does not represent an event of default under our debt. We cannot predict when or if we will meet the incurrence test.

We retained a portion of the cash received from our asset sales. Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.

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Summary of All Outstanding Debt

The following table summarizes certain significant aspects of our long-term debt outstanding at September 30, 2014.

	Priority on Collateral and Structural Seniority (1)
	Highest priority						Lowest priority
	First Lien		Second Lien		Senior Unsecured		Senior Subordinated
	Combined Credit Agreements		Second Lien Term Loan	Second Lien Notes due 2019	2019 Senior Notes	2021 Senior Notes	Senior Subordinated Notes
Principal amount (1) (2)	$325 million		$625 million	$200 million	$298 million	$325 million	$350 million
Scheduled maturity date (3)	September 6, 2016		June 21, 2019	June 21, 2019	August 15, 2019	July 1, 2021	April 1, 2016
Springing maturity date (3)	October 1, 2015		January 1, 2016	January 1, 2016	N/A	N/A	N/A
Interest rate on outstanding borrowings at September 30, 2014 (4)	4.09%		7.00%	7.00%	9.125%	11.00%	7.125%
Base interest rate options (5) (6)	LIBOR, ABR, CDOR		LIBOR floor of 1.25%; ABR floor of 2.25%	LIBOR floor of 1.25%	N/A	N/A	N/A
Financial covenants (7) (9)	- Minimum current ratio of 1.0 - Minimum EBITDA to cash interest expense ratio of 1.10 - Maximum senior secured debt leverage ratio of 2.0		N/A	N/A	N/A	N/A	N/A
Significant restrictive covenants (8)(9)	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions - Limitations on derivatives and investments		- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens and 1st lien cap -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 (9)	Any time		Any time, subject to re-pricing event June 21, 2015: 101	Any time, subject to re-pricing event June 21, 2015: 101	August 15, 2014: 104.563 2015: 103.042 2016: 101.521 2017: par	July 1, 2019: 102.000 2020: par	Any time
Make-whole redemption (9)	N/A		N/A	N/A	N/A	Callable prior to July 1, 2019 at make-whole call price of Treasury +50 bps	N/A
Change of control (9)	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	Put at 101% of principal plus accrued interest
Equity clawback (9)	N/A		N/A	N/A	N/A	Redeemable until July 1, 2016 at 111.00%, plus accrued interest for up to 35%	N/A
Estimated fair value (10)	$276.0 million		$568.8 million	$182.0 million	$186.3 million	$213.7 million	$136.5 million

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⁽¹⁾  Borrowings under the Amended and Restated U.S. Credit Facility, Second Lien Term Loan and Second Lien Notes due 2019 are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured (on a first priority basis with respect to the Amended and Restated U.S. Credit Facility and on a second priority basis with respect to the Second Lien Term Loan and the Second Lien Notes due 2019) 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, QPP Parent LLC and QPP Holdings LLC (collectively, the “Domestic Pledged Equity”), 65% of the equity interests of Quicksilver Resources Canada Inc. (“Quicksilver Canada”) and Quicksilver Production Partners Operating Ltd. (with respect to the Amended and Restated U.S. Credit Facility, on a ratable basis with borrowings under the Amended and Restated Canadian Credit Facility) and the majority of Quicksilver's domestic proved oil and gas properties and related assets, (the “Domestic Pledged Property”). 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, the Domestic Pledged Property, 100% of the equity interests of Quicksilver Canada (65% of which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and any Canadian restricted subsidiaries, under the Amended and Restated Canadian Credit Facility, and 65% of the equity interests of Quicksilver Production Partners Operating Ltd. (which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and the majority of Quicksilver Canada's oil and gas properties and related assets. 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, 2014.

⁽³⁾  The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the Senior Subordinated Notes, the Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Second Lien Term Loan and Second Lien Notes due 2019 are required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remain outstanding and (2) 91 days prior to the maturity of the Senior Subordinated Notes if on the applicable date the amount remaining outstanding is greater than $100 million. As of September 30, 2014, as presently structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would be due on October 1, 2015 and the Second Lien Term Loan and Second Lien Notes due 2019 would be due on January 1, 2016.

⁽⁴⁾  Represents the weighted average borrowing rate payable to lenders.

⁽⁵⁾  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 2.75% and 3.75%, (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 1.75% and 2.75%. 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 Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.50%.

⁽⁶⁾  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 2.75% and 3.75%, (ii) the Canadian Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75%, (iii) the U.S. Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75% and (iv) adjusted LIBOR (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%. 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 Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.50%.

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⁽⁷⁾  As of September 30, 2014, the future minimum required interest coverage ratio for the Combined Credit Agreements is as follows:

Period	Interest Coverage Ratio	Period	Interest Coverage Ratio
Q4 2014	1.10	Q4 2015	1.20
Q1 2015	1.10	Q1 2016	1.50
Q2 2015	1.15	Q2 2016	2.00
Q3 2015	1.15

In November 2014, the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:

	Minimum EBITDAX Covenant
	(in millions)
Three months ending December 31, 2014	$	30.0
Six months ending March 31, 2015	59.0
Nine months ending June 30, 2015	87.25
Twelve months ending September 30, 2015	120.5
Twelve months ending December 31, 2015	122.0

⁽⁸⁾  Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.

⁽⁹⁾  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.

⁽¹⁰⁾  The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). Our Second Lien Term Loan and Second Lien Notes due 2019 feature variable interest rates and we estimate their fair value by using market quotations based on recent trade activity (“Level 3” input). We consider our Combined Credit Agreements which have a variable interest rate to have a fair value equal to their carrying value (“Level 1” input).

6. INCOME TAXES

Note 13 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains additional information about our income taxes. At September 30, 2014, our U.S. and Canadian valuation allowances are $372.0 million and $60.7 million, respectively, which reduce our net deferred tax assets to a zero value as we continue to believe that it is not more likely than not that we will realize the deferred tax assets primarily related to our cumulative net operating losses. Income tax recognized for the three and nine months ended September 30, 2014 is a result of hedge gains previously deferred in AOCI being realized during the periods and the net tax impact being recognized, partially offset by a refund of $7.6 million filed in September 2014.

7. COMMITMENTS AND CONTINGENCIES

In each of July 2011 and June 2012, we received a subpoena duces tecum from the SEC requesting certain documents. In July 2014, the SEC notified us that the staff has completed its investigation and does not intend to recommend an enforcement action by the SEC against us.

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Note 14 to the consolidated financial statements in our 2013 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, 2014.

8. FORTUNE CREEK

Note 15 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains additional information on Fortune Creek. In March 2014, we agreed with KKR to an amendment to extend the ending date of the minimum gross capital expenditures requirement, of which C$120 million remains, to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset and to broaden allowable spending to include acquisitions of producing properties that utilize partnership assets. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by C$0.13 per Mcf until at least 2016. We do not expect to be able to satisfy these capital expenditure requirements with our cash on hand, committed financing or cash flow from operations and will need to obtain additional debt or equity financing or sell assets, which we may not be able to do on satisfactory terms, or at all.

We committed gas production from our Horn River Asset for ten years beginning 2012, as more fully described below. KKR contributed C$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.

The firm gathering agreement with Fortune Creek is guaranteed by us. 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. Fortune Creek has made cash distributions to KKR, which are reported as cash used in financing activities.

Based on a quarterly 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.

9. QUICKSILVER STOCKHOLDERS’ EQUITY

Common Stock, Preferred Stock and Treasury Stock

We are authorized to issue 400 million shares of common stock with a $0.01 par value per share and 10 million shares of preferred stock with a $0.01 par value per share. At September 30, 2014 and December 31, 2013, we had 179.8 million and 177.3 million shares of common stock outstanding, respectively.

Stock Options

No options have been granted during 2014. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the nine months endedSeptember 30, 2013:

Weighted avg grant date fair value	$1.05
Weighted avg risk-free interest rate	1.31%
Expected life	4.9 years
Wtd avg volatility	69.0%
Expected dividends	—

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The following table summarizes our stock option activity for the nine months endedSeptember 30, 2014:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
					(in years)	(in thousands)
Outstanding at January 1, 2014	6,771,578		$	7.82
Forfeited	(44,950	)	1.65
Expired	(111,494	)	9.83
Outstanding at September 30, 2014	6,615,134		$	7.83	5.4	$	—
Exercisable at September 30, 2014	5,232,903		$	9.18	4.6	$	—

As of September 30, 2014, we estimate that a total of 6.3 million stock options will vest including those options already exercisable. As of September 30, 2014, the unrecognized compensation cost related to outstanding unvested stock options was $1.0 million, which is expected to be recognized in expense through August 2016. Compensation expense related to stock options of $1.1 million and $3.2 million was recognized for the nine months endedSeptember 30, 2014 and 2013, respectively.

Restricted Stock and Stock Units

The following table summarizes our restricted stock and stock unit activity for the nine months endedSeptember 30, 2014:

	Payable in shares				Payable in cash
	Shares		Weighted Average Grant Date Fair Value		Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2014	5,668,090		$	3.90	1,572,341		$	3.69
Granted	4,765,425		2.64		—		—
Vested	(2,559,959	)	4.86		(631,275	)	4.29
Forfeited	(348,554	)	3.09		(33,458	)	3.20
Outstanding at September 30, 2014	7,525,002		$	2.82	907,608		$	3.32

As of September 30, 2014, the unrecognized compensation cost related to outstanding unvested restricted stock was $14.8 million, which is expected to be recognized in expense through July 2017. Grants of restricted stock and RSUs during the nine months endedSeptember 30, 2014 had an estimated grant date fair value of $12.6 million. The fair value of outstanding RSUs to be settled in cash was $0.5 million at September 30, 2014. For the nine months endedSeptember 30, 2014 and 2013, compensation expense related to restricted stock and RSUs of $8.4 million and $12.2 million, respectively, was recognized. The total fair value of shares vested during the nine months endedSeptember 30, 2014 was $10.2 million.

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10.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,
	2014			2013			2014			2013
	(in thousands, except per share data)
Net income (loss) attributable to Quicksilver	$	23,757		$	10,577		$	(71,171	)	$	193,397
Basic income allocable to participating securities (1)	(772		)	(312		)	—			(5,111		)
Income (loss) available to shareholders	$	22,985		$	10,265		$	(71,171	)	$	188,286
Weighted average common shares – basic	173,936			171,682			173,783			171,403
Effect of dilutive securities (2)
Share-based compensation awards	216			311			—			170
Weighted average common shares – diluted	174,152			171,993			173,783			171,573
Earnings (loss) per common share – basic	$	0.13		$	0.06		$	(0.41	)	$	1.10
Earnings (loss) per common share – diluted	$	0.13		$	0.06		$	(0.41	)	$	1.10

⁽¹⁾  Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, should be included in computing earnings per share using the two-class method. Participating securities, however, do not participate in undistributed net losses because there is no contractual obligation to do so.

⁽²⁾  For the three months ended September 30, 2014, 6.6 million shares associated with our stock options and 1.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the three months ended September 30, 2013, 6.2 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2014, 6.6 million shares associated with our stock options and 0.8 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2013, 5.5 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations.

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11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Note 18 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted subsidiaries under the indentures for our Senior Notes and Senior Subordinated Notes.

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

Condensed Consolidating Balance Sheets

	September 30, 2014
	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)
ASSETS
Current assets	$	338,424		$	13,096		$	65,733		$	(23,193	)	$	394,060		$	(455	)	$	1,746	$	949		$	396,300
Property and equipment	417,921			14,625			305,197			—			737,743			—			74,737		—			812,480
Investment in subsidiaries (equity method)	(227,994		)	—			(23,409		)	227,994			(23,409		)	(23,429		)	—		46,838			—
Other assets	457,285			—			15,473			(413,281		)	59,477			—			—		—			59,477
Total assets	$	985,636		$	27,721		$	362,994		$	(208,480	)	$	1,167,871		$	(23,884	)	$	76,483	$	47,787		$	1,268,257
LIABILITIES AND EQUITY
Current liabilities	$	103,042		$	13,401		$	11,064		$	(23,193	)	$	104,314		$	(475	)	$	3,736	$	949		$	108,524
Long-term liabilities	1,980,078			19,241			575,003			(413,281		)	2,161,041			—			1,525		94,651			2,257,217
Stockholders' equity	(1,097,484		)	(4,921		)	(223,073		)	227,994			(1,097,484		)	(23,409		)	71,222		(47,813		)	(1,097,484		)
Total liabilities and equity	$	985,636		$	27,721		$	362,994		$	(208,480	)	$	1,167,871		$	(23,884	)	$	76,483	$	47,787		$	1,268,257

	December 31, 2013
	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)
ASSETS
Current assets	$	349,586		$	10,735		$	53,034		$	(19,642	)	$	393,713		$	909		$	1,110	$	(1,772	)	$	393,960
Property and equipment	455,822			15,486			307,865			—			779,173			—			81,632		—			860,805
Investment in subsidiaries (equity method)	(217,852		)	—			(33,840		)	217,852			(33,840		)	(33,840		)	—		67,680			—
Other assets	472,792			—			32,892			(390,723		)	114,961			—			—		—			114,961
Total assets	$	1,060,348		$	26,221		$	359,951		$	(192,513	)	$	1,254,007		$	(32,931	)	$	82,742	$	65,908		$	1,369,726
LIABILITIES AND EQUITY
Current liabilities	$	124,275		$	12,210		$	17,167		$	(19,642	)	$	134,010		$	888		$	1,671	$	(1,772	)	$	134,797
Long-term liabilities	1,942,043			19,242			542,659			(390,723		)	2,113,221			—			1,546		126,132			2,240,899
Stockholders' equity	(1,005,970		)	(5,231		)	(199,875		)	217,852			(993,224		)	(33,819		)	79,525		(58,452		)	(1,005,970		)
Total liabilities and equity	$	1,060,348		$	26,221		$	359,951		$	(192,513	)	$	1,254,007		$	(32,931	)	$	82,742	$	65,908		$	1,369,726

24

Condensed Consolidating Statements of Income

	For the Three Months Ended September 30, 2014
	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	$	120,513		$	427		$	42,558		$	—		$	163,498		$	—	$	4,271	$	(4,271	)	$	163,498
Operating expenses	72,868			341			27,648			—			100,857			—		2,128		(4,271		)	98,714
Equity in net earnings of subsidiaries	8,821			—			(1,458		)	(8,821		)	(1,458		)	2,144		—		(686		)	—
Operating income (loss)	56,466			86			13,452			(8,821		)	61,183			2,144		2,143		(686		)	64,784
Fortune Creek accretion	—			—			—			—			—			—		—		(3,602		)	(3,602		)
Interest expense and other	(37,613		)	86			(4,838		)	—			(42,365		)	—		1		—			(42,364		)
Income tax (expense) benefit	4,826			(30		)	65			78			4,939			—		—		—			4,939
Net income (loss)	$	23,679		$	142		$	8,679		$	(8,743	)	$	23,757		$	2,144	$	2,144	$	(4,288	)	$	23,757
Other comprehensive income (loss)	(11,564		)	—			(3,325		)	—			(14,889		)	—		—		—			(14,889		)
Equity in OCI of subsidiaries	(3,325		)	—			—			3,325			—			—		—		—			—
Comprehensive income (loss)	$	8,790		$	142		$	5,354		$	(5,418	)	$	8,868		$	2,144	$	2,144	$	(4,288	)	$	8,868

	For the Three Months Ended September 30, 2013
	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	$	114,021		$	192	$	38,903		$	—		$	153,116		$	—	$	5,674	$	(5,674	)	$	153,116
Operating expenses	73,594			68		30,360			—			104,022			—		2,693		(5,674		)	101,041
Tokyo Gas Transaction gain	7,974			—		—			—			7,974			—		—		—			7,974
Equity in net earnings of subsidiaries	3,854			—		(1,834		)	(3,854		)	(1,834		)	2,984		—		(1,150		)	—
Operating income (loss)	52,255			124		6,709			(3,854		)	55,234			2,984		2,981		(1,150		)	60,049
Fortune Creek accretion	—			—		—			—			—			—		—		(4,818		)	(4,818		)
Interest expense and other	(36,922		)	—		(1,769		)	—			(38,691		)	—		3		—			(38,688		)
Income tax (expense) benefit	(4,756		)	—		(1,210		)	—			(5,966		)	—		—		—			(5,966		)
Net income (loss)	$	10,577		$	124	$	3,730		$	(3,854	)	$	10,577		$	2,984	$	2,984	$	(5,968	)	$	10,577
Other comprehensive income (loss)	(6,114		)	—		(2,680		)	—			(8,794		)	—		—		—			(8,794		)
Equity in OCI of subsidiaries	(2,680		)	—		—			2,680			—			—		—		—			—
Comprehensive income (loss)	$	1,783		$	124	$	1,050		$	(1,174	)	$	1,783		$	2,984	$	2,984	$	(5,968	)	$	1,783

25

	For the Nine Months Ended September 30, 2014
	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	$	269,321		$	1,212		$	102,783		$	—		$	373,316		$	—	$	13,349	$	(13,349	)	$	373,316
Operating expenses	225,906			988			86,491			—			313,385			—		6,014		(13,349		)	306,050
Equity in net earnings of subsidiaries	2,864			—			(4,266		)	(2,864		)	(4,266		)	7,339		—		(3,073		)	—
Operating income (loss)	46,279			224			12,026			(2,864		)	55,665			7,339		7,335		(3,073		)	67,266
Fortune Creek accretion	—			—			—			—			—			—		—		(11,605		)	(11,605		)
Interest expense and other	(117,315		)	86			(8,526		)	—			(125,755		)	—		4		—			(125,751		)
Income tax (expense) benefit	(213		)	(78		)	(868		)	78			(1,081		)	—		—		—			(1,081		)
Net income (loss)	$	(71,249	)	$	232		$	2,632		$	(2,786	)	$	(71,171	)	$	7,339	$	7,339	$	(14,678	)	$	(71,171	)
Other comprehensive income (loss)	(20,252		)	—			(6,849		)	—			(27,101		)	—		—		—			(27,101		)
Equity in OCI of subsidiaries	(6,849		)	—			—			6,849			—			—		—		—			—
Comprehensive income (loss)	$	(98,350	)	$	232		$	(4,217	)	$	4,063		$	(98,272	)	$	7,339	$	7,339	$	(14,678	)	$	(98,272	)

	For the Nine Months Ended September 30, 2013
	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	$	334,848		$	608	$	111,862		$	—	$	447,318		$	—	$	16,736	$	(16,736	)	$	447,318
Operating expenses	256,810			206		89,559			—		346,575			—		7,552		(16,736		)	337,391
Tokyo Gas Transaction gain	341,146			—		—			—		341,146			—		—		—			341,146
Equity in net earnings of subsidiaries	(9,227		)	—		(5,300		)	9,227		(5,300		)	9,190		—		(3,890		)	—
Operating income (loss)	409,957			402		17,003			9,227		436,589			9,190		9,184		(3,890		)	451,073
Fortune Creek accretion	—			—		—			—		—			—		—		(14,490		)	(14,490		)
Interest expense and other	(200,639		)	—		(24,490		)	—		(225,129		)	—		6		—			(225,123		)
Income tax (expense) benefit	(15,921		)	—		(2,142		)	—		(18,063		)	—		—		—			(18,063		)
Net income (loss)	$	193,397		$	402	$	(9,629	)	$	9,227	$	193,397		$	9,190	$	9,190	$	(18,380	)	$	193,397
Other comprehensive income (loss)	(29,014		)	—		(9,100		)	—		(38,114		)	—		—		—			(38,114		)
Equity in OCI of subsidiaries	(9,100		)	—		—			9,100		—			—		—		—			—
Comprehensive income (loss)	$	155,283		$	402	$	(18,729	)	$	18,327	$	155,283		$	9,190	$	9,190	$	(18,380	)	$	155,283

26

Condensed Consolidating Statements of Cash Flows

	For the Nine Months Ended September 30, 2014
	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)
Net cash flow provided by (used in) operating activities	$	(39,474	)	$	(688	)	$	28,843		$	—		$	(11,319	)	$	—		$	6,336		$	—		$	(4,983	)
Purchases of property, plant and equipment	(88,119		)	(57		)	(23,247		)	—			(111,423		)	—			(21		)	—			(111,444		)
Investment in subsidiary	(1,246		)	—			(26,395		)	1,246			(26,395		)	(26,395		)	—			52,790			—
Proceeds from Southwestern Transaction	95,587			—			—			—			95,587			—			—			—			95,587
Proceeds from sale of properties and equipment	1,445			—			497			—			1,942			—			—			—			1,942
Purchases of marketable securities	(55,890		)	—			—			—			(55,890		)	—			—			—			(55,890		)
Maturities and sales of marketable securities	222,025			—			—			—			222,025			—			—			—			222,025
Net cash flow provided by (used in) investing activities	173,802			(57		)	(49,145		)	1,246			125,846			(26,395		)	(21		)	52,790			152,220
Issuance of debt	174,000			—			69,184			—			243,184			—			—			—			243,184
Repayments of debt	(138,651		)	—			(55,038		)	—			(193,689		)	—			—			—			(193,689		)
Debt issuance costs paid	(225		)	—			—			—			(225		)	—			—			—			(225		)
Intercompany note	(22,558		)	—			22,558			—			—			—			—			—			—
Intercompany financing	—			745			501			(1,246		)	—			—			—			—			—
Contribution received	—			—			—			—			—			26,395			26,395			(52,790		)	—
Distribution of Fortune Creek Partnership funds	—			—			—			—			—			—			(37,113		)	—			(37,113		)
Purchase of treasury stock	(2,388		)	—			—			—			(2,388		)	—			—			—			(2,388		)
Net cash flow provided by (used in) financing activities	10,178			745			37,205			(1,246		)	46,882			26,395			(10,718		)	(52,790		)	9,769
Effect of exchange rates on cash	—			—			(2,718		)	—			(2,718		)	—			4,934			—			2,216
Net increase (decrease) in cash and equivalents	144,506			—			14,185			—			158,691			—			531			—			159,222
Cash and equivalents at beginning of period	83,893			—			4,135			—			88,028			22			1,053			—			89,103
Cash and equivalents at end of period	$	228,399		$	—		$	18,320		$	—		$	246,719		$	22		$	1,584		$	—		$	248,325

27

	For the Nine Months Ended September 30, 2013
	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 by (used in) operating activities	$	(113,029	)	$	(19	)	$	25,517		$	(87,531	)	$	—	$	6,428		$	(81,103	)
Purchases of property, plant and equipment	(53,291		)	19			(24,752		)	(78,024		)	—		(525		)	(78,549		)
Proceeds from Tokyo Gas Transaction	463,418			—			—			$	463,418		—		—			463,418
Proceeds from Synergy transaction	42,297			—			—			42,297			—		—			42,297
Proceeds from sale of properties and equipment	2,977			—			17			2,994			—		—			2,994
Purchases of marketable securities	(142,823		)	—			—			$	(142,823	)	—		—			(142,823		)
Maturities and sales of marketable securities	13,178			—			—			$	13,178		—		—			13,178
Net cash flow provided by (used in)  investing activities	325,756			19			(24,735		)	301,040			—		(525		)	300,515
Issuance of debt	1,170,266			—			3,040			1,173,306			—		—			1,173,306
Repayments of debt	(1,157,969		)	—			(150,413		)	(1,308,382		)	—		—			(1,308,382		)
Debt issuance costs paid	(25,868		)	—			—			(25,868		)	—		—			(25,868		)
Intercompany note	(147,103		)	—			147,103			—			—		—			—
Distribution of Fortune Creek Partnership funds	—			—			—			—			—		(8,079		)	(8,079		)
Purchase of treasury stock	(1,472		)	—			—			(1,472		)	—		—			(1,472		)
Net cash flow used in financing activities	(162,146		)	—			(270		)	(162,416		)	—		(8,079		)	(170,495		)
Effect of exchange rates on cash	—			—			(512		)	(512		)	—		3,122			2,610
Net increase in cash and equivalents	50,581			—			—			50,581			—		946			51,527
Cash and equivalents at beginning of period	4,618			—			—			4,618			—		333			4,951
Cash and equivalents at end of period	$	55,199		$	—		$	—		$	55,199		$	—	$	1,279		$	56,478

28

12. SEGMENT INFORMATION

We operate in two geographic segments, the U.S. and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. 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. In Canada, our midstream operation is the Fortune Creek partnership. Revenue earned by Fortune Creek for the gathering and processing of our gas is eliminated on a consolidated basis as is the GPT recognized by our producing properties. Based on the immateriality of our midstream segment, we have combined our U.S. and Canadian midstream information. We evaluate performance based on operating income and property and equipment costs incurred.

	Exploration & Production												Quicksilver Consolidated
	U.S.		Canada		Midstream		Corporate			Elimination
For the Three Months Ended September 30:	(in thousands)
2014
Revenue	$	120,513	$	42,072	$	5,184	$	—		$	(4,271	)	$	163,498
DD&A	8,096		4,171		1,256		446			—			13,969
Impairment expense	—		—		135		—			—			135
Operating income (loss)	57,809		16,364		2,367		(11,756		)	—			64,784
Property and equipment costs incurred	20,912		7,254		72		218			—			28,456
2013
Revenue	$	114,002	$	38,407	$	6,381	$	—		$	(5,674	)	$	153,116
DD&A	8,402		4,114		1,300		574			—			14,390
Operating income (loss)	56,911		11,076		3,107		(11,045		)	—			60,049
Property and equipment costs incurred	15,147		4,288		1,615		(329		)	—			20,721
For the Nine Months Ended September 30:
2014
Revenue	$	269,310	$	101,198	$	16,157	$	—		$	(13,349	)	$	373,316
DD&A	23,652		13,779		3,744		1,409			—			42,584
Impairment expense	—		—		135		—			—			135
Operating income (loss)	78,891		20,199		7,700		(39,524		)	—			67,266
Property and equipment costs incurred	85,814		20,924		83		763			—			107,584
2013
Revenue	$	334,804	$	110,052	$	19,198	$	—		$	(16,736	)	$	447,318
DD&A	29,745		12,458		3,947		1,761			—			47,911
Operating income (loss)	456,624		30,126		9,593		(45,270		)	—			451,073
Property and equipment costs incurred	50,459		9,972		2,369		9,655			—			72,455
Property, plant and equipment-net
September 30, 2014	$	415,163	$	303,827	$	89,362	$	4,128		$	—		$	812,480
December 31, 2013	451,840		306,423		97,118		5,424			—			860,805
Total assets
September 30, 2014	796,931		362,994		104,204		4,128			—			$	1,268,257
December 31, 2013	895,388		359,951		108,963		5,424			—			1,369,726

29

13. SUPPLEMENTAL CASH FLOW INFORMATION

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

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
Interest, net of capitalized interest	$	124,408		$	227,189
Income taxes	(7,844		)	1,217

Other significant non-cash transactions are as follows:

	For the Nine Months Ended September 30,
	2014		2013
	(in thousands)
Working capital related to capital expenditures	$	7,612	$	4,867

14. TRANSACTIONS AND OTHER MATTERS WITH RELATED PARTIES

As of September 30, 2014, members of the Darden family and entities controlled by them beneficially owned approximately 30% of our outstanding common stock. Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.

During the first nine months of 2013, we paid $0.3 million 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 less than $0.1 million for the first nine months of 2014 and 2013.

In August 2013, we paid $0.2 million in commission to an entity controlled by members of the Darden family in connection with the sublease of a portion of our office space.

Thomas Darden, brother of Glenn Darden and Anne Darden Self, retired as an employee on December 31, 2013, and resigned from the board of directors effective September 1, 2014. During the first nine months of 2014, consulting fee payments of $405,000, office allowance payments of $112,500 and COBRA payments of $39,000 were made to Mr. Darden. Additionally, in accordance with the agreement related to his retirement signed in May 2013 and following the execution and non-revocation of a release agreement satisfactory to us, we paid Mr. Darden a cash bonus of $286,650 and an equity bonus in the form of 72,662 fully vested shares having a grant date fair value equal to $191,100 in March 2014.

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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 2013 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:

• 2014 Highlights – a summary of significant activities and events affecting Quicksilver

• 2014 Capital Program – a summary of our planned capital expenditures during 2014

• 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

2014 HIGHLIGHTS

In March 2014, we executed an agreement with Southwestern Energy Company to sell all of our Niobrara Asset. The purchase price was subject to customary purchase price adjustments, which resulted in Southwestern paying us $95.6 million. The transaction closed on May 1, 2014. The decision to sell this acreage was largely rooted in SWEPI’s plans to exit its North American shale plays, including the shared interest in our Niobrara Asset.

In the third quarter of 2014, we drilled two wells in Pecos County as part of our joint venture with Eni. The first well began flow back up casing at a rate of 750 Boed. Tubing was later installed and the 83-day flow rate is approximately 535 Boed from a 3,700-foot lateral. A second well was completed in a 5,200-foot lateral with current flow back at a rate of 700 Boed, of which 75% is oil, on a restricted choke after recovering approximately 15% of the fracture fluid. Oil volumes have improved daily and continue to increase. The joint venture expects to commence drilling two additional wells in the fourth quarter of 2014.

Strategic Alternatives

We have appointed John Little with Deloitte Transactions and Business Analytics LLP as our Strategic Alternatives Officer. Mr. Little, in this capacity, has a number of duties that principally involve assisting us in various strategic pursuits, particularly involving our Combined Credit Agreements’ semi-annual redetermination, the springing debt maturities of our Combined Credit Agreements and our second lien indebtedness arising from our Senior Subordinated Notes’ stated maturity of April 2016, the marketing of our assets and our efforts to maximize liquidity in the present environment.

We completed a semi-annual borrowing base redetermination in early November 2014. Note 5 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report contains more information about the results of this redetermination.

We are exploring several avenues to address our capital structure, including the stated and springing maturities. We are in frequent discussions with certain of the security holders regarding possible paths to be undertaken.

We have also begun a broad and more formalized asset marketing process. This process, being led by Houlihan Lokey Capital, Inc., covers any and all of our operating assets and is flexible with regard to structure of any transaction proposal. The marketing process is targeting receipt of bids in the fourth quarter 2014, with a targeted closing date on any transaction(s) in the ordinary course following successful execution of sales agreement(s), which aligns with our other strategic activities.

Despite having liquidity of over $230 million at October 31, 2014, we are also continuing our liquidity enhancement program, including sales of non-core assets, reducing outstanding letters of credit, tax structuring and other items.

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While there are processes and accountabilities covering each separate component of these strategic alternatives, we are currently unable to predict when any of these efforts will be completed, or if they will be completed at all.

Significant Contract Revisions

In March 2014, we agreed with KKR to an amendment to extend the ending date of the remaining required capital spending to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset and to broaden allowable spending to include acquisitions of producing properties that utilize partnership assets. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by C$0.13 per Mcf until at least 2016. Additionally, as a result of this amendment, KKR is no longer required to fund the capital for construction of a proposed gas treatment facility, but at its option may provide funding for any facility to be constructed by the partnership, including the proposed gas treatment facility. The amendment provides us with additional time and flexibility in completing a joint venture transaction involving our Horn River Asset and immediate cash flow relief through the reduced gathering fee paid to Fortune Creek.

In July 2014, we reached an agreement to lower the rates assessed for gas lift and gas gathering and processing from midstream providers serving our Barnett Shale Asset. Under the terms of the amendment, which is effective June 1, 2014, the rate assessed for gas lift was reduced by as much as 65% for volumes originating from the core dry gas areas in the Barnett Shale. Additionally, in the southern liquids-rich area of our Barnett Shale Asset, the rate assessed for aggregate gathering and processing was reduced by 40% to 45% on new wells completed in the next 24 months, and the lower rates will apply to these wells through the remaining term of the gathering and processing agreement.

2014 CAPITAL PROGRAM

We incurred costs related to our capital program of $107.6 million for the first nine months of 2014. We anticipate full-year 2014 spending to be between $130 million and $135 million. The capital program may be further reduced should commodity prices retreat further and become unsupportive of forecasted capital spending.

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RESULTS OF OPERATIONS

Three Months Ended September 30, 2014 and 2013

The following discussion compares the results of operations for the three months ended September 30, 2014 and 2013, or the 2014 quarter and 2013 quarter, respectively. “Other U.S.” refers to the combined amounts for our Niobrara Asset, West Texas Asset and Southern Alberta Basin Asset. The impacts of the Southwestern and Synergy Transactions were immaterial for further disaggregation.

Revenue

We aggregate production revenue and realized cash gains (losses) on derivatives not treated as hedges in measuring revenue from our oil and gas production. Historically, we have used hedge accounting and combining these items mirrors our view of the derivatives' usefulness, provides more comparability and is consistent with how management views and evaluates operating results.

Production Revenue and Realized Cash Gains (Losses) on Derivatives by Operating Area:

	Natural Gas				NGL					Oil				Total
	2014		2013		2014		2013			2014		2013		2014		2013
	(in millions)
Barnett Shale	$	47.4	$	39.7	$	15.8	$	18.4		$	0.9	$	1.3	$	64.1	$	59.4
Other U.S.	—		0.1		—		0.1			0.6		2.2		0.6		2.4
Hedging	7.3		13.5		—		—			—		—		7.3		13.5
U.S.	54.7		53.3		15.8		18.5			1.5		3.5		72.0		75.3
Horseshoe Canyon	16.5		13.2		—		—			—		—		16.5		13.2
Horn River	11.9		12.3		—		—			—		—		11.9		12.3
Hedging	2.2		3.7		—		—			—		—		2.2		3.7
Canada	30.6		29.2		—		—			—		—		30.6		29.2
Consolidated production revenue	$	85.3	$	82.5	$	15.8	$	18.5		$	1.5	$	3.5	$	102.6	$	104.5
U.S. realized cash derivative gains (losses)	$	1.9	$	4.3	$	0.2	$	(0.2	)	$	—	$	—	$	2.1	$	4.1
Canada realized cash derivative gains	0.8		3.9		—		—			—		—		0.8		3.9
Consolidated realized cash derivative gains (losses)	2.7		8.2		0.2		(0.2		)	—		—		2.9		8.0
Consolidated production revenue and realized cash derivative gains (1)	$	88.0	$	90.7	$	16.0	$	18.3		$	1.5	$	3.5	$	105.5	$	112.5

⁽¹⁾  Realized cash derivative gains (losses) from derivatives not treated as hedges are included in net derivative gains (losses). Unrealized derivative gains (losses) make up the remainder of net derivative gains (losses) as reported on our statement of income. A discussion of net derivative gains (losses) is found elsewhere in our discussion of our results of operations. Total revenue is comprised of production revenue, net derivative gains (losses), sales of purchased natural gas and other revenue.

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Average Daily Production Volume:

	Natural Gas		NGL		Oil		Equivalent Total
	2014	2013	2014	2013	2014	2013	2014	2013
	(MMcfd)		(Bbld)		(Bbld)		(MMcfed)
Barnett Shale	128.4	124.8	5,913	6,873	102	142	164.5	166.9
Other U.S.	0.1	0.1	—	16	72	258	0.5	1.8
U.S.	128.5	124.9	5,913	6,889	174	400	165.0	168.7
Horseshoe Canyon	45.8	49.5	3	6	—	—	45.8	49.5
Horn River	34.8	55.7	—	—	—	—	34.8	55.7
Canada	80.6	105.2	3	6	—	—	80.6	105.2
Consolidated	209.1	230.1	5,916	6,895	174	400	245.6	273.9

Average Realized Price:

	Natural Gas				NGL					Oil				Equivalent Total
	2014		2013		2014		2013			2014		2013		2014		2013
	(per Mcf)				(per Bbl)					(per Bbl)				(per Mcfe)
Barnett Shale	$	4.02	$	3.47	$	29.06	$	29.02		$	91.82	$	99.84	$	4.24	$	3.88
Other U.S.	1.38		7.15		—		50.05			89.08		95.18		12.84		14.63
Hedging	0.62		1.17		—		—			—		—		0.48		0.87
U.S.	4.63		4.64		29.06		29.07			90.69		96.83		4.74		4.86
Horseshoe Canyon	$	3.93	$	2.90	$	66.35	$	34.46		$	—	$	—	$	3.93	$	2.90
Horn River	3.71		2.40		—		—			—		—		3.71		2.40
Hedging	0.29		0.38		—		—			—		—		0.29		0.38
Canada	$	4.12	$	3.01	$	66.35	$	42.46		$	—	$	—	$	4.13	$	3.02
Consolidated production revenue	$	4.44	$	3.90	$	29.07	$	29.08		$	90.69	$	96.83	$	4.54	$	4.15
U.S. realized cash derivative gains (losses)	$	0.16	$	0.38	$	0.31	$	(0.26	)	$	—	$	—	$	0.14	$	0.27
Canada realized cash derivative gains	0.11		0.40		—		—			—		—		0.11		0.40
Consolidated realized cash derivative gains (losses)	0.14		0.39		0.31		(0.26		)	—		—		0.13		0.32
Consolidated production revenue and realized cash derivative gains	$	4.58	$	4.29	$	29.38	$	28.82		$	90.69	$	96.83	$	4.67	$	4.47

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The following table summarizes the changes in our production revenue and realized cash gains (losses) on derivatives:

	Natural Gas			NGL			Oil			Total
	(in thousands)
Consolidated production revenue and realized cash derivative gains for the 2013 quarter	$	90,713		$	18,281		$	3,561		$	112,555
Volume variances	(5,980		)	(2,618		)	(2,009		)	(10,607		)
Hedge revenue variances	(7,669		)	—			—			(7,669		)
Realized cash derivative variance (1)	(5,465		)	331			—			(5,134		)
Price variances	16,448			(5		)	(98		)	16,345
Consolidated production revenue and realized cash derivative gains for the 2014 quarter	$	88,047		$	15,989		$	1,454		$	105,490

⁽¹⁾  This amount is also included in the production revenue and realized cash derivatives gains table above.

Our natural gas revenue, without the effects of realized cash derivative gains/losses or hedge revenue, increased for the 2014 quarter from the 2013 quarter primarily due to an increase in our realized price partially offset by lower volumes produced. As the realized prices have increased, our hedge revenue and realized cash derivative gain/loss have decreased for the 2014 quarter compared to the 2013 quarter as we have maintained a similar derivative position only having a portion of our derivative portfolio with higher fixed prices expire resulting in a lower weighted average fixed price for our natural gas derivative portfolio. The decrease in natural gas volumes is primarily due to a decrease in volumes in our Horn River Asset due to natural well decline. The natural well decline in the U.S. was replaced by new well production. Consolidated production revenue and realized cash derivative gains from NGL revenue for the 2014 quarter decreased from the 2013 quarter due to lower volumes as we began ethane rejection in September 2014 and natural well decline partially offset by an increase from the impact of our derivatives. The decrease in oil volumes is primarily due to the Synergy Transaction partially offset by new well production in the 2014 quarter.

Our production revenue for the 2014 quarter and 2013 quarter was higher by $9.5 million and $17.2 million, respectively, because of our hedging activities.

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Sales of Purchased Natural Gas and Costs of Purchased Natural Gas

	For the Three Months Ended September 30,
	2014		2013
	(in thousands)
Sales of purchased natural gas
Purchases from Eni	$	15,583	$	14,405
Purchases from others	1,077		725
Total	16,660		15,130
Costs of purchased natural gas sold
Purchases from Eni	15,582		14,405
Purchases from others	1,017		709
Total	16,599		15,114
Net sales and purchases of natural gas	$	61	$	16

Net Derivative Gains (Losses)

The following table summarizes our net derivative gains and losses:

	For the Three Months Ended September 30,
	2014		2013
	(in thousands)
Unrealized mark-to-market changes in fair value of natural gas derivative gains (1)	$	39,854	$	24,385
Realized cash settlements of natural gas derivative gains	2,709		8,174
Unrealized mark-to-market changes in fair value of NGL derivative gains (1)	581		339
Realized cash settlements of NGL derivative gains (losses)	166		(165		)
Derivative gains, net	$	43,310	$	32,733

⁽¹⁾  Unrealized mark-to-market changes in fair value are subject to continuing market risk.

Other Revenue

	For the Three Months Ended September 30,
	2014		2013
	(in thousands)
Midstream revenue from third parties
Canada	$	486	$	496
Texas	427		211
Total	$	913	$	707

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Operating Expense

Lease Operating

	For the Three Months Ended September 30,
	2014				2013
	(in thousands, except per unit amounts)
			Per Mcfe					Per Mcfe
Barnett Shale
Expense	$	9,193	$	0.61	$	10,351		$	0.67
Equity compensation expense	165		0.01		99			0.01
	$	9,358	$	0.62	$	10,450		$	0.68
Other U.S.
Expense	$	309	$	6.63	$	889		$	5.46
Equity compensation expense	48		1.03		(23		)	(0.14		)
	$	357	$	7.66	$	866		$	5.32
Total U.S.
Expense	$	9,502	$	0.63	$	11,240		$	0.72
Equity compensation expense	213		0.01		76			0.00
	$	9,715	$	0.64	$	11,316		$	0.72
Horseshoe Canyon
Expense	$	6,096	$	1.45	$	6,408		$	1.41
Equity compensation expense	415		0.10		84			0.02
	$	6,511	$	1.55	$	6,492		$	1.43
Horn River
Expense	$	950	$	0.30	$	783		$	0.15
Equity compensation expense	—		—		—			—
	$	950	$	0.30	$	783		$	0.15
Total Canada
Expense	$	7,046	$	0.95	$	7,191		$	0.74
Equity compensation expense	415		0.06		84			0.01
	$	7,461	$	1.01	$	7,275		$	0.75
Total Company
Expense	$	16,548	$	0.73	$	18,431		$	0.73
Equity compensation expense	628		0.03		160			0.01
	$	17,176	$	0.76	$	18,591		$	0.74

Lease operating expense for the 2014 quarter in the Barnett Shale decreased in total and on a unit basis primarily due to a non-cash inventory impairment in the 2013 quarter. In Other U.S., the decrease in total lease operating expense is primarily due to the Synergy and Southwestern Transactions. The Horn River increase on a unit basis is primarily due to fixed charges being distributed over lower volume compared to the 2013 quarter.

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Gathering, Processing and Transportation

	For the Three Months Ended September 30,
	2014				2013
	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale	$	23,910	$	1.58	$	23,398	$	1.52
Other U.S.	1		0.01		2		0.01
Total U.S.	23,911		1.58		23,400		1.51
Horseshoe Canyon	784		0.19		718		0.16
Horn River	10,112		3.16		11,449		2.23
Total Canada	10,896		1.47		12,167		1.26
Total	$	34,807	$	1.54	$	35,567	$	1.41

Barnett GPT increased on a unit basis for the 2014 quarter compared to the 2013 quarter primarily as a result of our production area mix as production has increased in the dry gas areas of our northern Barnett Asset. Horn River GPT increased on a unit basis for the 2014 quarter compared to the 2013 quarter primarily as a result of higher unused firm capacity. Canadian GPT includes payments made for unused firm capacity of $4.3 million and $1.7 million for the 2014 quarter and the 2013 quarter, respectively.

Production and Ad Valorem Taxes

	For the Three Months Ended September 30,
	2014				2013
	(in thousands, except per unit amounts)
			Per Mcfe					Per Mcfe
Production taxes
Barnett Shale	$	1,110	$	0.07	$	848		$	0.06
Other U.S.	251		5.40		172			1.05
Total U.S.	1,361		0.09		1,020			0.07
Horseshoe Canyon	26		0.01		(66		)	(0.01		)
Horn River	—		—		—			—
Total Canada	26		0.00		(66		)	(0.01		)
Total production taxes	1,387		0.06		954			0.04
Ad valorem taxes
Barnett Shale	$	1,746	$	0.12	$	2,645		$	0.17
Other U.S.	9		0.20		178			1.09
Total U.S.	1,755		0.12		2,823			0.18
Horseshoe Canyon	732		0.17		948			0.21
Horn River	193		0.06		(47		)	(0.01		)
Total Canada	925		0.12		901			0.09
Total ad valorem taxes	2,680		0.12		3,724			0.15
Total	$	4,067	$	0.18	$	4,678		$	0.19

Ad valorem taxes in our Barnett Shale Asset decreased primarily due to lower assessed values.

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Depletion, Depreciation and Accretion

	For the Three Months Ended September 30,
	2014				2013
	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Depletion
U.S.	$	7,654	$	0.50	$	7,880	$	0.51
Canada	1,080		0.15		1,058		0.11
Total depletion	8,734		0.39		8,938		0.35
Depreciation of other fixed assets
U.S.	$	1,554	$	0.10	$	1,802	$	0.12
Canada	2,262		0.30		2,377		0.25
Total depreciation	3,816		0.17		4,179		0.17
Accretion	1,419		0.06		1,273		0.05
Total	$	13,969	$	0.62	$	14,390	$	0.57

The Canadian depletion rate increased for the 2014 quarter, when compared to the 2013 quarter, primarily due to increased depletable asset base.

Impairment Expense

In the 2014 quarter, we recognized a non-cash impairment of $0.1 million related to midstream assets in our West Texas Asset.

General and Administrative

	For the Three Months Ended September 30,
	2014				2013
	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Expense	$	6,484	$	0.29	$	7,299	$	0.29
Strategic transaction costs	1,885		0.08		823		0.03
Equity compensation	2,941		0.13		2,349		0.09
Total	$	11,310	$	0.50	$	10,471	$	0.41

The increase in equity compensation, when compared to the 2013 quarter, is primarily due to annual employee long-term incentive grants for 2014 being issued in the 2014 quarter and includes vesting for retirement eligible and imminently retirement eligible individuals. Strategic transaction costs relating to asset marketing and retaining a Strategic Alternatives Officer have increased for the 2014 quarter as activity has increased compared to the 2013 quarter.

Tokyo Gas Transaction Gain

In the 2013 quarter, we revised our Tokyo Gas Transaction gain, which resulted in an increase of $8.0 million. Further information regarding the transaction can be found in Note 2 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report.

Other Income (Expense)

In the 2014 quarter the Canadian foreign currency exchange rate resulted in a recognized loss of $2.8 million compared to the 2013 quarter, which included a recognized gain of $0.2 million.

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Fortune Creek Accretion

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. The decrease in Fortune Creek accretion is primarily due to a contribution made to Fortune Creek in March 2014, which reduced the partnership liability and related accretion expense.

Interest Expense

	For the Three Months Ended September 30,
	2014			2013
	(in thousands)
Interest costs on debt outstanding	$	38,736		$	39,443
Add:
Fees paid on letters of credit outstanding	89			71
Net expense paid on debt refinancing	—			(28		)
Non-cash interest (1)	2,601			1,870
Total interest costs incurred	41,426			41,356
Less:
Interest capitalized	(1,527		)	(2,001		)
Interest expense	$	39,899		$	39,355

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

Income Taxes

The effective tax rates for the three months ended September 30, 2014 and 2013 are as follows:

	For the Three Months Ended September 30,
	2014			2013
	(in thousands)
Income tax (benefit) expense - U.S.	$	(4,873	)	$	4,755
Effective tax rate - U.S.	(48.0		)%	41.0		%
Income tax (benefit) expense - Canada	$	(66	)	$	1,211
Effective tax rate - Canada	(1.0		)%	25.0		%
Income tax (benefit) expense - total	$	(4,939	)	$	5,966
Effective tax rate - total	(26.2		)%	36.1		%

Income tax expense for the 2014 quarter included decreases in the U.S. and Canadian valuation allowances of $12.3 million and $5.4 million, respectively. Deferred income tax recognized for the 2014 and 2013 quarters is a result of hedge gains previously deferred in AOCI being realized during the quarter and the net tax impact being recognized and a $7.6 million refund being filed in the U.S. in September 2014.

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RESULTS OF OPERATIONS

Nine Months EndedSeptember 30, 2014 and 2013

The following discussion compares the results of operations for the nine months ended September 30, 2014 and 2013, or the 2014 period and 2013 period, respectively. “Other U.S.” refers to the combined amounts for our Niobrara Asset, West Texas Asset and Southern Alberta Basin Asset. The impacts of the Southwestern and Synergy Transactions were immaterial for further disaggregation.

Revenue

We aggregate production revenue and realized cash gains (losses) on derivatives not treated as hedges in measuring revenue from our oil and gas production. Combining these items mirrors our view of the derivatives' usefulness, provides more comparability and is consistent with how management views and evaluates operating results.

Production Revenue and Realized Cash Gains (Losses) on Derivatives by Operating Area:

	Natural Gas					NGL						Oil				Total
	2014			2013		2014			2013			2014		2013		2014			2013
	(in millions)
Barnett Shale	$	148.0		$	141.8	$	51.1		$	59.6		$	3.7	$	4.9	$	202.8		$	206.3
Other U.S.	—			0.1		—			0.3			1.2		8.7		1.2			9.1
Hedging	22.1			43.2		—			—			—		—		22.1			43.2
U.S.	170.1			185.1		51.1			59.9			4.9		13.6		226.1			258.6
Horseshoe Canyon	53.5			43.1		—			0.1			—		—		53.5			43.2
Horn River	46.1			46.8		—			—			—		—		46.1			46.8
Hedging	6.5			9.7		—			—			—		—		6.5			9.7
Canada	106.1			99.6		—			0.1			—		—		106.1			99.7
Consolidated production revenue	$	276.2		$	284.7	$	51.1		$	60.0		$	4.9	$	13.6	$	332.2		$	358.3
U.S. realized cash derivative gains (losses)	$	(11.8	)	$	5.8	$	(2.3	)	$	(0.2	)	$	—	$	—	$	(14.1	)	$	5.6
Canada realized cash derivative gains (losses)	(0.7		)	8.5		—			—			—		—		(0.7		)	8.5
Consolidated realized cash derivative gains (losses)	(12.5		)	14.3		(2.3		)	(0.2		)	—		—		(14.8		)	14.1
Consolidated production revenue and realized cash derivative gains (losses) (1)	$	263.7		$	299.0	$	48.8		$	59.8		$	4.9	$	13.6	$	317.4		$	372.4

⁽¹⁾  Realized cash derivative gains (losses) from derivatives not treated as hedges are included in net derivative losses. Unrealized derivative gains (losses) make up the remainder of net derivative gains (losses) as reported on our statement of income. A discussion of net derivative gains (losses) is found elsewhere in our discussion of our results of operations. Total revenue is comprised of production revenue, net derivative gains (losses), sales of purchased natural gas and other revenue.

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Average Daily Production Volume:

	Natural Gas		NGL		Oil		Equivalent Total
	2014	2013	2014	2013	2014	2013	2014	2013
	(MMcfd)		(Bbld)		(Bbld)		(MMcfed)
Barnett Shale	123.4	145.9	6,195	7,852	141	193	161.4	194.2
Other U.S.	—	0.1	—	20	49	363	0.3	2.4
U.S.	123.4	146.0	6,195	7,872	190	556	161.7	196.6
Horseshoe Canyon	46.7	49.9	5	6	—	—	46.8	49.9
Horn River	40.5	59.4	—	—	—	—	40.5	59.3
Canada	87.2	109.3	5	6	—	—	87.3	109.2
Consolidated	210.6	255.3	6,200	7,878	190	556	249.0	305.8

Average Realized Price:

	Natural Gas					NGL						Oil				Equivalent Total
	2014			2013		2014			2013			2014		2013		2014			2013
	(per Mcf)					(per Bbl)						(per Bbl)				(per Mcfe)
Barnett Shale	$	4.39		$	3.56	$	30.24		$	27.78		$	94.98	$	92.38	$	4.61		$	3.90
Other U.S.	—			4.72		—			51.00			89.53		87.43		12.04			13.08
Hedging	0.66			1.08		—			—			—		—		0.50			0.80
U.S.	$	5.05		$	4.64	$	30.24		$	27.84		$	93.58	$	89.15	$	5.12		$	4.82
Horseshoe Canyon	$	4.19		$	3.16	$	37.39		$	55.62		$	—	$	—	$	4.19		$	3.17
Horn River	4.18			2.89		—			—			—		—		4.18			2.89
Hedging	0.27			0.32		—			—			—		—		0.27			0.32
Canada	$	4.46		$	3.34	$	37.39		$	55.62		$	—	$	—	$	4.46		$	3.34
Consolidated production revenue	$	4.80		$	4.09	$	30.25		$	27.87		$	93.58	$	89.15	$	4.89		$	4.29
U.S. realized cash derivative gains (losses)	$	(0.35	)	$	0.15	$	(1.33	)	$	(0.08	)	$	—	$	—	$	(0.32	)	$	0.10
Canada realized cash derivative gains (losses)	(0.03		)	0.29		—			—			—		—		(0.03		)	0.29
Consolidated realized cash derivative gains (losses)	$	(0.22	)	$	0.21	$	(1.33	)	$	(0.08	)	$	—	$	—	$	(0.22	)	$	0.17
Consolidated production revenue and realized cash derivative gains (losses)	$	4.58		$	4.30	$	28.92		$	27.79		$	93.58	$	89.15	$	4.67		$	4.46

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The following table summarizes the changes in our production revenue and realized cash gains (losses) on derivatives:

	Natural Gas			NGL			Oil			Total
	(in thousands)
Consolidated production revenue and realized cash derivative gains for the 2013 period	$	299,111		$	59,763		$	13,536		$	372,410
Volume variances	(40,633		)	(12,765		)	(8,907		)	(62,305		)
Hedge revenue variances	(24,237		)	—			—			(24,237		)
Realized cash derivative variance (1)	(26,772		)	(2,088		)	—			(28,860		)
Price variances	56,188			4,029			231			60,448
Consolidated production revenue and realized cash derivative gains for the 2014 period	$	263,657		$	48,939		$	4,860		$	317,456

⁽¹⁾  This amount is also included in the production revenue and realized cash derivatives gains table above.

Our natural gas revenue, without the effects of realized cash derivative gains/losses or hedge revenue, increased for the 2014 period from the 2013 period primarily due to an increase in our realized price. Lower volumes produced primarily attributable to the Tokyo Gas Transaction and natural declines in our Barnett and Horn River Assets partially offset by new well production reduced natural gas revenue. As the realized prices have increased, our hedge revenue and realized cash derivative gain/loss have decreased for the 2014 period compared to the 2013 period as we have maintained a similar derivative position by only having a portion of our derivative portfolio with higher fixed prices expire, resulting in a lower weighted average fixed price for our natural gas derivative portfolio. Consolidated production revenue and realized cash derivative gains from NGL revenue for the 2014 period decreased from the 2013 period due to lower volumes produced primarily attributable to the Tokyo Gas Transaction and declining well production and the 2014 period including an NGL derivative loss that the 2013 period did not, partially offset by an increase in realized prices. Our oil revenue decreased for the 2014 period from the 2013 period due to lower volumes resulting from the Synergy Transaction.

Our production revenue for the 2014 period and 2013 period was higher by $28.6 million and $52.9 million, respectively, because of our hedging activities.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas

	For the Nine Months Ended September 30,
	2014		2013
	(in thousands)
Sales of purchased natural gas
Purchases from Eni	$	50,627	$	48,208
Purchases from others	2,774		2,165
Total	53,401		50,373
Costs of purchased natural gas sold
Purchases from Eni	50,604		48,207
Purchases from others	2,701		2,104
Total	53,305		50,311
Net sales and purchases of natural gas	$	96	$	62

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Net Derivative Gains (Losses)

The following table summarizes our net derivative gains and losses:

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
Unrealized mark-to-market changes in fair value of natural gas derivative gains (losses) (1)	$	(1,948	)	$	21,734
Realized cash settlements of natural gas derivative gains (losses)	(12,478		)	14,294
Unrealized mark-to-market changes in fair value of NGL derivative gains (1)	1,599			339
Realized cash settlements of NGL derivative losses	(2,253		)	(165		)
Derivative gains (losses), net	(15,080		)	36,202

⁽¹⁾  Unrealized mark-to-market changes in fair value are subject to continuing market risk.

Other Revenue

	For the Nine Months Ended September 30,
	2014		2013
	(in thousands)
Midstream revenue from third parties
Canada	$	1,585	$	1,810
Texas	1,223		652
Total	$	2,808	$	2,462

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Operating Expense

Lease Operating

	For the Nine Months Ended September 30,
	2014				2013
	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale
Expense	$	29,638	$	0.67	$	33,785	$	0.64
Equity compensation expense	359		0.01		568		0.01
	$	29,997	$	0.68	$	34,353	$	0.65
Other U.S.
Expense	$	1,339	$	15.17	$	3,911	$	5.96
Equity compensation expense	145		1.64		174		0.27
	$	1,484	$	16.81	$	4,085	$	6.23
Total U.S.
Expense	$	30,977	$	0.70	$	37,696	$	0.70
Equity compensation expense	504		0.01		742		0.01
	$	31,481	$	0.71	$	38,438	$	0.71
Horseshoe Canyon
Expense	$	19,456	$	1.52	$	21,793	$	1.60
Equity compensation expense	1,092		0.09		197		0.01
	$	20,548	$	1.61	$	21,990	$	1.61
Horn River
Expense	$	2,593	$	0.23	$	3,271	$	0.20
Equity compensation expense	—		—		—		—
	$	2,593	$	0.23	$	3,271	$	0.20
Total Canada
Expense	$	22,049	$	0.93	$	25,064	$	0.84
Equity compensation expense	1,092		0.05		197		0.01
	$	23,141	$	0.98	$	25,261	$	0.85
Total Company
Expense	$	53,026	$	0.78	$	62,760	$	0.75
Equity compensation expense	1,596		0.02		939		0.01
	$	54,622	$	0.80	$	63,699	$	0.76

Lease operating expense for the 2014 period in the Barnett Shale decreased in total primarily due to the Tokyo Gas Transaction and a non-cash inventory impairment in the 2013 period. Other U.S. decreased in total for the 2014 period primarily due to the Southwestern and Synergy Transactions and on a unit basis the 2014 period increased as fixed lease operating charges were distributed over lower volume compared to the 2013 period. In Canada, the decrease in lease operating expense in total for the 2014 period compared to the 2013 period is primarily due to a stronger U.S. dollar. Included in 2014 period lease operating expense above is a fully discretionary employee bonus of $0.3 million in the Barnett Shale and $1.0 million in the Horseshoe Canyon.

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Gathering, Processing and Transportation

	For the Nine Months Ended September 30,
	2014				2013
	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale	$	68,947	$	1.57	$	80,136	$	1.51
Other U.S.	1		0.02		8		0.01
Total U.S.	68,948		1.56		80,144		1.49
Horseshoe Canyon	2,531		0.20		2,335		0.17
Horn River	31,032		2.81		29,585		1.82
Total Canada	33,563		1.41		31,920		1.07
Total	$	102,511	$	1.51	$	112,064	$	1.34

U.S. GPT on a gross basis decreased primarily due to lower volumes in our Barnett Shale Asset attributable to the Tokyo Gas Transaction. On a unit basis, the 2014 period was higher primarily due to higher electric rates and new production being in an area with higher GPT rates. Our Horn River Asset GPT increased in total and on a unit basis for the 2014 period as compared to the 2013 period as a result of increased gathering rates as the 2013 period included discounted rates prior to the contractual increase in volumes. Our Horn River Asset GPT includes payments made for unused firm capacity of $11.0 million and $4.6 million for the 2014 period and the 2013 period, respectively.

Production and Ad Valorem Taxes

	For the Nine Months Ended September 30,
	2014				2013
	(in thousands, except per unit amounts)
			Per Mcfe					Per Mcfe
Production taxes
Barnett Shale	$	3,365	$	0.08	$	2,807		$	0.05
Other U.S.	260		2.95		650			0.99
Total U.S.	3,625		0.08		3,457			0.06
Horseshoe Canyon	128		0.01		(30		)	0.00
Horn River	—		—		—			—
Total Canada	128		0.01		(30		)	0.00
Total production taxes	3,753		0.06		3,427			0.04
Ad valorem taxes
Barnett Shale	$	5,938	$	0.13	$	9,102		$	0.17
Other U.S.	110		1.25		444			0.68
Total U.S.	6,048		0.14		9,546			0.18
Horseshoe Canyon	2,182		0.17		2,006			0.15
Horn River	574		0.05		483			0.03
Total Canada	2,756		0.12		2,489			0.08
Total ad valorem taxes	8,804		0.13		12,035			0.14
Total	$	12,557	$	0.18	$	15,462		$	0.19

Ad valorem taxes in our Barnett Shale Asset decreased primarily due to lower assessed values and lower property ownership due to the Tokyo Gas Transaction.

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Depletion, Depreciation and Accretion

	For the Nine Months Ended September 30,
	2014				2013
	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Depletion
U.S.	$	22,263	$	0.50	$	27,580	$	0.51
Canada	4,582		0.19		3,350		0.11
Total depletion	26,845		0.39		30,930		0.37
Depreciation of other fixed assets
U.S.	$	4,769	0.11		$	5,833	0.11
Canada	6,759		0.28		7,231		0.24
Total depreciation	11,528		0.17		13,064		0.16
Accretion	4,211		0.06		3,917		0.05
Total	$	42,584	$	0.62	$	47,911	$	0.58

U.S. depletion for the 2014 period, when compared to the 2013 period, reflects a decrease in production. Canadian depletion increased for the 2014 period, when compared to the 2013 period, due to an increase in the current year depletion rate primarily due to increased depletable asset base partially offset by a decrease in production.

Impairment Expense

In the 2014 period, we recognized a non-cash impairment of $0.1 million related to midstream assets in our West Texas Asset.

General and Administrative

	For the Nine Months Ended September 30,
	2014				2013
	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Expense	$	24,722	$	0.36	$	28,198	$	0.33
Strategic transaction costs	5,843		0.09		2,693		0.03
Equity compensation	7,550		0.11		12,618		0.15
Total	$	38,115	$	0.56	$	43,509	$	0.51

The decrease in general and administrative expense is primarily due to reduced headcount compared to the 2013 period partially offset by an increase in employee incentive compensation. Included in the 2014 period expense above is a fully discretionary employee bonus of $3.0 million. Strategic transaction costs relating to asset marketing and retaining a Strategic Alternatives Officer have increased for the 2014 period as activity has increased compared to the 2013 period. The decrease in equity compensation is primarily due to the 2013 period including a $3.6 million correction for assumptions on forfeitures and vesting for retirement eligible and imminently retirement eligible individuals.

Tokyo Gas Transaction Gain

In April 2013, we recognized a $341.1 million gain upon closing of the Tokyo Gas Transaction, which was subsequently adjusted in the fourth quarter of 2013 to $339.3 million. Further information regarding the transaction can be found in Note 2 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report.

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Other Income (Expense)

In June 2013, we recognized an expense of $12.8 million in connection with the termination of the PEA with NGTL. In the 2014 period, the Canadian foreign currency exchange rate resulted in a recognized loss of $2.0 million compared to the 2013 period, which included a recognized loss of $2.3 million. In June 2014, we recognized expense of $3.0 million for an adjustment to the accounting of the Eni Transaction.

Fortune Creek Accretion

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. The decrease in Fortune Creek accretion is primarily due to a contribution made to Fortune Creek in the 2014 period, which reduced the partnership liability and related accretion expense.

Interest Expense

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
Interest costs on debt outstanding	$	116,787		$	125,589
Add:
Fees paid on letters of credit outstanding	235			174
Net expense paid on debt refinancing	682			67,010
Non-cash interest (1)	8,441			23,643
Total interest costs incurred	126,145			216,416
Less:
Interest capitalized	(4,218		)	(5,881		)
Interest expense	$	121,927		$	210,535

⁽¹⁾  Represents amortization of deferred financing costs and original issue discount net of interest swap settlement amortization. The 2013 and 2014 periods include $18.9 million and $0.6 million, respectively, relating to the early redemption of our Senior Notes due 2015 and Senior Notes due 2016 and the reduction of the Combined Credit Agreements.

Interest costs incurred for the 2014 period were lower when compared to the 2013 period primarily because of the refinancing of our debt securities in June 2013, which reduced our weighted average interest rate. The refinancing costs included the premium and fees associated with the tender offer and consent solicitation for the Senior Notes due 2015 and Senior Notes due 2016 and the consent solicitation for the Senior Notes due 2019.

Income Taxes

The effective tax rates for the nine months ended September 30, 2014 and 2013 are as follows:

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
Income tax (benefit) expense - U.S.	$	213		$	15,921
Effective tax rate - U.S.	(0.3		)%	7.3		%
Income tax (benefit) expense - Canada	$	868		$	2,142
Effective tax rate - Canada	24.8		%	(28.6		)%
Income tax (benefit) expense - total	$	1,081		$	18,063
Effective tax rate - total	(1.5		)%	8.5		%

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Income tax expense for the 2014 period included an increase in the U.S. valuation allowance of $21.1 million and a reduction in the Canadian valuation allowance of $2.2 million. Deferred income tax recognized for the 2014 and 2013 periods is a result of hedge gains previously deferred in AOCI being realized during the period and the net tax impact being recognized and a $7.6 million refund being filed in the U.S. in September 2014.

Quicksilver Resources Inc. and its Restricted Subsidiaries

Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 11 to our condensed consolidated interim 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, 2014. 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 multiple factors discussed further in the Liquidity and Borrowing Capacity section below.

For the remainder of 2014 through 2021, swaps economically hedge a portion of our natural gas revenue. The following summarizes future production hedged with commodity derivatives as of September 30, 2014.

Production Year	Daily Production Volume
	Natural Gas	Natural Gas Basis Swaps
	MMcfd	MMcfd
2014 (1)	170	40
2015	150	—
2016-2021	40	—

⁽¹⁾  Our natural gas basis swaps economically hedge the AECO basis adjustment from NYMEX.

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The following summarizes our cash flow activity for the 2014 period and 2013 period:

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
Net cash used in operating activities	$	(4,983	)	$	(81,103	)
Net cash provided by investing activities	152,220			300,515
Net cash provided by (used in) financing activities	9,769			(170,495		)

Operating Cash Flows

Net cash used in operating activities for the 2014 period decreased from the 2013 period primarily due to reduced interest payments as the 2013 period included payments related to our early redemption of senior notes and positive changes in working capital.

Net cash used in operating activities for the 2014 period includes hedge cash settlements of $7.4 million, which is deferred in other comprehensive income related to our long-dated hedges restructured in the first and fourth quarters of 2012. The revenue impact will be realized over the original term of the hedges, which extends until 2021.

Investing Cash Flows

Costs incurred for property, plant and equipment for the 2014 period and 2013 period were as follows:

	United States		Canada		Consolidated
	(in thousands)
For the Nine Months Ended September 30, 2014
Exploration and development	$	85,814	$	20,924	$	106,738
Midstream	83		—		83
Administrative	310		453		763
Total	$	86,207	$	21,377	$	107,584
For the Nine Months Ended September 30, 2013
Exploration and development	$	50,459	$	9,972	$	60,431
Midstream	26		2,343		2,369
Administrative	473		9,182		9,655
Total	$	50,958	$	21,497	$	72,455

Costs incurred reflect the activity of the 2014 capital program, while capital expenditures shown in the condensed consolidated statement of cash flows also reflect the related changes in working capital. Changes in working capital are driven by changes in accounts payable from prior year activities.

All of our Marketable Securities matured during the 2014 period and were held as cash or cash equivalents.

Financing Cash Flows

Net borrowings increased in the 2014 period compared to the 2013 period as we utilized our Combined Credit Agreements. Distributions of Fortune Creek partnership funds of $37.1 million and $8.1 million were paid in the 2014 period and the 2013 period, respectively, to our partner based on our partner's preferential distribution rights.

Liquidity and Borrowing Capacity

At September 30, 2014, the Combined Credit Agreements’ global borrowing base was $325 million and the global letter of credit capacity was $280 million. At September 30, 2014, there was $6.7 million available under the Combined Credit Agreements and we held cash or cash equivalents of $248.3 million.

50

In November 2014, the Combined Credit Agreements' global borrowing base was reaffirmed at $325 million and the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:

	Minimum EBITDAX Covenant
	(in millions)
Three months ending December 31, 2014	$	30.0
Six months ending March 31, 2015	59.0
Nine months ending June 30, 2015	87.25
Twelve months ending September 30, 2015	120.5
Twelve months ending December 31, 2015	122.0

The minimum required interest coverage ratio for the first and second quarter of 2016 continues to be 1.50 and 2.00, respectively.

Additionally, the Combined Credit Agreements were amended changing certain definitions that impact the calculation of EBITDAX in both the November 2014 amendment and the April 2014 amendment and we permanently reduced the aggregate maximum credit amounts under the Combined Credit Agreements from $1.75 billion to $650 million in April 2014 and to $450 million in November 2014.

Our ability to borrow under our Combined Credit Agreements depends on our global borrowing base, which is scheduled to be redetermined twice each year. A reduction to the global borrowing base during the spring or autumn redetermination, or upon a special redetermination requested by our administrative agent under the Combined Credit Agreements, would adversely impact our liquidity and ability to meet our future obligations. Our derivatives contribute to the global borrowing base. Most of our derivative positions expire at year-end 2015. The expiration of these derivatives will adversely affect our global borrowing base, and absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing, significant cost savings through avoidance or deferral, or operational efficiencies, we expect to need additional sources of liquidity, including additional debt or equity financing or proceeds from asset sales, at the beginning of 2016 assuming no material debt maturities prior to that date. In addition, we are exploring potential transactions involving any and all of our assets, including our Horn River Asset. If successful, a sale of our Horn River Asset could eliminate or defray our need to make or fund significant capital investments in the Horn River Asset but would also reduce our global borrowing base if not offset by the effects of any related debt reduction. A sale of our other assets could also enhance liquidity if the sale proceeds exceed the associated decrease to the global borrowing base, if any.

While we believe we will be able to comply with the financial covenants contained in our Combined Credit Agreements through the end of 2015, we do not expect to exceed the required levels by a significant margin, particularly the minimum EBITDAX covenant under our Combined Credit Agreements. Accordingly, even a modest decline in prices for natural gas and NGLs, our failure to achieve anticipated cost savings through avoidance or deferral or operational efficiencies, our failure to execute certain asset purchases or the inaccuracy in any material respect of any of the other assumptions underlying our forecast could cause us to fall short of the financial covenants contained in the Combined Credit Agreements. Absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing, significant cost savings through avoidance or deferral, or operational efficiencies, we do not expect to comply with our interest coverage ratio covenant under our Combined Credit Agreements beginning in the first quarter of 2016 and expect that we would need to seek additional covenant relief under the Combined Credit Agreements at that time. In addition, we have benefitted from our natural gas derivatives, which have resulted in cash proceeds being greater than the prevailing price for natural gas. Without the benefit of these derivatives, most of which expire at year-end 2015, our earnings would be reduced and our cash interest expense would exceed our resulting EBITDAX. Any inability to comply with the financial covenants contained in our Combined Credit Agreements, unless waived or amended by the requisite lenders, could materially and adversely affect our

51

liquidity by precluding further borrowings under our credit facilities and by accelerating the maturity of our debt. We may be unsuccessful in obtaining the necessary waivers or amendments.

In addition, we have significant fixed and springing debt maturities in 2015 and 2016, including the Combined Credit Agreements, the Second Lien Term Loan, the Second Lien Notes and the Senior Subordinated Notes. We do not expect to be able to satisfy these obligations with our cash on hand, committed financing or cash flow from operations. In order to satisfy these obligations we will need to obtain additional debt or equity financing or to sell assets, which we may not be able to do on satisfactory terms, or at all. We are limited in our ability to incur additional debt by the indenture restrictions as more fully described in Note 5. We may also seek to address the springing maturities by extending the maturity of or refinancing all or a portion of our Senior Subordinated Notes. If we are unsuccessful in extending or refinancing, we may not be able to satisfy such obligations when they mature. Our ability to address these springing maturities prior to filing our financial statements for the year ended December 31, 2014, is a key factor in our auditor’s going concern assessment. Our Combined Credit Agreements and Second Lien Term Loan require us to provide financial statements within 120 days of year-end with an accompanying audit report without a going concern paragraph. If we fail to accomplish this it would be an event of default under these agreements.

Our indentures require us to reinvest or repay senior debt with net cash proceeds from sales of certain assets within one year. If certain capital spending and senior debt repayment thresholds are not met, we would be required to make an offer to repay our notes. We expect to meet the remaining obligation in our indentures through our planned capital program and investments during 2014.

In order to be able to incur debt, make restricted payments, designate unrestricted subsidiaries or effect mergers or consolidations, we must meet an incurrence test under the indentures applicable to our debt, which test requires EBITDA to exceed interest expense by 2.25 times. At September 30, 2014 and throughout the three months ended September 30, 2014, we did not meet this test and, as a result, we are limited in our ability to, among other things, incur additional debt, except for specific baskets. We do retain, however, the ability to utilize the full borrowing capacity under our Combined Credit Agreements and the ability to refinance existing debt. Not meeting this ratio does not represent an event of default under our debt. We are unable to predict when or if our EBITDA will exceed interest expense by 2.25 times.

Additional information about our debt and related covenants is included in Note 5 to the condensed consolidated interim 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.

Although we have been in discussions on a potential transaction involving our Horn River Asset and have proposed transaction terms, we reached no agreement on any material terms, including structure or valuation. Accordingly, we developed a formalized marketing process for this asset, along with any and all of our assets. We may be unsuccessful in consummating a transaction involving our Horn River Asset or any of our other assets being marketed on acceptable terms, or at all.

We anticipate that our remaining 2014 capital program, contractual commitments and recurring operating needs will be funded by cash flow from operations or cash and other short-term securities on hand and supplemented by proceeds from asset sales, although we could also borrow under the Combined Credit Agreements. If our capital resources are insufficient to fund our needs, we will need to reduce our capital expenditures, implement further cost reductions, successfully renegotiate our contractual commitments or seek other financing alternatives. We may be unable to realize further cost reductions, renegotiate our contractual commitments or obtain financing needed in the future on acceptable terms, or at all. If we limit or defer our 2014 capital expenditure plan or are unsuccessful in developing reserves and adding production through that capital program or our cost-cutting efforts are too overreaching, we could adversely affect our ability to meet our forecasted results and the value of our oil and natural gas properties.

In March 2014, we agreed with KKR to an amendment to extend the ending date of the minimum gross capital expenditures requirement, of which C$120 million remains, to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset and to broaden allowable spending to include acquisitions of producing properties that utilize partnership assets. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of

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the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by C$0.13 per Mcf until at least 2016. We do not expect to be able to satisfy these capital expenditure requirements with our cash on hand, committed financing or cash flow from operations and will need to obtain additional debt or equity financing or sell assets, which we may not be able to do on satisfactory 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 equity securities or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness, reduce debt 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 flow from operations, borrowings under the Combined Credit Agreements, proceeds from asset sales, the issuance of debt or other securities or a combination of those sources. Because we have not met our incurrence test, we are unable to fund acquisitions with debt other than under our Combined Credit Agreements. Our ability to access the debt and equity capital markets on economic terms is affected by general economic conditions, the domestic and global financial markets, our credit ratings assigned by independent credit rating agencies, our operational and financial performance, the value and performance of our equity and debt securities, prevailing commodity prices, and other macroeconomic factors outside of our control. In addition, we believe that access to the capital markets will be limited if we are unable to execute significant deleveraging transactions, due in large part to our high debt levels relative to cash flow.

We continue to explore options to refinance the Senior Subordinated Notes. The economics and interest rate of any offering will be subject to market conditions. It is likely any new debt instruments will result in a material increase to our interest expense, which would be partially offset by the recognition of the unamortized deferred gain of the terminated interest rate swaps related to our Senior Subordinated Notes.

We have retained Houlihan Lokey Capital, Inc., Deloitte Transactions and Business Analytics LLP and other advisors to assist us in one or more of the following exercises:

• evaluation of options to address near-term debt maturities;

• enhancement of our liquidity position;

• evaluation of various strategic alternatives, including the acquisition or monetization of any and all assets or the Company; and

• employee retention.

Financial Position

The following impacted our balance sheet as of September 30, 2014, as compared to our balance sheet as of December 31, 2013:

• Cash, cash equivalents and marketable securities decreased $7.1 million as we used cash on hand to fund operations and capital expenditures and make a contribution to Fortune Creek, which was distributed to KKR based on their preferential rights, partially offset by net borrowings under the Combined Credit Agreements.

• The valuation of our current and non-current derivative assets and liabilities was $36.2 million lower on a net basis, which was primarily due to settlements during the year without additional derivatives being added and an increase in the natural gas forward curve.

• Our net property, plant and equipment balance decreased $48.3 million from December 31, 2013 to September 30, 2014. The Southwestern Transaction resulted in a decrease of $97.1 million. Additional decreases were due to DD&A incurred of $38.5 million and $19.7 million related to U.S.-Canadian exchange rate changes. Offsetting these decreases, we incurred capital costs of $107.6 million during 2014.

• The $15.2 million decrease in accounts payable was due primarily to a reduction in accrued capital expenditures of $1.8 million and a decrease in trade payables of $13.4 million from December 31, 2013 as ad valorem tax invoices were paid in 2014.

• Long-term debt increased $48.9 million primarily from net borrowings under the Combined Credit Agreements of $68.0 million and $4.3 million of amortized discounts, partially offset by early retirement of $18.7 million of our 2015 Senior Notes and 2016 Senior Notes, recognition of $1.5

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million of interest rate swaps and changes to the U.S.-Canadian exchange rate resulting in a decrease of $3.2 million.

• Partnership liability decreased $31.5 million primarily due to a $25.4 million contribution to Fortune Creek and periodic distribution of $11.7 million, both of which were distributed to KKR based on their preferential rights, and foreign exchange rate changes of $6.0 million, partially offset by accretion of $11.6 million.

Contractual Obligations and Commercial Commitments

There have been no significant changes to our contractual obligations and commitments as reported in our 2013 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 2013 Annual Report on Form 10-K. These critical estimates, for which no significant changes, other than those discussed in the results of operations, occurred during the nine months ended September 30, 2014, 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

We have no off-balance sheet arrangements within the meaning of Item 303(a)(4) of SEC Regulation S-K.

RECENTLY ISSUED ACCOUNTING STANDARDS

In May 2014, the FASB issued accounting guidance, “Revenue from Contracts with Customers,” requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for us in the first quarter of 2017. We have not yet selected a transition method and we are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.

No other pronouncements materially affecting our financial statements have been issued since the filing of our 2013 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. 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.

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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 $28.6 million and $52.9 million for the 2014 period and 2013 period, respectively, and a loss was recognized in net derivative losses of $14.7 million for the 2014 period and a gain of $14.1 million for the 2013 period. Unrealized losses of $0.3 million and gains of $22.1 million were recognized for the 2014 period and 2013 period, respectively.

The following table details our open derivative positions at September 30, 2014:

Product	Type	Segment	Remaining Contract Period	Volume	Price Per Mcf or Bbl
Gas	Swap	U.S.	Oct 2014 - Dec 2014	10 MMcfd	3.91
Gas	Swap	U.S.	Oct 2014 - Dec 2014	10 MMcfd	3.89
Gas	Swap	U.S.	Oct 2014 - Dec 2015	5 MMcfd	6.23
Gas	Swap	U.S.	Oct 2014 - Dec 2015	5 MMcfd	6.20
Gas	Swap	U.S.	Oct 2014 - Dec 2015	20 MMcfd	6.00
Gas	Swap	U.S.	Oct 2014 - Dec 2015	10 MMcfd	6.00
Gas	Swap	U.S.	Oct 2014 - Dec 2015	5 MMcfd	5.68
Gas	Swap	U.S.	Oct 2014 - Dec 2015	7.5 MMcfd	5.475
Gas	Swap	U.S.	Oct 2014 - Dec 2015	7.5 MMcfd	5.50
Gas	Swap	U.S.	Oct 2014 - Dec 2015	5 MMcfd	4.15
Gas	Swap	U.S.	Oct 2014 - Dec 2015	5 MMcfd	4.13
Gas	Swap	U.S.	Oct 2014 - Dec 2015	5 MMcfd	4.255
Gas	Swap	U.S.	Oct 2014 - Dec 2015	5 MMcfd	4.25
Gas	Swap	U.S.	Oct 2014 - Dec 2021	10 MMcfd	4.54
Gas	Swap	U.S.	Oct 2014 - Dec 2021	5 MMcfd	4.38
Gas	Swap	U.S.	Oct 2014 - Dec 2021	10 MMcfd	4.37
Gas	Swap	U.S.	Oct 2014 - Dec 2021	5 MMcfd	4.35
Gas	Swap	Canada	Oct 2014 - Dec 2015	10 MMcfd	6.42
Gas	Swap	Canada	Oct 2014 - Dec 2015	10 MMcfd	6.45
Gas	Swap	Canada	Oct 2014 - Dec 2015	10 MMcfd	4.04
Gas	Swap	Canada	Oct 2014 - Dec 2021	10 MMcfd	4.625
Gas Basis1	Swap	Canada	Oct 2014 - Dec 2014	5 MMcfd	(0.475)
Gas Basis1	Swap	Canada	Oct 2014 - Dec 2014	5 MMcfd	(0.475)
Gas Basis1	Swap	Canada	Oct 2014 - Dec 2014	10 MMcfd	(0.475)
Gas Basis1	Swap	Canada	Oct 2014 - Dec 2014	10 MMcfd	(0.47)
Gas Basis1	Swap	Canada	Oct 2014 - Dec 2014	10 MMcfd	(0.45)

¹ Our gas basis swaps economically hedge the AECO basis adjustment at a discount from NYMEX.

These open derivative positions had a net fair value of $91.2 million as of September 30, 2014.

The fair value of all derivative instruments included in these disclosures was estimated using prices quoted in markets for the periods covered by the derivatives and the value confirmed by counterparties. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives and adjusted for counterparty credit risk.

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Interest Rate Risk

Changes in interest rates affect the interest rate we pay on borrowings under the Combined Credit Agreements, Second Lien Term Loan and Second Lien Notes due 2019. Our Senior Unsecured 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 2014 period and the 2013 period, we recognized $1.5 million and $11.5 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, 2014, each $50 million in borrowings would result in additional annual interest payments of $2.0 million. If the current borrowing availability under our Combined Credit Agreements were to be fully utilized by year-end 2014 at interest rates as of September 30, 2014, we estimate that annual interest payments would increase by $0.3 million. If interest rates change by 1% on our September 30, 2014 variable debt balances of $276.0 million, our annual pre-tax income would decrease or increase by $2.8 million.

Our Second Lien Term Loan and Second Lien Notes due 2019 feature a LIBOR floor. Consequently, a 1% increase in the interest rates on our outstanding variable rate debt as of September 30, 2014, would not impact our applicable interest rate on this debt, as the floor would not be exceeded. A 1% decrease in the interest rate would not impact our applicable interest rate on this debt, as we have not exceeded the floor at September 30, 2014.

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 2014 period and the 2013 period resulted in losses of $2.0 million and $2.3 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, 2014, our disclosure controls and procedures were not effective, due to the outstanding remediation of the income tax material weakness identified at December 31, 2013, 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 2013 Annual Report on Form 10-K, two material weaknesses were identified related to the design and operating effectiveness of our controls. We identified a material weakness related to the accounting for significant, non-recurring transactions, particularly related to the accuracy of the inputs provided to accounting

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to incorporate into the analysis of such transactions. This weakness caused several out of period adjustments principally between quarters in 2013 to be recognized in our financial statements though none of the adjustments were considered individually material. We remediated this material weakness as of June 30, 2014 by the design and operating effectiveness of additional controls regarding significant transactions.

We also had a material weakness related to the operating effectiveness of controls over the reconciliation of deferred income taxes, particularly related to the tax basis in property, plant and equipment. In response to this material weakness, management is working to complete a detailed reconciliation of the property, plant and equipment account balances. While the remediation process is not yet complete, we have concluded that the financial statements in this Quarterly Report on Form 10-Q present fairly, in all material respects, our consolidated financial condition, results of operations and cash flows in conformity with generally accepted accounting principles in the U.S.

There has been no other change in our internal control over financial reporting during the quarter ended September 30, 2014, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1.   Legal Proceedings

In each of July 2011 and June 2012, we received a subpoena duces tecum from the SEC requesting certain documents. In July 2014, the SEC notified us that the staff has completed its investigation and does not intend to recommend an enforcement action by the SEC against us.

There have been no other material changes in the legal proceedings described in Part I, Item 3 included in our 2013 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 2013 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, 2014.

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 2014	—	$	—	—	—
August 2014 (3)	436	$	1.80	—	—
September 2014	1,363	$	1.15	—	—
Total	1,799	$	1.31	—	—

⁽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.

⁽³⁾  Excluded from this amount is 816 shares with an average price of $3.05 which were a correction to a previous month.

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.

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ITEM 5. Entry into a Material Definitive Agreement

On November 7, 2014, Quicksilver Resources Inc. and Quicksilver Resources Canada Inc. (“Quicksilver Canada”) entered into an Omnibus Amendment to the Combined Credit Agreements, among Quicksilver, Quicksilver Canada, the U.S. lenders party thereto, the Canadian lenders party thereto, JPMorgan Chase Bank, N.A., as global administrative agent, and JPMorgan Chase Bank, N.A., Toronto Branch, as Canadian administrative agent (the “Amendment”). The Amendment amended the terms of the Combined Credit Agreements to, among other things:

• Reaffirm the global borrowing base at $325 million;

• Permanently reduce the aggregate maximum credit amount under the Combined Credit Agreements from $650 million to $450 million;

• Eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015;

• Add a minimum EBITDAX covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:

	Minimum EBITDAX Covenant
	(in millions)
Three months ending December 31, 2014	$	30.0
Six months ending March 31, 2015	59.0
Nine months ending June 30, 2015	87.25
Twelve months ending September 30, 2015	120.5
Twelve months ending December 31, 2015	122.0

• Change certain definitions that impact the calculation of EBITDAX.

The full text of the Amendment is attached as Exhibit 10.7 to this Quarterly Report on Form 10-Q.

Certain of the parties to the Amendment and their respective affiliates have, from time to time, performed, and may in the future perform, various financial, advisory, commercial banking and investment banking services for Quicksilver and Quicksilver’s affiliates in the ordinary course of business for fees and expenses.

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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	Second Amendment to Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.					†
10.2	Third Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP, Cowtown Gas Processing Partners L.P. and Cowtown Pipeline Partners L.P.					†
10.3	Fourth Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP, Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P.					†
10.4	Third Amendment to Amended and Restated Gas Gathering Agreement, dated August 13, 2012, between Quicksilver Resources Inc. and Cowtown Pipeline Partners L.P.					†
10.5	Fourth Amendment to Amended and Restated Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.					†
10.6	Fifth Amendment to Amended and Restated Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.					†
10.7	Omnibus Amendment No. 8 to Combined Credit Agreements, dated as of November 7, 2014, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein					†
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					†
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					†
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					†
101.INS	XBRL Instance Document					‡
101.SCH	XBRL Taxonomy Extension Schema Linkbase Document					‡
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					‡
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document					‡
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					‡
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document					‡

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SIGNATURES

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

Dated:	November 10, 2014	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)

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EXHIBIT INDEX

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
10.1	Second Amendment to Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.					†
10.2	Third Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP, Cowtown Gas Processing Partners L.P. and Cowtown Pipeline Partners L.P.					†
10.3	Fourth Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP, Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P.					†
10.4	Third Amendment to Amended and Restated Gas Gathering Agreement, dated August 13, 2012, between Quicksilver Resources Inc. and Cowtown Pipeline Partners L.P.					†
10.5	Fourth Amendment to Amended and Restated Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.					†
10.6	Fifth Amendment to Amended and Restated Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.					†
10.7	Omnibus Amendment No. 8 to Combined Credit Agreements, dated as of November 7, 2014, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein					†
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					†
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					†
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					†
101.INS	XBRL Instance Document					‡
101.SCH	XBRL Taxonomy Extension Schema Linkbase Document					‡
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					‡
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document					‡
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					‡
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document					‡

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EX-10.1

Exhibit 10.1

SECOND AMENDMENT TO
GAS GATHERING AGREEMENT

[Alliance]

This Second Amendment to the Gas Gathering Agreement (the “Second Amendment”) is executed July 9, 2014 but effective as of June 1, 2014 (the “Effective Date”), by and between Quicksilver Resources Inc. (“Quicksilver”) and TG Barnett Resources LP (“TG”) (Quicksilver and TG are collectively referred to herein as “Producer”), and Cowtown Pipeline Partners L.P. (“Gatherer”).

WHEREAS, Producer and Gatherer are parties to the Gas Gathering Agreement, dated as of December 1, 2009, as amended by Amendment to Gas Gathering Agreement dated October 1, 2010 (collectively referred to as the “Alliance Agreement”);

WHEREAS, by virtue of that certain Assignment, Bill of Sale and Conveyance, by and between Quicksilver and TG, dated the 30th day of April 2013, effective September 1, 2012, TG has been assigned an interest in the Alliance Agreement; and

WHEREAS, the parties desire to amend the terms of the Alliance Agreement as provided in this Second Amendment;

NOW, THEREFORE, in consideration of the mutual premises and benefits contained herein, the adequacy, receipt and sufficiency of which are hereby acknowledged, Producer and Gatherer amend the terms of the Alliance Agreement, as follows:

1. Article 1, Definitions is amended as follows:

Section m., “Escalation Date” shall be deleted in its entirety and the following substituted in its place: “m. “Escalation Date”, except for the Lift Gas Fee, shall mean January 1^st 2015 and each January 1^st thereafter during the Term. The Escalation Date for the Lift Gas Fee shall mean January 1, 2016 and each January 1^st thereafter during the Term.”

2. Article 1, Definitions is amended to add the following definition:

“oo.    “Lift Gas Volume” is the amount of Gas, reserved by Producer under Section 3.2, used by Producer for gas lift operations in the Contract Area, measured in MCFs at the existing Alliance CMU meter station number ALSA020MU.”

3. Article 11, Fees is amended by replacing the first sentence in 11.1 with the following:

“Producer shall pay to the Gatherer 59.355 cents ($0.59355) multiplied by the positive difference between (i) the total volume of Producer’s Gas (measured in Mcf) metered at the Receipt Point(s) and (ii) the Lift Gas Volume, subject to adjustment as provided in Section 11.2 (such rate, as so adjusted, the “Gathering Fee”).”

4. Article 11, Fees is amended to add the following:

“11.3    Producer shall pay to Gatherer twenty cents ($.20) per Mcf multiplied by the Lift Gas Volume pursuant to this Agreement, subject to adjustment as provided in Section 11.2 (such rate, as so adjusted, the “Lift Gas Fee”).

“11.4 For the period beginning on July 1, 2014 and ending on June 30, 2016, Gatherer shall work with Producer to evaluate the purchase of all or a portion of Producer’s existing and future gas lift systems at Alliance. Regardless of whether the parties are able to reach a mutual agreement as to such potential purchase(s), Gatherer shall have the Exclusive Right to provide Producer’s gas lift needs for the remaining Term of the Alliance Agreement. As used herein, the term “Exclusive Right” is defined to mean that (i) Gatherer shall be the exclusive provider of gas lift services to Producer at the existing and any future points delivered into Producer’s existing and future gas lift systems, and (ii) Producer shall negotiate with no other party and deal exclusively with Gatherer to potentially provide any alternative gas lift method which could eliminate or materially alter the then existing manner in which Gatherer supplies lift gas to Producer at existing and future wells. This Exclusive Right is not intended to hinder Producer from alternative non gas lift methods (including, but not limited to, plungers or other similar lifting technologies) at any individual well (including each such well for which there is no gas lift pipeline connection as of the date hereof), where such lift gas being provided or to be provided, as applicable by Gatherer is not or will not be adequate at such particular well to provide Producer’s lift requirements. Producer shall retain sole discretion in the deployment of these alternative non gas lift techniques; provided in the event that Producer employs such artificial non gas lift techniques on a well, it will notify Gatherer within a commercially reasonable time frame.”

Except as amended by this Second Amendment, the terms and provisions of the Alliance Agreement are and shall remain in full force and effect.

Capitalized terms used but not otherwise defined herein shall have the meaning given such terms in the Alliance Agreement.

2

IN WITNESS WHEREOF, the parties hereto have caused this Second Amendment to be duly executed by their respective authorized officers as of the Effective Date.

QUICKSILVER RESOURCES INC.
By:	/s/ C.C. Rupnow
	Name: Clifford Rupnow
	Title: VP Product Mktg & Transp.

TG BARNETT RESOURCES LP
By:	/s/ Koji Yoshizaki
	Name: KOJI YOSHIZAKI
	Title: Vice President and Secretary

COWTOWN PIPELINE PARTNERS L.P.
By:	Crestwood Gas Services Operating GP LLC, its general partner
By:	/s/ J. Heath Deneke
	Name: Heath Deneke
	Title: President Natural Gas Business Unit

3

EX-10.2

Exhibit 10.2

Third Amendment

To Sixth Amended and Restated Gas Gathering and Processing Agreement

(Cowtown Gas Facilities)

This Third Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement (Cowtown) (this “Third Amendment”) is made and entered into this 9^th day of July, 2014, but effective January 1, 2014 (“Effective Date”), by and among Quicksilver Resources Inc. (“Quicksilver”), TG Barnett Resources LP (“TG”) (Quicksilver and TG may be collectively referred to herein as “Producers”), Cowtown Gas Processing Partners L.P. (“Processor”) and Cowtown Pipeline Partners L.P. (“Gatherer”). Producers, Processor and Gatherer may be individually referred to as a “Party”, and collectively, as the “Parties”.

Recitals:

Whereas, Quicksilver, Processor, and Gatherer are the original parties to that certain Sixth Amended and Restated Gas Gathering Agreement dated September 1, 2008 (the “Original Agreement”), as amended by: (i) that certain Addendum and Amendment to Gas Gathering and Processing Agreement – Mash Unit Lateral dated as of January 1, 2009, (ii) that certain Amendment No. 1 to Addendum and Amendment to Gas Gathering and Processing Agreement – Mash Unit Lateral dated as of August 1, 2010, (iii) that certain Second Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement dated as of October 1, 2010, and (iv) that certain Amended and Restated Second Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement dated October 1, 2010 (collectively, (i) through (iv) immediately preceding are referred to herein as the “Prior Amendments”; the Original Agreement and the Prior Amendments are referred to herein collectively as the “Agreement”);

Whereas, by virtue of that certain Assignment, Bill of Sale and Conveyance, by and between Quicksilver and TG, dated the 30^th day of April 2013, effective September 1, 2012, TG has been assigned an interest in the Agreement and is therefore a Producer party (as that term is defined in the Agreement) thereto; and

Whereas, Producers, Processor and Gatherer desire to amend the Agreement, as set forth herein.

Now     therefore, in consideration of the mutual covenants herein, Producers, Processor, and Gatherer agree as follows:

1. A new section 27 shall be added to the Agreement as follows:

“Section 27    Liquid Nominations and Imbalances

27.1Plant Products Delivery Point(s) Nominations. No later than 12:00PM, four (4) business days prior to the beginning of each Month, Processor shall notify Quicksilver of the volumes of Plant Products per day that Processor anticipates will be made available for delivery to Producers at the Plant Products Delivery Point(s). No later than 12:00 PM, two (2) business days prior to the start of such Month, Quicksilver shall notify Processor of the Plant Products Delivery Point(s) where Plant Products are to be delivered by Processor and the specific amount of barrels associated therewith. At any time during the term hereof, Producers may adjust its nominations prospectively for the remainder of such Month by providing Processor notice prior to the nomination deadline of the applicable pipeline at the Plant Products Delivery Point(s) for making such changes.

27.2Because of dispatching and other causes outside of Processor’s reasonable control, imbalances may occur between the Plant Products delivered at the Plant Products Delivery Point(s) for Producers’ account and the Plant Products allocated to Producers as determined in Article 10 of the Agreement. Processor and Producers shall both use commercially reasonable efforts to manage daily receipts and deliveries so that any imbalances shall be kept as near to zero as practicable. Any imbalances described above shall be resolved in the following manner:

a.At the same time that Processor provides Quicksilver a statement pursuant to Section 14.1, Processor shall submit to Quicksilver a statement reflecting the “Liquid Volume Variance” for the previous Month which shall include the following information: (x) a comparison of (A) the volume of each Plant Product delivered for Producers’ account to the Plant Products Delivery Point(s), to (B) Producers’ allocated Plant Products as determined in Article 10 of the Agreement, (y) the value, using the pricing in Section 27.2(b) below, of the volume differences determined in such comparison, and (z) such other information and detail as may be mutually agreeable to the Parties. If there are amounts owed by each party pursuant to the Liquid Volume Variance calculation, then Processor shall net such amounts and reflect on the statement the net payment owed by the party with the greater payment obligation. In addition, Processor shall net such amount against the amount owed pursuant to Section 14.1 and reflect

on the statement the net payment amount owed by the party with the greater payment obligation, and any payment owed shall be due as provided in Section 14.1, but paid as provided above.

b.The value to be used for each Plant Product volume imbalance for the production Month shall be the Oil Price Information Service (OPIS) average monthly prices, using purity ethane, NON-TET propane, normal butane, ISO-butane, and natural gasoline, as applicable, less a “Transportation Fee” and a “Fractionation Fee”. For purposes of this Section 27.2(b), the Transportation Fee shall be $0.02091846/gallon and the Fractionation Fee shall be the higher of (A) 6.6678 cents per gallon or (B) (0.25 X “Fuel”) + 5.5, where Fuel = Houston Ship Channel First of the Month Index as published by Platts Gas Daily. The Transportation Fee and the fixed portion of the Fractionation Fee shall be adjusted each January during the term hereof, commencing January 1, 2015 using the most recent "F.E.R.C. Oil Pipeline Index - Multiplier to Use" as published online by the Federal Energy Regulatory Commission.  Gatherer and Processor will provide Producers notice of yearly escalation prices.

27.3In the event Producers, Gatherer, or Processor reasonably determines that the prices used in either the Transportation Fee or the Fractionation Fee above in Section 27.2(b) are no longer representative of current market prices, then such Party shall notify the other Parties in writing and propose a new price it reasonably believes to reflect current market value and the effective date of implementing said new price. Upon receipt of said proposal, the receiving Parties shall have 10 days to accept or reject the proposal or deliver a counter proposal to the proposing Party. If the receiving Parties reject the proposal or the proposing Party rejects the receiving Parties’ counter proposal within 10 days from the receipt thereof, then the proposing Party may invoke the dispute resolution procedures set forth in Article 23 to resolve such matter; provided, however, in no event shall the arbitrator(s) establish and set a price for the Fractionation Fee that would be less than 6.375 cents per gallon; provided, further, no Party may invoke this price renegotiation mechanism more than once per any 12 month period. For purposes of this Section 27.3, if the receiving Party fails to reject the proposed price in the proposal within its respective 10 day deadline or if the proposing Party fails to reject the proposed price in the counter proposal from the receiving Parties within its respective 10 day deadline, then such failure shall be deemed acceptance by such Party of the applicable fee.”

IN WITNESS WHEREOF, the Parties hereto have executed and delivered this Third Amendment as of the Effective Date.

Quicksilver:
Quicksilver Resources Inc.
By:	/s/ C.C. Rupnow
	Name: Cliff Rupnow
	Title: Vice President - Product Marketing & Transportation

TG:
TG Barnett Resources LP
By:	/s/ Koji Yoshizaki
	Name: KOJI YOSHIZAKI
	Title: Vice President and Secretary

Gatherer:
Cowtown Pipeline Partners L.P.
By:	Crestwood Gas Services Operating GP LLC, its general partner
By:	/s/ J. Heath Deneke
	Name: Heath Deneke
	Title: President Natural Gas Business Unit

Processor:
Cowtown Gas Processing Partners L.P.
By:	Crestwood Gas Services Operating GP LLC, its general partner
By:	/s/ J. Heath Deneke
	Name: Heath Deneke
	Title: President Natural Gas Business Unit

EX-10.3

Exhibit 10.3

FOURTH AMENDMENT TO
SIXTH AMENDED AND RESTATED
GAS GATHERING AND PROCESSING AGREEMENT
(Cowtown Gas Facilities)

This Fourth Amendment to the Sixth Amended and Restated Gas Gathering and Processing Agreement (this “Fourth Amendment”) is executed July 9, 2014 and effective as of June 1, 2014 (the “Fourth Amendment Effective Date”), by and among Quicksilver Resources Inc. (“Quicksilver”), TG Barnett Resources LP (“TG”) (Quicksilver and TG are collectively referred to herein as “Producer”), Cowtown Pipeline Partners L.P. (“Gatherer”), and Cowtown Gas Processing Partners L.P. (“Processor”). Capitalized terms not otherwise defined shall have the meaning given such terms in the Cowtown Agreement.

WHEREAS, Quicksilver, Gatherer and Processor are parties to the Sixth Amended and Restated Gas Gathering and Processing Agreement, dated as of September 1, 2008, as amended by the (i) Addendum and Amendment (Mash Unit Lateral), dated as of January 1, 2009, as amended by Amendment No. 1 To Gas Gathering and Processing Agreement Mash Unit Lateral dated July 22, 2010 but effective August 1, 2010, (ii) the Amended and Restated Second Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement executed August 13, 2012, effective October 1, 2010, and (iii) Third Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement executed July 9, 2014, effective January 1, 2014 (collectively, the “Cowtown Agreement”);

Whereas, by virtue of that certain Assignment, Bill of Sale and Conveyance, by and between Quicksilver and TG, dated the 30^th day of April 2013, effective September 1, 2012, TG has been assigned an interest in the Cowtown Agreement; and

WHEREAS, the parties hereto desire to amend certain of the terms of the Cowtown Agreement as provided in this Third Amendment;

NOW, THEREFORE, in consideration of the mutual premises and benefits contained herein, the adequacy, receipt and sufficiency of which are hereby acknowledged, Producer, Gatherer and Processor agree as follows:

1.The first paragraph of the Cowtown Agreement is amended to add TG as a Producer Party, such that Quicksilver and TG are collectively deemed to be “Producer” as of September 1, 2012.

2.Article I “Definitions” Section 1.1 is amended by adding the additional definitions as follows:

‘ “Qualifying Well(s)” shall mean (i) new wells drilled in the Contract Area that are requested by Producer to be added as such after Gatherer has provided the cost for the required pipeline, meter and appurtenant facilities connecting such Qualifying Well to Gatherer’s Gathering System, and (ii), the wells currently shut-in, as identified on the list provided by Producer on May 8, 2014; such shut-in wells being listed on Exhibit B, attached

hereto, under the heading “Qualifying Well(s).” Once a new well is determined to be a Qualifying Well, such a well, as well as the shut-in wells listed as Qualifying Wells on Exhibit B, shall remain a Qualifying Well(s), for the remaining term of this Agreement. Further, each party's existing obligations and responsibilities in the Cowtown Agreement, as amended by the provisions herein, shall apply to any and all Qualifying Well(s).

“Incentive Rate Period” shall mean the time period consisting of a primary term of two (2) years commencing upon first delivery of gas from the first of the Qualifying Well(s), to Gatherer, and ending two (2) years after the date of such commencement, with a secondary term month-to-month after the end of the primary term, such secondary term subject to termination by Gatherer by giving one-hundred eighty (180) days prior written notice of such termination to Producer.’

3.Article IV, Section 4.4 is deleted in its entirety and replaced with the following:

“a.    In the event that the Producer has elected to classify a well as a Qualifying Well, Producer shall provide written notice to Gatherer of Producer’s election to classify a well as a Qualifying Well, and within 45 days of Gatherer’s receipt of Producer’s notice, Gatherer shall notify Producer of Gatherer’s decision to construct or not to construct a pipeline, meter and appurtenant facilities connecting such Qualifying Well to Gatherer’s Gathering System. Gatherer, in its sole and absolute discretion, may elect to construct such Gathering System expansion to the Qualifying Well. In such an event Producer shall reimburse Gatherer all actual pipeline and appurtenant facilities’ design and construction costs associated with the Gathering System expansion, and such Gathering System expansion shall, at all times, be owned and operated by Gatherer. If Gatherer, in its sole and absolute discretion, declines to construct a Gathering System expansion, Producer may elect to construct a Gathering System expansion at its sole cost and expense. Any such Gathering System expansion must meet all of Gatherer’s specifications, and Gatherer will be responsible for a meter station and connection to the then existing Gathering System. Gatherer may, at its election, but within two (2) years of the initial delivery of production from such Gathering System expansion acquire the ownership of the Gathering System expansion installed by the Producer by reimbursing Producer for the actual cost of the Gathering System expansion with no allowance for inflation or depreciation. In such an event, Producer agrees to execute all assignments or contracts deemed necessary by Gatherer to accomplish the transfer to Gatherer of title to the Gathering System expansion, including rights-of-way and easements. In the event that neither Gatherer nor Producer elects to construct a Gathering System expansion to connect to Gatherer’s Gathering System, this Agreement shall terminate as to the gas from such well or wells and such gas will be deemed released from this Agreement.

b.    In the event that Producer elects to not classify a well as a Qualifying Well, Producer shall provide written notice to Gatherer of Producer’s election to not classify a well as a Qualifying Well, and within 45 days of Gatherer’s receipt of Producer’s notice, Gatherer shall notify Producer of Gatherer’s decision to construct or not to construct a pipeline, meter and appurtenant facilities connecting such non-Qualifying Well to Gatherer’s Gathering System. Gatherer, in its sole and absolute discretion, may elect to construct such Gathering

System expansion at its sole cost and expense and such gas produced as a result of such Gathering System expansion shall be subject to the fees and terms applicable under the Cowtown Agreement for a Gathering System Delivery Point(s) and shall not be considered a Qualifying Well. If Gatherer, in its sole and absolute discretion, declines to construct a Gathering System expansion, Producer may elect to construct a Gathering System expansion at its sole cost and expense. Any such Gathering System expansion must meet all of Gatherer’s specifications, and Gatherer will be responsible for a meter station and connection to the then existing Gathering System. Gatherer may, at its election, but within two (2) years of the initial delivery of production from such Gathering System expansion acquire the ownership of the Gathering System expansion installed by the Producer by reimbursing Producer for the actual cost of the Gathering System expansion with no allowance for inflation or depreciation. In such an event, Producer agrees to execute all assignments or contracts deemed necessary by Gatherer to accomplish the transfer to Gatherer of title to the Gathering System expansion, including rights-of-way and easements. In the event that neither Gatherer nor Producer elects to construct a Gathering System expansion to connect to Gatherer’s Gathering System, this Agreement shall terminate as to the gas from such well or wells and such gas will be deemed released from this Agreement.”

4.A new section 4.6 shall be added as follows:

“Producer agrees to provide Gatherer its forward-looking twelve (12) month drilling program, as updated internally, on a quarterly basis or as often as the parties may mutually agree from time to time, during the term of this Agreement.”

5.Article XII, Section 12.1 is deleted in its entirety and replaced with the following:

“Producer shall pay to Gatherer 46.193 cents ($0.46193) per MMBtu of Gas gathered pursuant to this Agreement; provided with respect to Gas gathered from any Qualifying Well, Producer shall pay 25 cents ($0.25) per MMBtu (as applicable, the Gathering Fee).”

6.Article XII, Section 12.2 is deleted in its entirety and replaced with the following:

“Producer shall pay to Processor 57.74 cents ($0.5774) per MMBtu of Gas processed pursuant to this Agreement; provided with respect to Gas processed from any Qualifying Well, Producer shall pay 35 cents ($0.35) per MMBtu (as applicable, the Processing Fee).”

7.In Article XII, Section 12.3, the first sentence is deleted in its entirety and replaced by the following:

“Producer shall pay to Gatherer the applicable compression fee or fees (the “Compression Fee”), computed by multiplying the MMBtu’s of Producer’s Gas metered at each Gathering System Delivery Point by the compression rate applicable to such Gathering System Delivery Point, which shall be based upon the average monthly operating pressure registered at such Gathering System Delivery Point as more particularly provided and described in Exhibit D, attached hereto and incorporated herein.”

8.Article XII, Section 12.4 is deleted in its entirety and replaced with the following:

“In the event Gas is treated as provided by Section 7.3, Producer shall pay a treating fee (the “Treating Fee”) computed by multiplying 3.65 cents ($0.0365) per mole percent of CO2 in excess of the two percent (2%) specification set forth in Section 7.1d(iii) (based on tests conducted pursuant to Section 8.1), per MMBtu of Gas metered at the applicable Gathering System Delivery Point where such Gas was delivered.”

9.Exhibit B is amended to add the list of wells attached to this Third Amendment under the heading, “Qualifying Well(s).” Further, at such time as new wells drilled become Qualifying Well(s) pursuant to the terms of Section 4.4 as amended herein, Exhibit B will be deemed amended to include such Qualifying Wells(s), and a new Exhibit B evidencing the addition of such new Qualifying Well(s) shall be provided by Gatherer to Producer.

10.Exhibit D is amended to add another heading “Compression Fees for Qualifying Well(s),” and the pressure ranges and fees applicable thereto, as follows:

“Compression Fees for Qualifying Well(s)
Monthly Avg. Psia	Rate/MMBtu
<=69.9	$0.40
79.9-70	$0.32
99.9-80	$0.24
149.9-100	$0.16
299.9-150	$0.08
>300	$0.00''

Except as amended by this Amendment, which shall be effective as of the Fourth Amendment Effective Date, the terms and provisions of the Cowtown Agreement are, and shall remain, in full force and effect.

IN WITNESS WHEREOF, the parties hereto have caused this Fourth Amendment to be duly executed by their respective authorized officers as of the date first written above.

QUICKSILVER RESOURCES INC.
By:	/s/ C.C. Rupnow
	Name: Clifford Rupnow
	Title: VP Product Mktg & Transp.

TG BARNETT RESOURCES LP
By:	/s/ Koji Yoshizaki
	Name: KOJI YOSHIZAKI
	Title: Vice President and Secretary

COWTOWN PIPELINE PARTNERS L.P.
By:	Crestwood Gas Services Operating GP LLC, its general partner
By:	/s/ J. Heath Deneke
	Name: Heath Deneke
	Title: President Natural Gas Business Unit

COWTOWN GAS PROCESSING PARTNERS L.P.
By:	Crestwood Gas Services Operating GP LLC, its general partner
By:	/s/ J. Heath Deneke
	Name: Heath Deneke
	Title: President Natural Gas Business Unit

Exhibit B
Qualifying Well(s)

Well Number	Well Name	TRRC #
1	Station Branch 7	248143
2	Sass 6	237625
3	Yosemite 3	238048
4	Yosemite 5	237968
5	Smelley 2	235679
6	Smelly B 1	237980
7	Lucy 2	228695
8	Charca 3	214659
9	Speed Racer 2	239823
10	Possum Holler 3	233374
11	Possum Holler 4	231905
12	Lafrance 2	215448
13	Goldsmith Hilton 3	237975
14	McPherson 2	241032
15	East Cletus 3	249244
16	Colonel Flagg 5	237638
17	Colonel Flagg 7	239495
18	Ralph Wiggum 14	248883
19	Dugger Hewlitt 9	252129
20	Thelonius Monk 2	237181
21	Branham Keller 2	265735
22	Apu 1	231422
23	Apu 2	231405
24	Carl Carlson 3	232020
25	Waylon Smithers 1	235527
26	Waylon Smithers 2	235462
27	Bob Denver 2	221658
28	Bob Denver 4	231694
29	Parker 1	231397
30	Parker 6	239914
31	Bubbs 6	246881
32	Deborah Lou 5	240196
33	Stewart 3	237667
34	Campos A3	232455

EX-10.4

Exhibit 10.4

THIRD AMENDMENT TO
AMENDED AND RESTATED GAS GATHERING AGREEMENT[Lake Arlington]

This Third Amendment to Amended and Restated Gas Gathering Agreement (the "Third Amendment") is executed August 13, 2012 but dated effective as of July 1, 2012 (the "Amendment Effective Date"), by and between Quicksilver Resources Inc. ("Producer"), and Cowtown Pipeline Partners L.P. (as assignee of Cowtown Pipeline L.P.) ("Gatherer").

WHEREAS, Producer and Gatherer are parties to the Amended and Restated Gas Gathering Agreement, dated as of September 1, 2008, as amended by the First Amendment to Amended and Restated Gas Gathering Agreement [Lake Arlington] dated as of September 29, 2009, and that Second Amendment to Gas Gathering Agreement dated as of October 1, 2010 (together, the "Lake Arlington Agreement");

WHEREAS, the parties desire to amend the terms of the Lake Arlington Agreement as provided in this Third Amendment;

NOW, THEREFORE, in consideration of the mutual premises and benefits contained herein, the adequacy, receipt and sufficiency of which are hereby acknowledged, Producer and Gatherer amend the terms of the Lake Arlington Agreement, as follows:

1. Section 1, Definitions is amended to add the following definition at the end of Section 1.1:

"aa. "Lift Gas Volume" is the amount of Gas reserved under Section 3.2 and used by Producer for gas lift operations in the Contract Area measured at meter station number TXSA119MU Arlington Plant MU and expressed in MMBtus."

2. Sections 11.1 and 11.2 of Section 11, Fees are deleted in their entirety and replaced with the following:

"11.1 Producer shall pay to Gatherer:

(a)sixty-six and 615/1000 cents ($.66615) multiplied by the positive difference between (i) the total volume of Producer's Gas (measured in MMBtus) metered at the Receipt Point(s) and (ii) the Lift Gas Volume (the "Gathering Fee"); and

(b)thirty cents ($.30) per MMBtu multiplied by the Lift Gas Volume (the "Lift Gas Fee").

11.2 On each Escalation Date, the Gathering Fee and Lift Gas Fee will increase by a percentage equal to the CPI Adjustment."

3. The calculation of the Gathering Fee and the Lift Gas Fee shall be reflected in the monthly statement furnished by Gatherer to Producer under Section 12.1 of the Lake Arlington Agreement.

4. Except as amended by this Third Amendment, which shall be effective as of the Amendment Effective Date, the terms and provisions of the Lake Arlington Agreement are and shall remain in full force and effect.

5. Capitalized terms used but not otherwise defined herein shall have the meaning given such terms in the Lake Arlington Agreement.

2

IN WITNESS WHEREOF, the parties hereto have caused this Third Amendment to be duly executed by their respective authorized officers as of the date first written above.

QUICKSILVER RESOURCES INC.
By:	/s/ C.C. Rupnow
	Name: Clifford C. Rupnow
	Title: VP Midstream Devel.

CRESTWOOD PIPELINE PARTNERS L.P.
By:	Crestwood Gas Services Operating GP LLC, its general partner
By:	/s/ Joel D. Moxley
	Name: Joel D. Moxley
	Title: Sr. Vice President and COO

EX-10.5

Exhibit 10.5

Fourth Amendment

To Amended and Restated Gas Gathering Agreement

(Lake Arlington)

This Fourth Amendment to Amended and Restated Gas Gathering Agreement (Lake Arlington) (this “Fourth Amendment”) is made and entered into this 9th day of July, 2014, but effective August 1, 2013 (“Effective Date”), by and among Quicksilver Resources Inc. (“Quicksilver”), TG Barnett Resources LP (“TG”) (Quicksilver and TG may be collectively referred to herein as “Producers”) and Cowtown Pipeline Partners L.P. (“Gatherer”).

Recitals:

Whereas, Quicksilver and Gatherer are the original parties to that certain Amended and Restated Gas Gathering Agreement dated September 1, 2008 (the “Original Agreement”), as amended by: (i) that certain First Amendment to Amended and Restated Gas Gathering Agreement [Lake Arlington] dated September 29, 2009, (ii) that certain Second Amendment to Gas Gathering Agreement dated as of October 1, 2010, and (iii) that certain Third Amendment to Amended and Restated Gas Gathering Agreement [Lake Arlington] executed August 13, 2012, to be effective as of July 1, 2012 (collectively, (i) through (iii) immediately preceding are referred to herein as the “Prior Amendments”; the Original Agreement and the Prior Amendments are referred to herein collectively as the “Agreement”);

Whereas, by virtue of that certain Assignment, Bill of Sale and Conveyance, by and between Quicksilver and TG, dated the 30^th day of April 2013, effective September 1, 2012, TG has been assigned an interest in the Agreement; and

Whereas, Producers and Gatherer desire to amend the Agreement as set forth herein.

Now     therefore, in consideration of the mutual covenants herein, Producers and Gatherer agree as follows:

1. Exhibit “A” to the Agreement (which is physically attached to the Original Agreement) shall be deleted in its entirety and replaced with the Exhibit “A” attached hereto, and by this reference made a part of this Fourth Amendment.

2. A new Exhibit “C” attached hereto is added to the Agreement and by this reference made a part of this Fourth Amendment.

3. Section 1, Definitions of the Agreement is amended by adding the following definitions at the end of Section 1.1:

“bb. ‘Crestwood Offload Point’ means the interconnect between Third Party Gatherer’s central delivery point and Gatherer’s Gathering System, as described

on Exhibit C. With regard to Producers’ Gas produced from the Village Creek Pad, the Crestwood Offload Point is not and will not be deemed to be a Receipt Point on Gatherer’s Gathering System.

cc.    ‘Third Party Delivery Points’ shall mean the points of interconnect between the Third Party Gathering System and a Transporter, which points are described on Exhibit C.

dd.    ‘Third Party Gatherer’ refers to Access Midstream Partner LP.

ee.    ‘Third Party Gatherer’s Gathering System’ refers to the gathering system owned and operated by Third Party Gatherer.

ff.    ‘Third Party Gathering System Fuel’ shall mean that gas or electricity consumed or used in the operation of the Third Party Gatherer’s Gathering System, which includes gas consumed or used in gathering and compressing, or treating gas on the Third Party Gatherer’s Gathering System, but shall not include lost and unaccounted for gas, or gas vented during operations.

gg.    ‘Village Creek Lift Gas’ shall have the meaning set forth in Section 25.5.

hh.    ‘Village Creek Gas Lift Facility’ shall have the meaning set forth in Section 25.5.

ii.    ‘Village Creek Pad’ means Producers’ wells located on the pad depicted on Exhibit A as further described in Section 25.5.

jj.    ‘Village Creek Pad Receipt Point’ shall mean Third Party Gatherer’s meter on the Village Creek Pad, as further described in Section 25.2 and on Exhibit C.

kk.    ‘Village Creek Pad Volume’ shall have the meaning set forth in Section 25.4.”

4. A new Section 25 shall be added to the Agreement as follows, and such Section 25 shall be applicable only to Gas delivered by Producers at the Village Creek Pad:

“Section 25.    Gas Gathering at Village Creek Pad

25.1Use of Third Party Gatherer. Producers acknowledge and agree that Gatherer may cause the gathering of Gas from the Village Creek Pad by Third Party Gatherer at the Village Creek Pad Receipt Point pursuant to a separate gathering agreement between Gatherer and Third Party Gatherer for delivery of such Gas to a Third Party Delivery Point as follows: On a daily basis, the first

Fourth Amendment to Amended and

Restated Gas Gathering Agreement (Lake Arlington)                        

2 of 9

15,000 MMBtu’s of Gas produced from the Village Creek Pad will be delivered to the Crestwood Offload Point; the remainder of the Gas produced from the Village Creek Pad may be delivered to any Third Party Delivery Point at the Producer’s direction and discretion. In addition, if the total quantity of all gas, inclusive of third party gas, delivered to the Crestwood Offload Point exceeds 15,000 MMBtu’s per day (“Excess Quantity”), Gatherer shall cause Producer’s portion of the Excess Quantity to be delivered to any Third Party Delivery Point, for no additional fee, at the Producer’s direction and discretion.

25.2Village Creek Pad Receipt Point. The receipt point for the wells on the Village Creek Pad will be the Third Party Gatherer’s meter number 22421 located on the Village Creek Pad.

25.3    Quality of Gas. The quality of the Gas delivered by Producers to the Village Creek Pad Receipt Point shall comply with those specifications and conditions as provided in Section 7 of the Agreement, and specifically Section 7.1, provided in the event of any conflict of quality specifications with downstream transporters, the more stringent or restrictive specifications shall be satisfied.

Producers shall be responsible for reimbursing Gatherer for the actual reasonable cost incurred by Third Party Gatherer for the cost of handling and disposal of associated saltwater and other liquids not meeting the applicable specifications and conditions as provided above, if Producers deliver such liquids into the Third Party Gathering System.

Producers warrant that, with respect to the Gas, they have, to the knowledge of each, complied with the terms and conditions of the Agreement with Gatherer, and that the Producers’ Gas to be delivered at the Village Creek Pad will comply with all applicable laws, rules and regulations.

25.4    Allocation of Gains, Fuel, Loss, and Electrical Power. The following calculations shall be used in lieu of Section 10 to allocate Gain, Fuel, Loss, and Electrical Power to the Village Creek Pad:

a. Gatherer’s Allocation of Gain, Fuel, Loss, and Electric Power incurred on Gatherer’s Gathering system (measured in MMBtu’s):

The quantity of Gas attributable to the Village Creek Pad Receipt Point for purposes of allocating Gain, Fuel and Loss on Gatherer’s Gathering System shall be calculated as follows: volume of Gas at Village Creek Pad Receipt Point, less any volume nominated by Producers for delivery to a Third Party Delivery Point other than the Crestwood Offload Point, less any Gain, Fuel, or Loss allocated to

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Restated Gas Gathering Agreement (Lake Arlington)                        

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Producers on the Third Party Gatherer’s Gathering System (the “Village Creek Pad Volume”). This Village Creek Pad Volume shall be multiplied by (1.), (2.), or (3.) below to derive the respective allocation for each:

1. Percentage of Gathering System Gain/Loss:

[Sum of Total Delivered Quantities, less (the sum of all gas delivered at all Receipt Points, less Gathering System Fuel, less quantities of any Gathering System Gas Lift), divided by the sum of all gas delivered at all Receipt Points;

e.g.     a – ( b – c – d)

b.

2. Percentage of Gathering System Fuel:

Fuel utilized or consumed by the Gathering System divided by the sum of all gas delivered at all Receipt Points.

3. Gathering System Electrical Power (in Dollars):

The total dollar amount paid for such Electrical Power divided by the sum of all gas delivered at all Receipt Points on the Gathering System.

b. Third Party GathererAllocation of Gain, Fuel, Loss incurred on Third Party Gatherer’s Gathering System (measured in MMBtu’s):

1. When all of Producers’ Gas delivered into the Village Creek Pad Receipt Point is nominated for delivery to the Crestwood Offload Point:

a. Allocation of Gathering System Gain/Loss :

Third Party Gatherer’s Gain/Loss incurred on the Third Party Gatherer’s Gathering System that is attributable to Producers’ Gas shall be passed through to the Producers.

b. Percentage of Fuel:

No Third Party Gathering System Fuel shall be passed through or allocated to the Producers.

Fourth Amendment to Amended and

Restated Gas Gathering Agreement (Lake Arlington)                        

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2. When Producers’ Gas delivered into the Village Creek Pad Receipt Point is nominated for delivery to other Third Party Delivery Points as well as to the Crestwood Offload Point:

a. Allocation of Gathering System Gain/Loss :

All Third Party’s Gain/Loss incurred on the Third Party Gatherer’s Gathering System shall be passed through to the Producers.

b. Percentage of Fuel:

Fuel incurred on the Third Party Gatherer’s Gathering System in the delivery of Producers’ Gas to Third Party Delivery Points other than the Crestwood Offload Point shall be passed through to the Producers.

25.5 Gas Lift at Village Creek Pad.

a. In the event that Producers request Gas for gas lift for:

(i) the following wells (collectively, the “Existing Village Creek Wells”):

(1)Village Creek 8H

(2) Village Creek 10H

(3) Village Creek 12H, or

(ii) any future well situated on the Village Creek Pad,

Gatherer shall promptly install (or cause to be installed) all equipment at the Village Creek Pad necessary to provide gas lift Gas to the wells situated on the Village Creek Pad (collectively, the “Village Creek Gas Lift Facility”), which may include but is not limited to a meter station, over pressure protection valve and device, electronic flow meter, radio communication, SCADA and appurtenant valves and appropriate piping and tubing. Producers agree to reimburse Gatherer for all actual costs, upon invoice, incurred by Gatherer for the installation of the Village Creek Gas Lift Facility. Following installation, the Village Creek Gas Lift Facility shall become a part of the Third Party Gatherer’s Gathering System.

Fourth Amendment to Amended and

Restated Gas Gathering Agreement (Lake Arlington)                        

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b. Gatherer will make available (or cause to be made available) to Producers at the Village Creek Gas Lift Facility a quantity of Gas to be used by Producers as field use gas for all present and future wells situated on the Village Creek Pad (as permitted by Section 3.2 of the Agreement). Such field use quantities made available to Producers (“Village Creek Lift Gas”) shall be subtracted from the quantities of Gas delivered by Gatherer at the Third Party Delivery Point(s). In the event that the quantities of Village Creek Lift Gas made available to Producers during a given Month exceed the total quantities of Gas delivered for Producers at the Third Party Delivery Point(s) for the given month and the following two (2) Months (the “Un-Replaced Quantities”), then Producers shall purchase upon invoice the Un-Replaced Quantities ($ per MMBtu) at the monthly average of the daily Platts Gas Daily survey “Midpoint Average” for the “Waha” index price plus ten cents ($0.10), in effect for the Month such Village Creek Lift Gas was delivered by Gatherer or its designee to Producers at the Village Creek Gas Lift Facility. Any amount owed to Gatherer for such Un-Replaced Quantities shall be paid to Gatherer by Producers within thirty (30) days of receipt of invoice from Gatherer.

c. Notwithstanding any other provision of the Agreement to the contrary: (i) no Lift Gas Fee shall apply to the Village Creek Lift Gas and (ii) the Lift Gas Volume of the Village Creek Lift Gas shall be measured at Third Party Gatherer’s meter number 22422.”

5.    Gatherer agrees that the rights afforded Producers pursuant to Sections 12.2 and 12.5 (examination of books and records, and record retention) shall include all such books, records, charts and data which Gatherer is entitled to examine, obtain or receive from Third Party Gatherer relating to Producers’ Gas from the Village Creek Pad.

6.    Producers and Gatherer agree that notwithstanding any other provision of the Agreement, this Fourth Amendment shall terminate at the same time that Gatherer’s agreement with the Third Party Gatherer, with respect to the matters herein, terminates for any reason, and Gatherer shall execute and deliver to Producers a written release of Producers Gas’ from the Agreement.     

This Fourth Amendment contains the entire understanding of the Parties hereto with respect to the matters addressed herein. As amended by this Fourth Amendment, the terms, conditions, and covenants of the Agreement shall continue in full force and effect in accordance with their respective terms. Capitalized terms used but not otherwise defined herein shall have the meaning given such terms in the Agreement as amended by this Fourth Amendment.

Fourth Amendment to Amended and

Restated Gas Gathering Agreement (Lake Arlington)                        

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This Fourth Amendment may be executed in three or more counterparts, each of which shall be deemed an original, and which together shall constitute but one and the same instrument.    

IN WITNESS WHEREOF, the Parties hereto have executed and delivered this Fourth Amendment as of the date first written above.

Quicksilver Resources Inc.
By:	/s/ C.C. Rupnow
	Name: Cliff Rupnow
	Title: Vice President - Product Marketing & Transportation

TG Barnett Resources LP
By:	/s/ Koji Yoshizaki
	Name: KOJI YOSHIZAKI
	Title: Vice President and Secretary

Gatherer:
Cowtown Pipeline Partners L.P.
By:	Crestwood Gas Services Operating GP LLC, its general partner
By:	/s/ J. Heath Deneke
	Name: Heath Deneke
	Title: President Natural Gas Business Unit

Fourth Amendment to Amended and

Restated Gas Gathering Agreement (Lake Arlington)                        

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Amended Exhibit A

Dated Effective August 1, 2013

to the

Amended and Restated Gas Gathering Agreement

Contract Area

Lands located in Tarrant County, Texas depicted on the following attached plats, consisting of 2 pages, the second of which shows a portion of the Contract Area to include those areas of land within the boundaries of the red solid lines.

Fourth Amendment to Amended and

Restated Gas Gathering Agreement (Lake Arlington)                        

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Exhibit C
Dated Effective August 1, 2013
to the
Amended and Restated Gas Gathering Agreement

Third Party Gatherer’s Receipt Point

Village Creek Pad Access Meter #22421

Third Party Delivery Point(s)

Delivery Point	Description	Meter
Crestwood Offload Point	Offload point between Third Party Gatherer and Gatherer’s Gathering System	TX20542
ETC Delivery Point	Mercado ETC Del	OMV10115
ETC Delivery Point	4th Street ETC Del	OMV10271
ETC Delivery Point	Delga ETC Del	OMV10107

Fourth Amendment to Amended and

Restated Gas Gathering Agreement (Lake Arlington)                        

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EX-10.6

Exhibit 10.6

Fifth Amendment

To Amended and Restated Gas Gathering Agreement

(Lake Arlington)

This Fifth Amendment to the Amended and Restated Gas Gathering Agreement (Lake Arlington) (this “Fifth Amendment”) is made and entered into this July 9, 2014, but effective June 1, 2014 (“Effective Date”), by and among Quicksilver Resources Inc. (“Quicksilver”), and TG Barnett Resources LP (“TG”) (Quicksilver and TG are collectively referred to herein as “Producer”), and Cowtown Pipeline Partners L.P. (“Gatherer”).

Recitals:

Whereas, Quicksilver and Gatherer are parties to that certain Amended and Restated Gas Gathering Agreement dated September 1, 2008 (the “Original Agreement”), as amended by: (i) that certain First Amendment to Amended and Restated Gas Gathering Agreement [Lake Arlington] dated September 29, 2009, (ii) that certain Second Amendment to Gas Gathering Agreement dated as of October 1, 2010, (iii) that certain Third Amendment to Amended and Restated Gas Gathering Agreement [Lake Arlington] executed August 13, 2012, but to be effective as of July 1, 2012, and (iv) that certain Fourth Amendment to Amended and Restated Gas Gathering Agreement [Lake Arlington] executed July 9, 2014 between Producer and Gatherer, but to be effective as of August 1, 2013 (collectively. the “Lake Arlington Agreement”);

NOW, THEREFORE, in consideration of the mutual premises and benefits contained herein, the adequacy, receipt and sufficiency of which are hereby acknowledged, Producer and Gatherer amend the terms of the Lake Arlington Agreement, as follows:

1. Article 1, Definitions is amended as follows:

Section i, “Escalation Date” shall be deleted in its entirety and the following substituted in its place: “i. “Escalation Date”, except for the Gas Lift Fee, shall mean January 1^st following the Effective Date and each January 1st thereafter during the Term. The Escalation Date for the Lift Gas Fee shall mean January 1, 2016 and each January 1^st thereafter during the Term.

2. Article 11, Fees is amended as follows:

Section 11.1    (b) is amended by deleting the words “thirty cents ($.30)” and the following words substituted in their place: “twenty cents ($.20)”.

3. Article 11, Fees shall be amended by adding the following:

“11.3 For the period beginning on July 1, 2014 and ending on June 30, 2016, Gatherer shall work with Producer to evaluate the purchase of all or a portion of Producer’s existing and future gas lift systems at Lake Arlington. Regardless of whether the parties are able to reach a mutual agreement as to such potential purchase(s), Gatherer shall

have the Exclusive Right to provide Producer’s gas lift needs for the remaining Term of the Lake Arlington Agreement. As used herein, the term “Exclusive Right” is defined to mean that (i) Gatherer shall be the exclusive provider of gas lift services to Producer at the existing and any future points delivered into Producer’s existing and future gas lift systems, and (ii) Producer shall negotiate with no other party and deal exclusively with Gatherer to potentially provide any alternative gas lift method which could eliminate or materially alter the then existing manner in which Gatherer supplies lift gas to Producer at existing and future wells. This Exclusive Right is not intended to hinder Producer from alternative non gas lift methods (including, but not limited to, plungers or other similar lifting technologies) at any individual well (including each such well for which there is no gas lift pipeline connection as of the date hereof), where such lift gas being provided or to be provided, as applicable, by Gatherer is not or will not be adequate at such particular well to provide Producer’s lift requirements. Producer shall retain sole discretion in the deployment of these alternative non gas lift techniques; provided in the event that Producer employs such artificial non gas lift techniques on a well, it will notify Gatherer within a commercially reasonable time frame.

Except as amended by this Fifth Amendment, which shall be effective as of the Effective Date of this Fifth Amendment, the terms and provisions of the Lake Arlington Agreement are and shall remain in full force and effect.

Capitalized terms used but not otherwise defined herein shall have the meaning given such terms in the Lake Arlington Agreement.

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IN WITNESS WHEREOF, the parties hereto have caused this Fifth Amendment to be duly executed by their respective authorized officers as of the date first written above.

QUICKSILVER RESOURCES INC.
By:	/s/ C.C. Rupnow
	Name: Clifford Rupnow
	Title: VP Product Mktg & Transp.

TG BARNETT RESOURCES LP
By:	/s/ Koji Yoshizaki
	Name: KOJI YOSHIZAKI
	Title: Vice President and Secretary

COWTOWN PIPELINE PARTNERS L.P.
By:	Crestwood Gas Services Operating GP LLC, its general partner
By:	/s/ J. Heath Deneke
	Name: Heath Deneke
	Title: President Natural Gas Business Unit

EX-10.7

Exhibit 10.7

OMNIBUS AMENDMENT NO. 8
TO COMBINED CREDIT AGREEMENTS

THIS OMNIBUS AMENDMENT NO. 8 TO COMBINED CREDIT AGREEMENTS (this “Amendment”), dated as of November 7, 2014,is among QUICKSILVER RESOURCES INC.,(the “U.S. Borrower”), QUICKSILVER RESOURCES CANADA INC., (the “Canadian Borrower”) (collectively, the “Combined Borrowers”), the Guarantors, JPMORGAN CHASE BANK, N.A., as global administrative agent (in such capacity, the “Global Administrative Agent”), JPMORGAN CHASE BANK, N.A., TORONTO BRANCH, as Canadian administrative agent (in such capacity, the “Canadian Administrative Agent” and, together with the Global Administrative Agent, the “Administrative Agents”), and each of the U.S. Lenders and Canadian Lenders party hereto.

R E C I T A L S

A.    The U.S. Borrower, the Global Administrative Agent and the various financial institutions party thereto as Agents or Lenders (the “U.S. Lenders”) entered into that certain Amended and Restated Credit Agreement dated as of December 22, 2011 (as amended by Omnibus Amendment No. 1 dated as of May 23, 2012, Omnibus Amendment No. 2 dated as of August 6, 2012, Omnibus Amendment No. 3 dated as of October 5, 2012, Omnibus Amendment No. 4 dated as of April 30, 2013, Omnibus Amendment No. 5 dated as of June 21, 2013, Omnibus Amendment No. 6 dated as of November 15, 2013, and Omnibus Amendment No. 7 dated as of April 25, 2014, and as further amended, supplemented or modified, the “U.S. Credit Agreement”).

B.    The U.S. Borrower, as parent, the Canadian Borrower, the Canadian Administrative Agent, the Global Administrative Agent, and the various financial institutions party thereto as agents or lenders (the “CanadianLenders”) entered into that certain Amended and Restated Credit Agreement dated as of December 22, 2011 (as amended by Omnibus Amendment No. 1 dated as of May 23, 2012, Omnibus Amendment No. 2 dated as of August 6, 2012, Omnibus Amendment No. 3 dated as of October 5, 2012, Omnibus Amendment No. 4 dated as of April 30, 2013, Omnibus Amendment No. 5 dated as of June 21, 2013, Omnibus Amendment No. 6 dated as of November 15, 2013, and Omnibus Amendment No. 7 dated as of April 25, 2014, and as further amended, supplemented or modified, the “Canadian Credit Agreement”) (the U.S. Credit Agreement and the Canadian Credit Agreement being collectively referred to as the “Combined Credit Agreements”).

C.    The Combined Borrowers have requested that the Required Lenders and the Required U.S. Lenders agree, and the Required Lenders and the Required U.S. Lenders have agreed, to amend and waive certain provisions of the Combined Credit Agreements.

NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given to such term in the U.S. Credit Agreement, as amended by this

Amendment. Unless otherwise indicated, all section references in this Amendment refer to applicable section of the Combined Credit Agreements.

Section 2.Amendments to Combined Credit Agreements.

2.1Amendment to Section 1.02 – Certain Defined Terms of the Combined Credit Agreements.

(a)In the definition of “Consolidated Net Income” in each Combined Credit Agreement:

(i) clause (c) is hereby amended and restated to read as follows:

“(c) any extraordinary gains (or extraordinary losses) during such period;”;

(ii) clause (g) is hereby amended and restated to read as follows:

“(g) any gain (or losses) realized in connection with the asset sales;”; and

(iii) clause (h) is hereby amended to (A) replace the word “and” at the end of clause (h)(iv) with a comma, (B) replace the semi-colon at the end of clause (h)(v) with a comma and (C) add the following new clause (h)(vi):

“(vi) any strategic transactions, asset dispositions or acquisitions or the evaluation thereof or of other transactions, whether or not consummated, which, in each case, are paid in the fiscal year ended December 31, 2015 and are in an aggregate amount not to exceed $7,500,000;”.

2.2Amendments to Section 8.01 — Monthly Financial Reporting Package.

(a)Section 8.01 of the U.S. Credit Agreement is hereby amended by adding the following new Section 8.01(j):

“(j)    Monthly Financial Reporting Package. As soon as available, but in any event within one (1) month and five (5) Business Days after the last day of each month, with delivery commencing December 5, 2014, an internally generated monthly financial reporting package for the Borrower and its Consolidated Subsidiaries, including, but not limited to, an internally prepared cash flow analysis, in each case, in form reasonably satisfactory to the Global Administrative Agent.”

(b)Section 8.01 of the Canadian Credit Agreement is hereby amended by adding the following new Section 8.01(j):

“(j)    Monthly Financial Reporting Package. As soon as available, but in any event within one (1) month and five (5) Business Days after the last day of each month, with delivery commencing December 5, 2014, an internally generated monthly financial reporting package

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for the Parent and its Consolidated Subsidiaries, including, but not limited to, an internally prepared cash flow analysis, in each case, in form reasonably satisfactory to the Global Administrative Agent.”

2.3Amendments to Section 9.01— Financial Covenants.

(a)Section 9.01 of the U.S. Credit Agreement is hereby amended to add the following new Section 9.01(d):

“(d)    EBITDAX Covenant. The Borrower will not, as of the last day of any fiscal quarter set forth below, commencing with the fiscal quarter ending December 31, 2014, permit EBITDAX to be less than the amount set forth opposite such date in the table below:

Fiscal Quarter Ending	Minimum EBITDAX
December 31, 2014	$30,000,000.00
March 31, 2015	$59,000,000.00
June 30, 2015	$87,250,000.00
September 30, 2015	$120,500,000.00
December 31, 2015	$122,000,000.00

provided, that for purposes of calculating the minimum EBITDAX covenant set forth in this Section 9.01(d), for the fiscal quarter ending (i) December 31, 2014, EBITDAX shall be equal to EBITDAX for the most recent full fiscal quarter of the Borrower then ending, (ii) March 31, 2015, EBITDAX shall be equal to EBITDAX for the two most recent full fiscal quarters of the Borrower then ending, (iii) June 30, 2015, EBITDAX shall be equal to EBITDAX for the three most recent full fiscal quarters of the Borrower then ending, (iv) September 30, 2015, EBITDAX shall be equal to EBITDAX for the four most recent full fiscal quarters of the Borrower then ending and (v) December 31, 2015, EBITDAX shall be equal to EBITDAX for the four most recent full fiscal quarters of the Borrower then ending.”

(b)Section 9.01 of the Canadian Credit Agreement is hereby amended to add the following new Section 9.01(d):

“(d)    EBITDAX Covenant. The Parent will not, as of the last day of any fiscal quarter, commencing with the fiscal quarter ending December 31, 2014, permit EBITDAX to be less than the amount set forth opposite such date in the table below:

Fiscal Quarter Ending	Minimum EBITDAX
December 31, 2014	$30,000,000.00
March 31, 2015	$59,000,000.00
June 30, 2015	$87,250,000.00
September 30, 2015	$120,500,000.00
December 31, 2015	$122,000,000.00

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provided, that for purposes of calculating the minimum EBITDAX covenant set forth in this Section 9.01(d), for the fiscal quarter ending (i) December 31, 2014, EBITDAX shall be equal to EBITDAX for the most recent full fiscal quarter of the Parent then ending, (ii) March 31, 2015, EBITDAX shall be equal to EBITDAX for the two most recent full fiscal quarters of the Parent then ending, (iii) June 30, 2015, EBITDAX shall be equal to EBITDAX for the three most recent full fiscal quarters of the Borrower then ending, (iv) September 30, 2015, EBITDAX shall be equal to EBITDAX for the four most recent full fiscal quarters of the Parent then ending and (v) December 31, 2015, EBITDAX shall be equal to EBITDAX for the four most recent full fiscal quarters of the Parent then ending .”

Section 3.Global Borrowing Base Redetermination; Allocation of U.S. Borrowing Base and Canadian Borrowing Base.    The Required Lenders and the Combined Borrowers agree that from and after the Eighth Amendment Effective Date (as defined below), the amount of the Global Borrowing Base shall be $325,000,000 and the amount of the U.S. Borrowing Base shall be $250,000,000, with an Allocated U.S. Borrowing Base of $185,000,000 and an Allocated Canadian Borrowing Base of $140,000,000. This provision does not limit redeterminations of the Global Borrowing Base or the U.S. Borrowing Base, including in accordance with Section 2.07(c) or further adjustments thereto pursuant to Section 8.12(c), Section 9.02(n), Section 9.10(d) or Section 9.10(i) of the Combined Credit Agreements. This Section 3 constitutes a New Borrowing Base Notice in accordance with Section 2.07(d) of the Combined Credit Agreements and a Borrowing Base Allocation Notice in accordance with Section 2.07(e) of the Combined Credit Agreements, in each case, delivered in connection with this second Scheduled Redetermination of the Global Borrowing Base and U.S. Borrowing Base for the 2014 calendar year.

Section 4.Reduction of Aggregate Maximum Credit Amounts.

4.1Pursuant to the Reduction in Aggregate Maximum Credit Amounts Notice dated, April 22, 2014, provided by the Combined Borrowers to the Global Administrative Agent and the Canadian Administrative Agent, the Combined Aggregate Maximum Credit Amount was reduced to $650,000,000, the Aggregate Maximum Credit Amount was reduced to $400,000,000 and the Canadian Aggregate Maximum Credit Amount was reduced to $250,000,000.

4.2Pursuant to, and in accordance with, Section 2.06(b) of each Combined Credit Agreement, the Combined Borrowers hereby notify the Global Administrative Agent and the Canadian Administrative Agent that as of the Eighth Amendment Effective Date (a) the Combined Aggregate Maximum Credit Amount shall be reduced to $450,000,000, (b) the Aggregate Maximum Credit Amount shall be reduced to $275,000,000 and (c) the Canadian Aggregate Maximum Credit Amount shall be reduced to $175,000,000 (each, a “Reduction”). After giving effect to each Reduction, the Combined Borrowers certify that the total Revolving Credit Exposures (as defined in the applicable Combined Credit Agreement as used in this Section) do not exceed the total Commitments (as defined in the applicable Combined Credit Agreement as used in this Section). This Section 4.2 constitutes the notice that the Global Administrative Agent and the Canadian Administrative Agent shall provide to the Lenders pursuant to Section 2.06(b)(ii) of each Combined Credit Agreement.

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Section 5.Waiver Request. The Combined Borrowers hereby request and the Global Administrative Agent, the Canadian Administrative Agent and the Majority Lenders hereby agree to waive compliance with the minimum interest coverage ratio set forth in Section 9.01(a) of the Combined Credit Agreements (the “Interest Coverage Ratio”) for the fiscal quarters ending December 31, 2014, March 31, 2015, June 30, 2015, September 30, 2015 and December 31, 2015 (the “Specified Waiver”) and, for the avoidance of doubt, no Default or Event of Default may arise from any failure to comply with the Interest Coverage Ratio for the fiscal quarters then ending. The Specified Waiver shall not be a waiver by the Global Administrative Agent, the Canadian Administrative Agent, the U.S. Lenders or the Canadian Lenders of any other defaults which may exist or which may occur in the future under the Combined Credit Agreements and/or the other Loan Documents (as defined in the applicable Combined Credit Agreement, as used in this Section 4) (collectively, “Other Violations”). Similarly, nothing contained in this Amendment shall directly or indirectly in any way whatsoever: (i) impair, prejudice or otherwise adversely affect the Global Administrative Agents’, the Canadian Administrative Agents’, the U.S. Lenders’ or the Canadian Lenders’ right at any time to exercise any right, privilege or remedy in connection with the Loan Documents with respect to any Other Violations, (ii) amend or alter any provision of the Combined Credit Agreements, the other Loan Documents, or any other contract or instrument except as expressly set forth in this Amendment, or (iii) constitute any course of dealing or other basis for altering any obligation of the Combined Borrowers or any right, privilege or remedy of the Global Administrative Agent, the Canadian Administrative Agent, the U.S. Lenders or the Canadian Lenders under the Combined Credit Agreements, the other Loan Documents, or any other contract or instrument. Nothing in this Amendment shall be construed to be a consent or waiver by the Global Administrative Agent, the Canadian Administrative Agent, the U.S. Lenders or the Canadian Lenders to any Other Violations.

Section 6.Conditions Precedent.

6.1This Amendment shall not become effective until the date on which each of the following conditions is satisfied (the “Eighth Amendment Effective Date”):

(a)The Global Administrative Agent shall have received from each of the Combined Borrowers, the Guarantors, the U.S. Required Lenders, the Required Lenders, the Global Administrative Agent and the Canadian Administrative Agent counterparts of this Amendment signed on behalf of each such Person.

(b)The Combined Borrowers shall have paid all amounts due and payable in connection with this Amendment on or prior to the Eighth Amendment Effective Date, including (i) to the extent invoiced at least one (1) Business Day prior to such date, all documented out-of-pocket expenses required to be reimbursed or paid by the Combined Borrowers under the Combined Credit Agreements and (ii) all consent fees owing under the Consent Fee Letter dated the date hereof between the U.S. Borrower and the Global Administrative Agent.

Section 7.Miscellaneous.

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7.1Confirmation. All of the terms and provisions of the Combined Credit Agreements, as amended by this Amendment, are, and shall remain, in full force and effect following the effectiveness of this Amendment.

7.2Ratification and Affirmation; Representations and Warranties. Each Combined Borrower hereby (a) acknowledges the terms of this Amendment; (b) ratifies and affirms its obligations under, and acknowledges, renews and extends its continued liability under, each Loan Document (as defined in the applicable Combined Credit Agreement as used in this Section) to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect, except as expressly amended hereby, notwithstanding the amendments contained herein; and (c) represents and warrants to the Lenders (as defined in the applicable Combined Credit Agreement) that as of the date hereof, after giving effect to the terms of this Amendment: (i) all of the representations and warranties contained in each Loan Document to which it is a party are true and correct in all material respects on and as of the Eighth Amendment Effective Date, except that to the extent any such representations and warranties are (x) expressly limited to an earlier date, in which case, on the Eight Amendment Effective Date such representations and warranties shall continue to be true and correct as of such specified earlier date and (y) qualified by materiality, such representations and warranties (as so qualified) shall continue to be true and correct in all respects and (ii) no Default (as defined in the applicable Combined Credit Agreement) has occurred and is continuing as of the Eighth Amendment Effective Date. Each Guarantor (as defined in the applicable Combined Credit Agreement) (i) acknowledges the terms of this Amendment and (ii) ratifies and affirms (A) its respective obligations under the Loan Documents to which it is a party (including its guarantee obligations under the applicable Guaranty Agreement (as defined in the applicable Combined Credit Agreement) to which it is a party as amended hereby), all of which shall continue in full force and effect and (B) that the Liens created by the Loan Documents to which it is a party are valid and continuing and secure the Secured Indebtedness or Canadian Secured Indebtedness, as the case may be, in accordance with the terms thereof, in each case, after giving effect to this Amendment. This Amendment is a Loan Document.

7.3Counterparts. This Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed counterpart by facsimile or electronic mail shall be effective as delivery of a manually executed counterpart hereof.

7.4Governing Law, Jurisdiction, etc. Sections 12.09 and 12.18 of the Canadian Credit Agreement shall be incorporated herein mutatis mutandis as this Amendment relates to the Canadian Credit Agreement and Sections 12.09 and 12.18 of the U.S. Credit Agreement shall be incorporated herein mutatis mutandis as this Amendment relates to the U.S. Credit Agreement.

[SIGNATURES BEGIN NEXT PAGE]

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IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the date first written above.

QUICKSILVER RESOURCES INC., a Delaware corporation

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

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

QUICKSILVER RESOURCES CANADA INC., an Alberta, Canada corporation

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

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

With respect to Section 7 hereof:

COWTOWN PIPELINE MANAGEMENT, INC., a Texas corporation

By: /s/ Glenn Darden

        Name: Glenn Darden

        Title: President and Chief Executive Officer

COWTOWN PIPELINE FUNDING, INC., a Delaware corporation

By: /s/ Glenn Darden

        Name: Glenn Darden

        Title: President and Chief Executive Officer

COWTOWN GAS PROCESSING L.P., a Texas limited partnership

By: Cowtown Pipeline Management, Inc., its general partner

By: /s/ Glenn Darden

        Name: Glenn Darden

        Title: President and Chief Executive Officer

COWTOWN PIPELINE L.P., a Texas limited partnership

By: Cowtown Pipeline Management, Inc., its general partner

By: /s/ Glenn Darden

        Name: Glenn Darden

        Title: President and Chief Executive Officer

BARNETT SHALE OPERATING, LLC., a Delaware limited liability company

By: /s/ Glenn Darden

        Name: Glenn Darden

        Title: President and Chief Executive Officer

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

SILVER STREAM PIPELINE COMPANY LLC., a Delaware limited liability company

By: /s/ Glenn Darden

        Name: Glenn Darden

        Title: President and Chief Executive Officer

QPP HOLDINGS LLC, a Delaware limited liability company

By: /s/ Glenn Darden

        Name: Glenn Darden

        Title: President and Chief Executive Officer

QPP PARENT LLC, a Delaware limited liability company

By: Quicksilver Resources Inc., its sole member

By: /s/ Glenn Darden

        Name: Glenn Darden

        Title: President and Chief Executive Officer

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

JPMORGAN CHASE BANK, N.A., as a Lender under the U.S. Credit Agreement, as Global Administrative Agent

By: /s/ Patricia S. Carpen    
Name: Patricia S. Carpen
Title: Senior Asset Manager

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

JPMORGAN CHASE BANK, N.A., TORONTO BRANCH, as a Lender under the Canadian Credit Agreement and as Canadian Administrative Agent

By: /s/ Steve Voigt    
Name: Steve Voigt
Title: Senior Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

BANK OF AMERICA, N.A., as a Lender under the U.S. Credit Agreement

By: /s/ John W. Woodiel III    
Name: John W. Woodiel III    
Title: Managing Director    

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

BANK OF AMERICA, N.A., (by its Canada Branch) as a Lender under the Canadian Credit Agreement

By: /s/ Sylwia Durkiewicz    
Name: Sylwia Durkiewicz    
Title: Vice President    

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

BRANCH BANKING & TRUST COMPANY, as a Lender under the U.S. Credit Agreement and the Canadian Credit Agreement

By: /s/ Ryan Aman    
Name: Ryan Aman    
Title: Vice President    

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

CANADIAN IMPERIAL BANK OF COMMERCE, as a Lender under the Canadian Credit Agreement

By: /s/ E. Lindsay Gordon    
Name: E. Lindsay Gordon
Title: Canadian Imperial Bank of Commerce
Executive Director    

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK BRANCH, as a Lender under the U.S. Credit Agreement

By: /s/ E. Lindsay Gordon    Name: E. Lindsay Gordon
Title: Canadian Imperial Bank of Commerce
Executive Director    

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

CITIBANK, N.A., as a Lender under the U.S. Credit Agreement

By: /s/ Eamon Baqui        
Name: Eamon Baqui
Title: Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

CITIBANK, N.A., CANADIAN BRANCH, as a Lender under the Canadian Credit Agreement

By: /s/ Jonathan Cain    
Name: Jonathan Cain    
Title: Authorized Signatory    

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

COMERICA BANK, as a Lender under the U.S. Credit Agreement

By: /s/ Brandon M. White        
Name: Brandon M. White
Title: Assistant Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

COMERICA BANK, CANADA BRANCH, as a Lender under the Canadian Credit Agreement

By: /s/ Prashant Prakash        
Name: Prashant Prakash
Title: AVP & Portfolio Risk Manager

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

COMPASS BANK, as a Lender under the U.S. Credit Agreement

By: /s/ Blake Kirshman        
Name: Blake Kirshman
Title: Senior Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK, as a Lender under the U.S. Credit Agreement and the Canadian Credit Agreement

By: /s/ Sharada Manne        
Name: Sharada Manne
Title: Managing Director

By: /s/ Michael Willis        
Name: Michael Willis
Title: Managing Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH, as a Lender under the U.S. Credit Agreement

By: /s/ Nupur Kumar        
Name: Nupur Kumar
Title: Authorized Signatory

By: /s/ Samuel Miller        
Name: Samuel Miller
Title: Authorized Signatory

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

CREDIT SUISSE AG, TORONTO BRANCH, as a Lender under the Canadian Credit Agreement

By: /s/ Alain Daoust        
Name: Alain Daoust
Title: Authorized signatory

By: /s/ Nicholas Lam    
Name: Nicholas Lam    
Title: Authorized signatory    

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

DEUTSCHE BANK TRUST COMPANY AMERICAS, as a Lender under the U.S. Credit Agreement

By: /s/ Benjamin Souh        
Name: Benjamin Souh
Title: Vice President

By: /s/ Kelvin Ji        
Name: Kelvin Ji
Title: Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

DEUTSCHE BANK AG CANADA BRANCH, as a Lender under the Canadian Credit Agreement

By: /s/ Paul Uffelmann        
Name: Paul Uffelmann
Title: Vice President

By: /s/ Scott Lampard    
Name: Scott Lampard    
Title: Chief Country Officer    

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

EXPORT DEVELOPMENT CANADA, as a Lender under the U.S. Credit Agreement

By: /s/ Trevor Mulligan        
Name: Trevor Mulligan
Title: Asset Manager

By: /s/ Talal M. Kairouz        
Name: Talal M. Kairouz
Title: Senior Asset Manager

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

GOLDMAN SACHS BANK USA, as a Lender under the U.S. Credit Agreement

By: /s/ Michelle Latzoni        
Name: Michelle Latzoni
Title: Authorized Signatory

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

KEYBANK, N.A., as a Lender under the U.S. Credit Agreement

By: /s/ Stephen J Jones        
Name: Stephen J Jones
Title: Senior Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

SUMITOMO MITSUI BANKING CORPORATION, as a Lender under the U.S. Credit Agreement

By: /s/ Akira Ando        
Name: Akira Ando
Title: Managing Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

THE BANK OF NOVA SCOTIA, as a Lender under the U.S. Credit Agreement and the Canadian Credit Agreement

By: /s/ Alan Dawson    
Name: Alan Dawson    
Title: Director    

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

THE ROYAL BANK OF SCOTLAND PLC, as a Lender under the U.S. Credit Agreement

By: /s/ David W. Stack        
Name: David W. Stack
Title: Senior Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

THE ROYAL BANK OF SCOTLAND PLC, CANADA BRANCH, as a Lender under the Canadian Credit Agreement

By: /s/ David W. Stack        
Name: David W. Stack
Title: Authorized Signatory

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

TORONTO DOMINION (NEW YORK) LLC, as a Lender under the U.S. Credit Agreement

By: /s/ Marie Fernandes        
Name: Marie Fernandes
Title: Authorized Signatory

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

THE TORONTO-DOMINION BANK, as a Lender under the Canadian Credit Agreement

By: /s/ Marie Fernandes    
Name: Marie Fernandes    
Title: Authorized Signatory    

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

U.S. BANK NATIONAL ASSOCIATION, as a Lender under the U.S. Credit Agreement

By: /s/ Christopher D. Zumberge        
Name: Christopher D. Zumberge
Title: Senior Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

UBS AG, STAMFORD BRANCH, as a Lender under the U.S. Credit Agreement

By: /s/ Lana Gifas        
Name: Lana Gifas
Title: Director

By: /s/ Jennifer Anderson        
Name: Jennifer Anderson
Title: Associate Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

UBS AG CANADA BRANCH, as a Lender under the Canadian Credit Agreement

By: /s/ Lana Gifas        
Name: Lana Gifas
Title: Director

By: /s/ Jennifer Anderson        
Name: Jennifer Anderson
Title: Associate Director

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

WELLS FARGO BANK, N.A., as a Lender under the U.S. Credit Agreement

By: /s/ Trent J. Brendon        
Name: Trent J. Brendon
Title: Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

WELLS FARGO FINANCIAL CORPORATION CANADA, as a Lender under the Canadian Credit Agreement

By: /s/ Jeahnette Cavaliere    
Name: Jeahnette Cavaliere    
Title: Vice President

SIGNATURE PAGE TO OMNIBUS AMENDMENT NO. 8 TO

COMBINED CREDIT AGREEMENTS

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Glenn Darden, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Quicksilver Resources Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 10, 2014

/s/ Glenn Darden

Glenn Darden

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, John C. Regan, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Quicksilver Resources Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 10, 2014

/s/ John C. Regan

John C. Regan

Senior Vice President – Chief Financial Officer

(Principal Financial and Accounting Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, in connection with the Quarterly Report on Form 10-Q of Quicksilver Resources Inc. (the “Company”) for the quarter ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, John C. Regan, Senior Vice President – Chief Financial Officer (Principal Financial and Accounting Officer) of the Company, and Glenn Darden, President and Chief Executive Officer of the Company, each certifies that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Report.

Date: November 10, 2014

By:	/s/ John C. Regan	By:	/s/ Glenn Darden
	John C. Regan		Glenn Darden
	Senior Vice President – Chief Financial Officer		President and Chief Executive Officer
	(Principal Financial and Accounting Officer)

XML

Property, Plant And Equipment (Schedule Of Property, Plant And Equipment) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Subject to depletion	$ 5,635,307		$ 5,635,307		$ 5,687,557
Unevaluated costs	218,398		218,398		221,605
Accumulated depletion	(5,245,133)		(5,245,133)		(5,268,719)
Net oil and gas properties	608,572		608,572		640,443
Pipelines and processing facilities	332,710		332,710		347,093
General properties	71,049		71,049		72,125
Accumulated depreciation	(199,851)		(199,851)		(198,856)
Net other property and equipment	203,908		203,908		220,362
Property, plant and equipment, net of accumulated depletion and depreciation	812,480		812,480		860,805
Impairment of Oil and Gas Properties	135	0	135	0
Midstream [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depletion and depreciation	89,362		89,362		97,118
Impairment of Oil and Gas Properties	135		135
Property, Plant and Equipment, Other Types [Member] | Midstream [Member]
Property, Plant and Equipment [Line Items]
Impairment of Oil and Gas Properties			$ 100

XML

Condensed Consolidating Financial Information (Schedule of Condensed Consolidated Statements of Cash Flows) (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Schedule of Equity Method Investments [Line Items]
Net cash flow provided (used) by operating activities	$ (4,983)	$ (81,103)
Purchases of property, plant and equipment	(111,444)	(78,549)
Investment in subsidiary	0
Proceeds from sale of properties and equipment	1,942	2,994
Payments to acquire marketable securities	(55,890)	(142,823)
Proceeds from Sale and Maturity of Marketable Securities	222,025	13,178
Net cash used by investing activities	152,220	300,515
Issuance of debt	243,184	1,173,306
Repayments of debt	(193,689)	(1,308,382)
Debt issuance costs	(225)	(25,868)
Intercompany note	0	0
Intercompany financing	0
Contribution received	0
Distribution of Fortune Creek Partnership funds	(37,113)	(8,079)
Purchase of treasury stock	(2,388)	(1,472)
Net cash flow provided (used) by financing activities	9,769	(170,495)
Effect of exchange rates on cash	2,216	2,610
Net increase (decrease) in cash and equivalents	159,222	51,527
Cash and cash equivalents at beginning of period	89,103	4,951
Cash and cash equivalents at end of period	248,325	56,478
Quicksilver Resources Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Net cash flow provided (used) by operating activities	(39,474)	(113,029)
Purchases of property, plant and equipment	(88,119)	(53,291)
Investment in subsidiary	(1,246)
Proceeds from sale of properties and equipment	1,445	2,977
Payments to acquire marketable securities	(55,890)	(142,823)
Proceeds from Sale and Maturity of Marketable Securities	222,025	13,178
Net cash used by investing activities	173,802	325,756
Issuance of debt	174,000	1,170,266
Repayments of debt	(138,651)	(1,157,969)
Debt issuance costs	(225)	(25,868)
Intercompany note	(22,558)	(147,103)
Intercompany financing	0
Contribution received	0
Distribution of Fortune Creek Partnership funds	0	0
Purchase of treasury stock	(2,388)	(1,472)
Net cash flow provided (used) by financing activities	10,178	(162,146)
Effect of exchange rates on cash	0	0
Net increase (decrease) in cash and equivalents	144,506	50,581
Cash and cash equivalents at beginning of period	83,893	4,618
Cash and cash equivalents at end of period	228,399	55,199
Restricted Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Net cash flow provided (used) by operating activities	(688)	(19)
Purchases of property, plant and equipment	(57)	19
Investment in subsidiary	0
Proceeds from sale of properties and equipment	0	0
Payments to acquire marketable securities	0	0
Proceeds from Sale and Maturity of Marketable Securities	0	0
Net cash used by investing activities	(57)	19
Issuance of debt	0	0
Repayments of debt	0	0
Debt issuance costs	0	0
Intercompany note	0	0
Intercompany financing	745
Contribution received	0
Distribution of Fortune Creek Partnership funds	0	0
Purchase of treasury stock	0	0
Net cash flow provided (used) by financing activities	745	0
Effect of exchange rates on cash	0	0
Net increase (decrease) in cash and equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Restricted Non-Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Net cash flow provided (used) by operating activities	28,843	25,517
Purchases of property, plant and equipment	(23,247)	(24,752)
Investment in subsidiary	(26,395)
Proceeds from sale of properties and equipment	497	17
Payments to acquire marketable securities	0	0
Proceeds from Sale and Maturity of Marketable Securities	0	0
Net cash used by investing activities	(49,145)	(24,735)
Issuance of debt	69,184	3,040
Repayments of debt	(55,038)	(150,413)
Debt issuance costs	0	0
Intercompany note	22,558	147,103
Intercompany financing	501
Contribution received	0
Distribution of Fortune Creek Partnership funds	0	0
Purchase of treasury stock	0	0
Net cash flow provided (used) by financing activities	37,205	(270)
Effect of exchange rates on cash	(2,718)	(512)
Net increase (decrease) in cash and equivalents	14,185	0
Cash and cash equivalents at beginning of period	4,135	0
Cash and cash equivalents at end of period	18,320	0
Restricted Subsidiary Eliminations [Member]
Schedule of Equity Method Investments [Line Items]
Net cash flow provided (used) by operating activities	0
Purchases of property, plant and equipment	0
Investment in subsidiary	1,246
Proceeds from sale of properties and equipment	0
Payments to acquire marketable securities	0
Proceeds from Sale and Maturity of Marketable Securities	0
Net cash used by investing activities	1,246
Issuance of debt	0
Repayments of debt	0
Debt issuance costs	0
Intercompany note	0
Intercompany financing	(1,246)
Contribution received	0
Distribution of Fortune Creek Partnership funds	0
Purchase of treasury stock	0
Net cash flow provided (used) by financing activities	(1,246)
Effect of exchange rates on cash	0
Net increase (decrease) in cash and equivalents	0
Cash and cash equivalents at beginning of period	0
Cash and cash equivalents at end of period	0
Quicksilver And Restricted Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Net cash flow provided (used) by operating activities	(11,319)	(87,531)
Purchases of property, plant and equipment	(111,423)	(78,024)
Investment in subsidiary	(26,395)
Proceeds from sale of properties and equipment	1,942	2,994
Payments to acquire marketable securities	(55,890)	(142,823)
Proceeds from Sale and Maturity of Marketable Securities	222,025	13,178
Net cash used by investing activities	125,846	301,040
Issuance of debt	243,184	1,173,306
Repayments of debt	(193,689)	(1,308,382)
Debt issuance costs	(225)	(25,868)
Intercompany note	0	0
Intercompany financing	0
Contribution received	0
Distribution of Fortune Creek Partnership funds	0	0
Purchase of treasury stock	(2,388)	(1,472)
Net cash flow provided (used) by financing activities	46,882	(162,416)
Effect of exchange rates on cash	(2,718)	(512)
Net increase (decrease) in cash and equivalents	158,691	50,581
Cash and cash equivalents at beginning of period	88,028	4,618
Cash and cash equivalents at end of period	246,719	55,199
Unrestricted Non-Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Net cash flow provided (used) by operating activities	0	0
Purchases of property, plant and equipment	0	0
Investment in subsidiary	(26,395)
Proceeds from sale of properties and equipment	0	0
Payments to acquire marketable securities	0	0
Proceeds from Sale and Maturity of Marketable Securities	0	0
Net cash used by investing activities	(26,395)	0
Issuance of debt	0	0
Repayments of debt	0	0
Debt issuance costs	0	0
Intercompany note	0	0
Intercompany financing	0
Contribution received	26,395
Distribution of Fortune Creek Partnership funds	0	0
Purchase of treasury stock	0	0
Net cash flow provided (used) by financing activities	26,395	0
Effect of exchange rates on cash	0	0
Net increase (decrease) in cash and equivalents	0	0
Cash and cash equivalents at beginning of period	22	0
Cash and cash equivalents at end of period	22	0
Fortune Creek [Member]
Schedule of Equity Method Investments [Line Items]
Net cash flow provided (used) by operating activities	6,336	6,428
Purchases of property, plant and equipment	(21)	(525)
Investment in subsidiary	0
Proceeds from sale of properties and equipment	0	0
Payments to acquire marketable securities	0	0
Proceeds from Sale and Maturity of Marketable Securities	0	0
Net cash used by investing activities	(21)	(525)
Issuance of debt	0	0
Repayments of debt	0	0
Debt issuance costs	0	0
Intercompany note	0	0
Intercompany financing	0
Contribution received	26,395
Distribution of Fortune Creek Partnership funds	(37,113)	(8,079)
Purchase of treasury stock	0	0
Net cash flow provided (used) by financing activities	(10,718)	(8,079)
Effect of exchange rates on cash	4,934	3,122
Net increase (decrease) in cash and equivalents	531	946
Cash and cash equivalents at beginning of period	1,053	333
Cash and cash equivalents at end of period	1,584	1,279
Consolidating Eliminations [Member]
Schedule of Equity Method Investments [Line Items]
Net cash flow provided (used) by operating activities	0
Purchases of property, plant and equipment	0
Investment in subsidiary	52,790
Proceeds from sale of properties and equipment	0
Payments to acquire marketable securities	0
Proceeds from Sale and Maturity of Marketable Securities	0
Net cash used by investing activities	52,790
Issuance of debt	0
Repayments of debt	0
Debt issuance costs	0
Contribution received	(52,790)
Distribution of Fortune Creek Partnership funds	0
Purchase of treasury stock	0
Net cash flow provided (used) by financing activities	(52,790)
Effect of exchange rates on cash	0
Net increase (decrease) in cash and equivalents	0
Cash and cash equivalents at beginning of period	0
Cash and cash equivalents at end of period	0
Tokyo Gas [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0	463,418
Tokyo Gas [Member] | Quicksilver Resources Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		463,418
Tokyo Gas [Member] | Restricted Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Tokyo Gas [Member] | Restricted Non-Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Tokyo Gas [Member] | Quicksilver And Restricted Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		463,418
Tokyo Gas [Member] | Unrestricted Non-Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Tokyo Gas [Member] | Fortune Creek [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Sandwash Basin [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	95,587	0
Sandwash Basin [Member] | Quicksilver Resources Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	95,587
Sandwash Basin [Member] | Restricted Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0
Sandwash Basin [Member] | Restricted Non-Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0
Sandwash Basin [Member] | Restricted Subsidiary Eliminations [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0
Sandwash Basin [Member] | Quicksilver And Restricted Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	95,587
Sandwash Basin [Member] | Unrestricted Non-Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0
Sandwash Basin [Member] | Fortune Creek [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0
Sandwash Basin [Member] | Consolidating Eliminations [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0
Synergy [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0	42,297
Synergy [Member] | Quicksilver Resources Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		42,297
Synergy [Member] | Restricted Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Synergy [Member] | Restricted Non-Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Synergy [Member] | Quicksilver And Restricted Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		42,297
Synergy [Member] | Unrestricted Non-Guarantor Subsidiaries [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Synergy [Member] | Fortune Creek [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		$ 0

XML

Quicksilver Stockholders' Equity (Assumptions For The Black-Scholes Option Pricing Model For Stock Options Issued) (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Weighted avg grant date fair value	$ 1.05
Weighted avg risk-free interest rate	1.31%
Expected life (in years)	4 years 10 months 25 days
Wtd avg volatility	69.00%
Expected dividends	0.00%

XML

Segment Information (Operating Income And Property And Equipment Costs Incurred) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]
Number of geographical segments	2		2
Revenue	$ 163,498	$ 153,116	$ 373,316	$ 447,318
Depletion, depreciation and accretion	13,969	14,390	42,584	47,911
Impairment of Oil and Gas Properties	135	0	135	0
Operating income (loss)	64,784	60,049	67,266	451,073
Property and equipment costs incurred	28,456	20,721	107,584	72,455
Property, plant and equipment - net	812,480		812,480		860,805
Total assets	1,268,257		1,268,257		1,369,726
UNITED STATES
Segment Reporting Information [Line Items]
Revenue	120,513	114,002	269,310	334,804
Depletion, depreciation and accretion	8,096	8,402	23,652	29,745
Impairment of Oil and Gas Properties	0		0
Operating income (loss)	57,809	56,911	78,891	456,624
Property and equipment costs incurred	20,912	15,147	85,814	50,459
Property, plant and equipment - net	415,163		415,163		451,840
Total assets	796,931		796,931		895,388
CANADA
Segment Reporting Information [Line Items]
Revenue	42,072	38,407	101,198	110,052
Depletion, depreciation and accretion	4,171	4,114	13,779	12,458
Impairment of Oil and Gas Properties	0		0
Operating income (loss)	16,364	11,076	20,199	30,126
Property and equipment costs incurred	7,254	4,288	20,924	9,972
Property, plant and equipment - net	303,827		303,827		306,423
Total assets	362,994		362,994		359,951
Midstream [Member]
Segment Reporting Information [Line Items]
Revenue	5,184	6,381	16,157	19,198
Depletion, depreciation and accretion	1,256	1,300	3,744	3,947
Impairment of Oil and Gas Properties	135		135
Operating income (loss)	2,367	3,107	7,700	9,593
Property and equipment costs incurred	72	1,615	83	2,369
Property, plant and equipment - net	89,362		89,362		97,118
Total assets	104,204		104,204		108,963
Corporate [Member]
Segment Reporting Information [Line Items]
Revenue	0	0	0	0
Depletion, depreciation and accretion	446	574	1,409	1,761
Impairment of Oil and Gas Properties	0		0
Operating income (loss)	(11,756)	(11,045)	(39,524)	(45,270)
Property and equipment costs incurred	218	(329)	763	9,655
Property, plant and equipment - net	4,128		4,128		5,424
Total assets	4,128		4,128		5,424
Elimination [Member]
Segment Reporting Information [Line Items]
Revenue	(4,271)	(5,674)	(13,349)	(16,736)
Depletion, depreciation and accretion	0	0	0	0
Impairment of Oil and Gas Properties	0		0
Operating income (loss)	0	0	0	0
Property and equipment costs incurred	0	0	0	0
Property, plant and equipment - net	0		0		0
Total assets	$ 0		$ 0		$ 0

XML

Fortune Creek (Details)	9 Months Ended
	Sep. 30, 2014 USD ($)	Sep. 30, 2014 CAD	Sep. 30, 2014 KKR [Member] CAD Y
Minimum Expenditures Required to Acquire Productive Assets	$ 120,000,000
Capital Contribution, Fortune Creek		28,000,000
Reduction in Gathering Rate, Fortune Creek		0.13
Dedicated years for gas production			10
Payments to acquire interest in joint venture			125,000,000
Percentage of interest by parent in the partnership			50.00%

XML

Derivatives And Fair Value Measurements (Changes In Level 3 Fair Values) (Details) (Fair Value Inputs, Level 3 [Member], USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	$ (24,829)	$ (24,080)	$ 6,488	$ (24,618)
Balance at beginning of period	(5,533)	(9,873)	23,485	(4,931)
Balance at end of period	17,754	10,905	17,754	10,905
Total gains (losses) included in net derivative gains (losses) attributable to the change in unrealized gains (losses) related to assets still held at the reporting date	24,485	24,026	(2,476)	26,788
Derivative gains (losses) [Member]
Settlements	$ (1,542)	$ (3,302)	$ 757	$ (8,782)

XML

Supplemental Cash Flow Information (Other Significant Noncash Transactions) (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Supplemental Cash Flow Information [Abstract]
Capital Expenditures Incurred but Not yet Paid	$ 7,612	$ 4,867

XML

Quicksilver Stockholders' Equity (Tables)

9 Months Ended

Sep. 30, 2014

Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]

Assumptions For The Black-Scholes Option Pricing Model For Stock Options Issued

Weighted avg grant date fair value	$1.05
Weighted avg risk-free interest rate	1.31%
Expected life	4.9 years
Wtd avg volatility	69.0%
Expected dividends	—

Stock Option Activity

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
					(in years)	(in thousands)
Outstanding at January 1, 2014	6,771,578		$	7.82
Forfeited	(44,950	)	1.65
Expired	(111,494	)	9.83
Outstanding at September 30, 2014	6,615,134		$	7.83	5.4	$	—
Exercisable at September 30, 2014	5,232,903		$	9.18	4.6	$	—

Restricted Stock And Stock Unit Activity

	Payable in shares				Payable in cash
	Shares		Weighted Average Grant Date Fair Value		Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2014	5,668,090		$	3.90	1,572,341		$	3.69
Granted	4,765,425		2.64		—		—
Vested	(2,559,959	)	4.86		(631,275	)	4.29
Forfeited	(348,554	)	3.09		(33,458	)	3.20
Outstanding at September 30, 2014	7,525,002		$	2.82	907,608		$	3.32

XML

Quicksilver Stockholders' Equity (Restricted Stock And Stock Unit Activity) (Details) (USD $) In Millions, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 14.8
Payable In Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at beginning of period, Shares	5,668,090
Granted, Shares	4,765,425
Vested, Shares	(2,559,959)
Forfeited, Shares	(348,554)
Outstanding at end of period, Shares	7,525,002
Outstanding at beginning of period, Wtd Avg Grant Date Fair Value	$ 3.90
Granted, Wtd Avg Grant Date Fair Value	$ 2.64
Vested, Wtd Avg Grant Date Fair Value	$ 4.86
Forfeited, Wtd Avg Grant Date Fair Value	$ 3.09
Outstanding at end of period, Wtd Avg Grant Date Fair Value	$ 2.82
Payable In Cash [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at beginning of period, Shares	1,572,341
Granted, Shares	0
Vested, Shares	(631,275)
Forfeited, Shares	(33,458)
Outstanding at end of period, Shares	907,608
Outstanding at beginning of period, Wtd Avg Grant Date Fair Value	$ 3.69
Granted, Wtd Avg Grant Date Fair Value	$ 0.00
Vested, Wtd Avg Grant Date Fair Value	$ 4.29
Forfeited, Wtd Avg Grant Date Fair Value	$ 3.20
Outstanding at end of period, Wtd Avg Grant Date Fair Value	$ 3.32

XML

Long-Term Debt (Schedule Of Outstanding Debt) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 325
Credit Agreement Repayment Term Trigerring Event, Maximum Threshold For Measurement	100
Senior Secured Second Lien Credit Facility [Member]
Debt Instrument [Line Items]
Credit Agreement Repayment Term Trigerring Event, Maximum Threshold For Measurement	100
Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument Year Of Maturity	2019
Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Equity interests	100.00%
Multiple Subsidiaries Set One [Member] | U.S. Credit Facility [Member]
Debt Instrument [Line Items]
Equity interests	100.00%
Multiple Subsidiaries Set Two [Member] | U.S. Credit Facility [Member]
Debt Instrument [Line Items]
Equity interests	65.00%
Maximum [Member] | U.S. Credit Facility [Member]
Debt Instrument [Line Items]
Commitment fee percentage	1.75%
Applicable margin in addition to interest rate	2.75%
First Mortgage [Member] | Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	325	[1],[2]
Scheduled maturity date	Sep. 06, 2016	[3]
Debt Instrument, Potential Earliest Maturity Date	October 1, 2015	[3]
Debt Instrument, Interest Rate, Stated Percentage	4.09%	[4]
Base Interest Rate Options	LIBOR, ABR, CDOR	[5],[6]
Financial covenants	- Minimum current ratio of 1.0 - Minimum EBITDA to cash interest expense ratio of 1.10 - Maximum senior secured debt leverage ratio of 2.0	[7],[8]
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions - Limitations on derivatives and investments	[8],[9]
Optional redemption	Any time	[8]
Make-whole redemption	N/A
Change of control	Event of default	[8]
Equity Clawback	N/A
Estimated fair value	276.0	[10]
Current ratio	1.0
Minimum EBITDA to cash interest expense ratio	1.10
Senior secured debt leverage ratio	2.0
Second Lien Debt [Member] | Senior Secured Second Lien Credit Facility [Member]
Debt Instrument [Line Items]
Principal amount	625	[2]
Scheduled maturity date	Jun. 21, 2019	[3]
Debt Instrument, Potential Earliest Maturity Date	January 1, 2016	[3]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Base Interest Rate Options	LIBOR floor of 1.25%; ABR floor of 2.25%
Financial covenants	N/A
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	[8],[9]
Optional redemption	Any time, subject to re-pricing event June 21, 2015: 101	[8]
Make-whole redemption	N/A
Change of control	Put at 101% of principal plus accrued interest	[8]
Equity Clawback	N/A
Estimated fair value	568.8	[10]
Percentage of principal plus accrued interest for change of control	101.00%
Second Lien Debt [Member] | Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Principal amount	200	[2]
Scheduled maturity date	Jun. 21, 2019	[3]
Debt Instrument, Potential Earliest Maturity Date	January 1, 2016	[3]
Debt Instrument, Interest Rate, Stated Percentage	7.00%
Base Interest Rate Options	LIBOR floor of 1.25%
Financial covenants	N/A
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	[8],[9]
Optional redemption	Any time, subject to re-pricing event June 21, 2015: 101	[8]
Make-whole redemption	N/A
Change of control	Put at 101% of principal plus accrued interest	[8]
Equity Clawback	N/A
Estimated fair value	182.0	[10]
Percentage of principal plus accrued interest for change of control	101.00%
Senior Notes [Member] | Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Principal amount	298
Scheduled maturity date	Aug. 15, 2019
Debt Instrument, Potential Earliest Maturity Date	N/A
Debt Instrument, Interest Rate, Stated Percentage	9.125%
Base Interest Rate Options	N/A
Financial covenants	N/A
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	[8],[9]
Optional redemption	August 15, 2014: 104.563 2015: 103.042 2016: 101.521 2017: par	[8]
Make-whole redemption	N/A
Make-whole redemption	0.50%
Change of control	Put at 101% of principal plus accrued interest	[8]
Equity Clawback	N/A
Estimated fair value	186.3	[10]
Percentage of principal plus accrued interest for change of control	101.00%
Senior Notes [Member] | Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Principal amount	325
Scheduled maturity date	Jul. 01, 2021
Debt Instrument, Potential Earliest Maturity Date	N/A
Debt Instrument, Interest Rate, Stated Percentage	11.00%
Base Interest Rate Options	N/A
Financial covenants	N/A
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	[8],[9]
Optional redemption	July 1, 2019: 102.000 2020: par	[8]
Make-whole redemption	Callable prior to July 1, 2019 at make-whole call price of Treasury +50 bps	[8]
Make-whole redemption	0.50%
Change of control	Put at 101% of principal plus accrued interest	[8]
Equity Clawback	Redeemable until July 1, 2016 at 111.00%, plus accrued interest for up to 35%	[8]
Equity Clawback	111.00%
Estimated fair value	213.7	[10]
Percentage of principal plus accrued interest for change of control	101.00%
Senior Subordinated Notes [Member] | Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Principal amount	350
Scheduled maturity date	Apr. 01, 2016
Debt Instrument, Potential Earliest Maturity Date	N/A
Debt Instrument, Interest Rate, Stated Percentage	7.125%
Base Interest Rate Options	N/A
Financial covenants	N/A
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	[8],[9]
Optional redemption	Any time	[8]
Make-whole redemption	N/A
Change of control	Put at 101% of principal plus accrued interest	[8]
Equity Clawback	N/A
Estimated fair value	$ 136.5	[10]
Percentage of principal plus accrued interest for change of control	101.00%
Libor [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	3.75%
Libor [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	2.75%
Libor [Member] | Second Lien Debt [Member] | Senior Secured Second Lien Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Reference Rate, Floor	1.25%
Libor [Member] | Second Lien Debt [Member] | Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Reference Rate, Floor	1.25%
ABR [Member] | Second Lien Debt [Member] | Senior Secured Second Lien Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Reference Rate, Floor	2.25%
CDOR Rate [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	3.75%
CDOR Rate [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	2.75%
LIBOR [Member] | U.S. Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	1.00%
Canadian Prime Rate [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	2.75%
Canadian Prime Rate [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	1.75%
U.S. Prime Rate [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	2.75%
U.S. Prime Rate [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	1.75%
2013 [Member] | Senior Notes [Member] | Senior Notes Due 2015 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	101.938%
2013 [Member] | Senior Notes [Member] | Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	105.875%
2014 [Member] | Second Lien Debt [Member] | Senior Secured Second Lien Credit Facility [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	102.00%
2014 [Member] | Second Lien Debt [Member] | Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	102.00%
2014 [Member] | Senior Notes [Member] | Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	104.563%
2014 [Member] | Senior Subordinated Notes [Member] | Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	100.00%
2015 [Member] | Second Lien Debt [Member] | Senior Secured Second Lien Credit Facility [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	101.00%
2015 [Member] | Second Lien Debt [Member] | Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	101.00%
2015 [Member] | Senior Notes [Member] | Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	103.042%
2016 [Member] | Senior Notes [Member] | Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	101.521%
2017 [Member] | Senior Notes [Member] | Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	100.00%
2019 [Member] | Senior Notes [Member] | Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	102.00%
2020 [Member] | Senior Notes [Member] | Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	100.00%

[1] The principal amount for the Combined Credit Agreements represents the global borrowing base as of September 30, 2014.

[2] Borrowings under the Amended and Restated U.S. Credit Facility, Second Lien Term Loan and Second Lien Notes due 2019 are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured (on a first priority basis with respect to the Amended and Restated U.S. Credit Facility and on a second priority basis with respect to the Second Lien Term Loan and the Second Lien Notes due 2019) 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, QPP Parent LLC and QPP Holdings LLC (collectively, the “Domestic Pledged Equity”), 65% of the equity interests of Quicksilver Resources Canada Inc. (“Quicksilver Canada”) and Quicksilver Production Partners Operating Ltd. (with respect to the Amended and Restated U.S. Credit Facility, on a ratable basis with borrowings under the Amended and Restated Canadian Credit Facility) and the majority of Quicksilver's domestic proved oil and gas properties and related assets, (the “Domestic Pledged Property”). 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, the Domestic Pledged Property, 100% of the equity interests of Quicksilver Canada (65% of which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and any Canadian restricted subsidiaries, under the Amended and Restated Canadian Credit Facility, and 65% of the equity interests of Quicksilver Production Partners Operating Ltd. (which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and the majority of Quicksilver Canada's oil and gas properties and related assets. The other debt presented is based upon structural seniority and priority of payment.

[3] The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the Senior Subordinated Notes, the Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Second Lien Term Loan and Second Lien Notes due 2019 are required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remain outstanding and (2) 91 days prior to the maturity of the Senior Subordinated Notes if on the applicable date the amount remaining outstanding is greater than $100 million. As of September 30, 2014, as presently structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would be due on October 1, 2015 and the Second Lien Term Loan and Second Lien Notes due 2019 would be due on January 1, 2016.

[4] Represents the weighted average borrowing rate payable to lenders.

[5] 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 2.75% and 3.75%, (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 1.75% and 2.75%. 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 Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.50%.

[6] 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 2.75% and 3.75%, (ii) the Canadian Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75%, (iii) the U.S. Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75% and (iv) adjusted LIBOR (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%. 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 Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.50%.

[7] As of September 30, 2014, the future minimum required interest coverage ratio for the Combined Credit Agreements is as follows:Period Interest Coverage Ratio Period Interest Coverage RatioQ4 2014 1.10 Q4 2015 1.20Q1 2015 1.10 Q1 2016 1.50Q2 2015 1.15 Q2 2016 2.00Q3 2015 1.15 In November 2014, the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels: Minimum EBITDAX Covenant (in millions)Three months ending December 31, 2014$30.0Six months ending March 31, 201559.0Nine months ending June 30, 201587.25Twelve months ending September 30, 2015120.5Twelve months ending December 31, 2015122.0

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

[9] Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.

[10] The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). Our Second Lien Term Loan and Second Lien Notes due 2019 feature variable interest rates and we estimate their fair value by using market quotations based on recent trade activity (“Level 3” input). We consider our Combined Credit Agreements which have a variable interest rate to have a fair value equal to their carrying value (“Level 1” input).

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Derivatives And Fair Value Measurements Derivatives And Fair Value Measurements (Available-for-sale securities) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014
Schedule of Available-for-sale Securities [Line Items]
Held-to-maturity Securities, Sold Security, at Carrying Value	$ 10.0
Held-to-maturity Securities, Transferred Security, at Carrying Value	$ 10.0

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Condensed Consolidating Financial Information (Schedule Of Condensed Consolidated Balance Sheets) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets	$ 396,300	$ 393,960
Property and equipment	812,480	860,805
Investment in subsidiaries (equity method)	0	0
Other assets	59,477	114,961
Total assets	1,268,257	1,369,726
Current liabilities	108,524	134,797
Long-term liabilities	2,257,217	2,240,899
Stockholders' equity	(1,097,484)	(1,005,970)
Total liabilities and stockholders' equity	1,268,257	1,369,726
Quicksilver Resources Inc. [Member]
Current assets	338,424	349,586
Property and equipment	417,921	455,822
Investment in subsidiaries (equity method)	(227,994)	(217,852)
Other assets	457,285	472,792
Total assets	985,636	1,060,348
Current liabilities	103,042	124,275
Long-term liabilities	1,980,078	1,942,043
Stockholders' equity	(1,097,484)	(1,005,970)
Total liabilities and stockholders' equity	985,636	1,060,348
Restricted Guarantor Subsidiaries [Member]
Current assets	13,096	10,735
Property and equipment	14,625	15,486
Investment in subsidiaries (equity method)	0	0
Other assets	0	0
Total assets	27,721	26,221
Current liabilities	13,401	12,210
Long-term liabilities	19,241	19,242
Stockholders' equity	(4,921)	(5,231)
Total liabilities and stockholders' equity	27,721	26,221
Restricted Non-Guarantor Subsidiaries [Member]
Current assets	65,733	53,034
Property and equipment	305,197	307,865
Investment in subsidiaries (equity method)	(23,409)	(33,840)
Other assets	15,473	32,892
Total assets	362,994	359,951
Current liabilities	11,064	17,167
Long-term liabilities	575,003	542,659
Stockholders' equity	(223,073)	(199,875)
Total liabilities and stockholders' equity	362,994	359,951
Restricted Subsidiary Eliminations [Member]
Current assets	(23,193)	(19,642)
Property and equipment	0	0
Investment in subsidiaries (equity method)	227,994	217,852
Other assets	(413,281)	(390,723)
Total assets	(208,480)	(192,513)
Current liabilities	(23,193)	(19,642)
Long-term liabilities	(413,281)	(390,723)
Stockholders' equity	227,994	217,852
Total liabilities and stockholders' equity	(208,480)	(192,513)
Quicksilver And Restricted Subsidiaries [Member]
Current assets	394,060	393,713
Property and equipment	737,743	779,173
Investment in subsidiaries (equity method)	(23,409)	(33,840)
Other assets	59,477	114,961
Total assets	1,167,871	1,254,007
Current liabilities	104,314	134,010
Long-term liabilities	2,161,041	2,113,221
Stockholders' equity	(1,097,484)	(993,224)
Total liabilities and stockholders' equity	1,167,871	1,254,007
Unrestricted Non-Guarantor Subsidiaries [Member]
Current assets	(455)	909
Property and equipment	0	0
Investment in subsidiaries (equity method)	(23,429)	(33,840)
Other assets	0	0
Total assets	(23,884)	(32,931)
Current liabilities	(475)	888
Long-term liabilities	0	0
Stockholders' equity	(23,409)	(33,819)
Total liabilities and stockholders' equity	(23,884)	(32,931)
Fortune Creek [Member]
Current assets	1,746	1,110
Property and equipment	74,737	81,632
Investment in subsidiaries (equity method)	0	0
Other assets	0	0
Total assets	76,483	82,742
Current liabilities	3,736	1,671
Long-term liabilities	1,525	1,546
Stockholders' equity	71,222	79,525
Total liabilities and stockholders' equity	76,483	82,742
Consolidating Eliminations [Member]
Current assets	949	(1,772)
Property and equipment	0	0
Investment in subsidiaries (equity method)	46,838	67,680
Other assets	0	0
Total assets	47,787	65,908
Current liabilities	949	(1,772)
Long-term liabilities	94,651	126,132
Stockholders' equity	(47,813)	(58,452)
Total liabilities and stockholders' equity	$ 47,787	$ 65,908

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Quicksilver Stockholders' Equity (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified			9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 Restricted Stock [Member]	Sep. 30, 2013 Restricted Stock [Member]	Sep. 30, 2014 Equity Option [Member]	Sep. 30, 2013 Equity Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock, shares authorized	400,000,000	400,000,000
Shares of common stock outstanding	179,800,000	177,300,000
Common stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares outstanding	0	0
Preferred stock, par value	$ 0.01	$ 0.01
Total intrinsic values of options					6,300,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized			$ 14.8		$ 1.0
Share Based Compensation Nonvested Awards Total Compensation Cost Not Yet Recognized Period For Recognition			July 2017		August 2016
Estimated grant date fair value			12.6
Fair value of RSUs settled in cash			0.5
Allocated Share-based Compensation Expense			8.4	12.2	1.1	3.2
Total fair value of shares vested			$ 10.2
Common stock, shares issued	187,222,654	183,994,879
Treasury stock, shares	7,444,372	6,698,640

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Divestitures

9 Months Ended

Sep. 30, 2014

Discontinued Operations and Disposal Groups [Abstract]

Divestitures

DIVESTITURES

In May 2014, we completed the sale of our Niobrara Asset to Southwestern Energy Company. The purchase price was subject to customary purchase price adjustments, which resulted in Southwestern paying us $95.6 million. We determined that the Southwestern Transaction did not represent a significant disposal of reserves under GAAP, therefore we reduced the balance of U.S. oil and gas properties by the amount of these proceeds and we did not recognize a gain or loss.

In August 2013, we completed the sale of our Southern Alberta Asset to Synergy. The purchase price was $46.0 million, which was subject to customary purchase price adjustments, resulting in a final purchase price of $42.3 million. We determined that the Synergy Transaction did not represent a significant disposal of reserves, therefore our U.S. oil and gas properties were reduced by these proceeds and we did not recognize a gain or a loss.

In April 2013, we sold an undivided 25% interest in our Barnett Shale Asset to TGBR for a purchase price of $485 million. The effective date of the transaction was September 1, 2012. The purchase price was subject to customary price adjustments, which resulted in a final purchase price of $464.0 million. We recognized a gain of $341.1 million, which was subsequently adjusted in the second half of 2013 to $339.3 million, including a revision of the gain calculation in the third quarter of 2013 of $8.0 million, before consideration of income taxes based on our determination that the Tokyo Gas Transaction represented a significant disposal of reserves under GAAP. Our U.S. oil and gas properties were ultimately reduced through December 31, 2013 by $110.7 million as a result of the Tokyo Gas Transaction.

Note 3 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains additional information on other divestitures.

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Long-Term Debt Long-Term Debt (Minimum Required Interest Coverage Ratio) (Details) (Minimum [Member], Combined Credit Agreements [Member])	9 Months Ended
	Sep. 30, 2014
Q4 2014 [Member]
Debt Instrument [Line Items]
Interest coverage ratio	1.10
Q1 2015 [Member]
Debt Instrument [Line Items]
Interest coverage ratio	1.10
Q2 2015 [Member]
Debt Instrument [Line Items]
Interest coverage ratio	1.15
Q3 2015 [Member]
Debt Instrument [Line Items]
Interest coverage ratio	1.15
Q4 2015 [Member]
Debt Instrument [Line Items]
Interest coverage ratio	1.20
Q1 2016 [Member]
Debt Instrument [Line Items]
Interest coverage ratio	1.50
Q2 2016 [Member]
Debt Instrument [Line Items]
Interest coverage ratio	2.00

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2014

Supplemental Cash Flow Information [Abstract]

Cash Paid Or Received For Interest And Income Taxes

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
Interest, net of capitalized interest	$	124,408		$	227,189
Income taxes	(7,844		)	1,217

Other Significant Non-cash Transactions

	For the Nine Months Ended September 30,
	2014		2013
	(in thousands)
Working capital related to capital expenditures	$	7,612	$	4,867

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Operating Income And Property And Equipment Costs Incurred

	Exploration & Production												Quicksilver Consolidated
	U.S.		Canada		Midstream		Corporate			Elimination
For the Three Months Ended September 30:	(in thousands)
2014
Revenue	$	120,513	$	42,072	$	5,184	$	—		$	(4,271	)	$	163,498
DD&A	8,096		4,171		1,256		446			—			13,969
Impairment expense	—		—		135		—			—			135
Operating income (loss)	57,809		16,364		2,367		(11,756		)	—			64,784
Property and equipment costs incurred	20,912		7,254		72		218			—			28,456
2013
Revenue	$	114,002	$	38,407	$	6,381	$	—		$	(5,674	)	$	153,116
DD&A	8,402		4,114		1,300		574			—			14,390
Operating income (loss)	56,911		11,076		3,107		(11,045		)	—			60,049
Property and equipment costs incurred	15,147		4,288		1,615		(329		)	—			20,721
For the Nine Months Ended September 30:
2014
Revenue	$	269,310	$	101,198	$	16,157	$	—		$	(13,349	)	$	373,316
DD&A	23,652		13,779		3,744		1,409			—			42,584
Impairment expense	—		—		135		—			—			135
Operating income (loss)	78,891		20,199		7,700		(39,524		)	—			67,266
Property and equipment costs incurred	85,814		20,924		83		763			—			107,584
2013
Revenue	$	334,804	$	110,052	$	19,198	$	—		$	(16,736	)	$	447,318
DD&A	29,745		12,458		3,947		1,761			—			47,911
Operating income (loss)	456,624		30,126		9,593		(45,270		)	—			451,073
Property and equipment costs incurred	50,459		9,972		2,369		9,655			—			72,455
Property, plant and equipment-net
September 30, 2014	$	415,163	$	303,827	$	89,362	$	4,128		$	—		$	812,480
December 31, 2013	451,840		306,423		97,118		5,424			—			860,805
Total assets
September 30, 2014	796,931		362,994		104,204		4,128			—			$	1,268,257
December 31, 2013	895,388		359,951		108,963		5,424			—			1,369,726

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Supplemental Cash Flow Information (Cash Paid Or Received For Interest And Income Taxes) (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Supplemental Cash Flow Information [Abstract]
Interest, net of capitalized interest	$ 124,408	$ 227,189
Income taxes	$ (7,844)	$ 1,217

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Long-Term Debt Minimum EBITDAX Covenant (Details) (Subsequent Event [Member], Minimum [Member], Combined Credit Agreements [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Three Months Ended December 31, 2014 [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	$ 30.00
Six months ending March 31, 2015 [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	59.00
Nine months ending June 30, 2015 [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	87.25
Twelve months ending September 30, 2015 [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	120.50
Twelve months ending December 31, 2015 [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	$ 122.00

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Divestitures Divestitures (Details) (USD $)					3 Months Ended		9 Months Ended
	May 01, 2014 Sandwash Basin [Member]	Sep. 30, 2013 Southern Alberta Basin [Member]	Sep. 30, 2013 Barnett Shale [Member]	Apr. 30, 2013 Barnett Shale [Member]	Sep. 30, 2014 Tokyo Gas [Member]	Sep. 30, 2013 Tokyo Gas [Member]	Sep. 30, 2014 Tokyo Gas [Member]	Sep. 30, 2013 Tokyo Gas [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity Method Investment, Ownership Percentage				25.00%
PurchasePricePriorToAdjustments		$ 46,000,000		$ 485,000,000
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	95,600,000	42,300,000		464,000,000
Gain (Loss) on Disposition of Oil and Gas and Timber Property					0	7,974,000	0	341,146,000
Significant Acquisitions and Disposals, Gain (Loss) on Sale or Disposal, Pretax			8,000,000	339,300,000
Oil and Gas Property Decrease due to Gain						$ 110,700,000

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Derivatives And Fair Value Measurements (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings	$ 22.7
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	1.5	11.5
Reduction Of Interest Expense Over Life Of Debt Instruments, next 12 months	$ 2.2
Fair Value Inputs, Level 3 [Member]
Natural gas hedges original tenure	10 years
Fair Value Inputs, Level 3 [Member] | Maximum [Member]
Unobservable inputs included within the fair value calculation	4.90
Fair Value Inputs, Level 3 [Member] | Minimum [Member]
Unobservable inputs included within the fair value calculation	3.85

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Accounting Policies And Disclosures

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Accounting Policies And Disclosures

ACCOUNTING POLICIES, DISCLOSURES AND NATURE OF OPERATIONS

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, 2014 and our results of operations and cash flows for the periods presented. All such adjustments are of a normal recurring nature unless otherwise noted. 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 2013 Annual Report on Form 10-K.

Our ability to borrow under our Combined Credit Agreements depends on our global borrowing base, which is scheduled to be redetermined twice each year. A reduction to the global borrowing base during the spring or autumn redetermination, or upon a special redetermination requested by our administrative agent under the Combined Credit Agreements, would adversely impact our liquidity and ability to meet our future obligations. Our derivatives contribute to the global borrowing base. Most of our derivative positions expire at year-end 2015. The expiration of these derivatives will adversely affect our global borrowing base, and absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing, significant cost savings through avoidance or deferral, or operational efficiencies, we expect to need additional sources of liquidity, including additional debt or equity financing or proceeds from asset sales, at the beginning of 2016 assuming no material debt maturities prior to that date. In addition, we are exploring potential transactions involving any and all of our assets, including our Horn River Asset. If successful, a sale of our Horn River Asset could eliminate or defray our need to make or fund significant capital investments in the Horn River Asset but would also reduce our global borrowing base if not offset by the effects of any related debt reduction. A sale of our other assets could also enhance liquidity if the sale proceeds exceed the associated decrease to the global borrowing base, if any.

In November 2014, the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. While we believe with these amendments we will be able to comply with the financial covenants contained in our Combined Credit Agreements through the end of 2015, we do not expect to exceed the required levels by a significant margin, particularly the minimum EBITDAX covenant under our Combined Credit Agreements. Accordingly, even a modest decline in prices for natural gas and NGLs, our failure to achieve anticipated cost savings through avoidance or deferral or operational efficiencies, our failure to execute certain asset purchases or the inaccuracy in any material respect of any of the other assumptions underlying our forecast could cause us to fall short of the financial covenants contained in the Combined Credit Agreements. Absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing, significant cost savings through avoidance or deferral, or operational efficiencies, we do not expect to comply with our interest coverage ratio covenant under our Combined Credit Agreements beginning in the first quarter of 2016 and expect that we would need to seek additional covenant relief under the Combined Credit Agreements at that time. In addition, we have benefitted from our natural gas derivatives, which have resulted in cash proceeds being greater than the prevailing price for natural gas. Without the benefit of these derivatives, most of which expire at year-end 2015, our earnings would be reduced and our cash interest expense would exceed our resulting EBITDAX. Any inability to comply with the financial covenants contained in our Combined Credit Agreements, unless waived or amended by the requisite lenders, could materially and adversely affect our liquidity by precluding further borrowings under our credit facilities and by accelerating the maturity of our debt. We may be unsuccessful in obtaining the necessary waivers or amendments.

In addition, we have significant fixed and springing debt maturities in 2015 and 2016, including the Combined Credit Agreements, the Second Lien Term Loan, the Second Lien Notes and the Senior Subordinated Notes. Note 5 contains a more complete description of our long-term debt, including springing maturities, which could occur as early as October 1, 2015. We do not expect to be able to satisfy these obligations with our cash on hand, committed financing or cash flow from operations. In order to satisfy these obligations we will need to obtain additional debt or equity financing or to sell assets, which we may not be able to do on satisfactory terms, or at all. We are limited in our ability to incur additional debt by the indenture restrictions. We may also seek to address the springing maturities by extending the maturity of or refinancing all or a portion of our Senior Subordinated Notes. If we are unsuccessful in extending or refinancing, we may not be able to satisfy such obligations when they mature.

Although we have been in discussions on a potential transaction involving our Horn River Asset and have proposed transaction terms, we reached no agreement on any material terms, including structure or valuation. Accordingly, we developed a formalized marketing process for this asset, along with any and all of our assets. We may be unsuccessful in consummating a transaction involving our Horn River Asset or any of our other assets being marketed on acceptable terms, or at all.

We have retained Houlihan Lokey Capital, Inc., Deloitte Transactions and Business Analytics LLP and other advisors to assist us in one or more of the following exercises:

• evaluation of options to address near-term debt maturities;

• enhancement of our liquidity position;

• evaluation of various strategic alternatives, including the acquisition or monetization of any and all assets or the Company; and

• employee retention.

Recently Issued Accounting Standards

In May 2014, the FASB issued accounting guidance, “Revenue from Contracts with Customers,” requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for us in the first quarter of 2017. We have not yet selected a transition method and we are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.

No other pronouncements materially affecting our financial statements have been issued since the filing of our 2013 Annual Report on Form 10-K.

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Derivatives And Fair Value Measurements (Estimated Fair Value Of Derivative Instruments Under Input Levels) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Asset Derivatives [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	$ 92,066	$ 130,880
Asset Derivatives [Member] | Fair Value Inputs, Level 2 [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	74,312	107,395
Asset Derivatives [Member] | Fair Value Inputs, Level 3 [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	17,754	23,485
Liability Derivatives [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	846	3,448
Liability Derivatives [Member] | Fair Value Inputs, Level 2 [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	846	3,448
Liability Derivatives [Member] | Fair Value Inputs, Level 3 [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	$ 0	$ 0

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Long-Term Debt (Narrative) (Details) (USD $)	9 Months Ended							9 Months Ended				9 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 Senior Notes Due 2015 [Member]	Sep. 30, 2014 Senior Notes Due 2016 [Member]	Sep. 30, 2014 Combined Credit Agreements [Member]	Dec. 31, 2013 Combined Credit Agreements [Member]	Sep. 30, 2014 Canadian Credit Facility [Member]	Sep. 30, 2014 Combined Credit Agreements [Member]	Sep. 30, 2014 Maximum [Member] U.S. Credit Facility [Member]	Sep. 30, 2014 Maximum [Member] Combined Credit Agreements [Member]	Sep. 30, 2014 Maximum [Member] Global Letter Of Credit [Member]	Sep. 30, 2014 Minimum [Member]	Sep. 30, 2014 Multiple Subsidiaries Set Two [Member] U.S. Credit Facility [Member]	Sep. 30, 2014 London Interbank Offered Rate (LIBOR) [Member] U.S. Credit Facility [Member]	Sep. 30, 2014 Libor [Member] Maximum [Member] Canadian Credit Facility [Member]	Sep. 30, 2014 Libor [Member] Minimum [Member] Canadian Credit Facility [Member]	Sep. 30, 2014 2013 [Member] Senior Notes [Member] Senior Notes Due 2015 [Member]	Sep. 30, 2014 2013 [Member] Senior Notes [Member] Senior Notes Due 2016 [Member]	Sep. 30, 2014 Subsequent Event [Member] Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Percentage of ownership interest							100.00%						65.00%
Borrowing capacity					$ 325,000,000						$ 280,000,000
Line of Credit Facility, Maximum Borrowing Capacity					650,000,000	1,750,000,000													450,000,000
Redemption percentage of par value																	101.938%	105.875%
Available borrowing under combined credit agreements								6,700,000
Commitment fee percentage								0.50%	1.75%	0.50%
EBITDA to interest expense												2.25
Repayments of Long-term Debt	193,689,000	1,308,382,000	10,900,000	8,900,000
Issuance of debt	$ 243,184,000	$ 1,173,306,000
Debt Instrument, Basis Spread on Variable Rate									2.75%					1.00%	3.75%	2.75%

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Condensed Consolidating Financial Information (Schedule of Condensed Consolidated Statements Of Income (Loss)) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenue	$ 163,498	$ 153,116	$ 373,316	$ 447,318
Operating expenses	98,714	101,041	306,050	337,391
Equity in net earnings of subsidiaries	0	0	0	0
Operating income (loss)	64,784	60,049	67,266	451,073
Fortune Creek accretion	(3,602)	(4,818)	(11,605)	(14,490)
Interest expense and other	(42,364)	(38,688)	(125,751)	(225,123)
Income tax (expense) benefit	4,939	(5,966)	(1,081)	(18,063)
Net income (loss)	23,757	10,577	(71,171)	193,397
Other comprehensive income (loss)	(14,889)	(8,794)	(27,101)	(38,114)
Equity in OCI of subsidiaries	0	0	0	0
Comprehensive income (loss)	8,868	1,783	(98,272)	155,283
Quicksilver Resources Inc. [Member]
Revenue	120,513	114,021	269,321	334,848
Operating expenses	72,868	73,594	225,906	256,810
Equity in net earnings of subsidiaries	8,821	3,854	2,864	(9,227)
Operating income (loss)	56,466	52,255	46,279	409,957
Fortune Creek accretion	0	0	0	0
Interest expense and other	(37,613)	(36,922)	(117,315)	(200,639)
Income tax (expense) benefit	4,826	(4,756)	(213)	(15,921)
Net income (loss)	23,679	10,577	(71,249)	193,397
Other comprehensive income (loss)	(11,564)	(6,114)	(20,252)	(29,014)
Equity in OCI of subsidiaries	(3,325)	(2,680)	(6,849)	(9,100)
Comprehensive income (loss)	8,790	1,783	(98,350)	155,283
Restricted Guarantor Subsidiaries [Member]
Revenue	427	192	1,212	608
Operating expenses	341	68	988	206
Equity in net earnings of subsidiaries	0	0	0	0
Operating income (loss)	86	124	224	402
Fortune Creek accretion	0	0	0	0
Interest expense and other	86	0	86	0
Income tax (expense) benefit	(30)	0	(78)	0
Net income (loss)	142	124	232	402
Other comprehensive income (loss)	0	0	0	0
Equity in OCI of subsidiaries	0	0	0	0
Comprehensive income (loss)	142	124	232	402
Restricted Non-Guarantor Subsidiaries [Member]
Revenue	42,558	38,903	102,783	111,862
Operating expenses	27,648	30,360	86,491	89,559
Equity in net earnings of subsidiaries	(1,458)	(1,834)	(4,266)	(5,300)
Operating income (loss)	13,452	6,709	12,026	17,003
Fortune Creek accretion	0	0	0	0
Interest expense and other	(4,838)	(1,769)	(8,526)	(24,490)
Income tax (expense) benefit	65	(1,210)	(868)	(2,142)
Net income (loss)	8,679	3,730	2,632	(9,629)
Other comprehensive income (loss)	(3,325)	(2,680)	(6,849)	(9,100)
Equity in OCI of subsidiaries	0	0	0	0
Comprehensive income (loss)	5,354	1,050	(4,217)	(18,729)
Restricted Subsidiary Eliminations [Member]
Revenue	0	0	0	0
Operating expenses	0	0	0	0
Equity in net earnings of subsidiaries	(8,821)	(3,854)	(2,864)	9,227
Operating income (loss)	(8,821)	(3,854)	(2,864)	9,227
Fortune Creek accretion	0	0	0	0
Interest expense and other	0	0	0	0
Income tax (expense) benefit	78	0	78	0
Net income (loss)	(8,743)	(3,854)	(2,786)	9,227
Other comprehensive income (loss)	0	0	0	0
Equity in OCI of subsidiaries	3,325	2,680	6,849	9,100
Comprehensive income (loss)	(5,418)	(1,174)	4,063	18,327
Quicksilver And Restricted Subsidiaries [Member]
Revenue	163,498	153,116	373,316	447,318
Operating expenses	100,857	104,022	313,385	346,575
Equity in net earnings of subsidiaries	(1,458)	(1,834)	(4,266)	(5,300)
Operating income (loss)	61,183	55,234	55,665	436,589
Fortune Creek accretion	0	0	0	0
Interest expense and other	(42,365)	(38,691)	(125,755)	(225,129)
Income tax (expense) benefit	4,939	(5,966)	(1,081)	(18,063)
Net income (loss)	23,757	10,577	(71,171)	193,397
Other comprehensive income (loss)	(14,889)	(8,794)	(27,101)	(38,114)
Equity in OCI of subsidiaries	0	0	0	0
Comprehensive income (loss)	8,868	1,783	(98,272)	155,283
Unrestricted Non-Guarantor Subsidiaries [Member]
Revenue	0	0	0	0
Operating expenses	0	0	0	0
Equity in net earnings of subsidiaries	2,144	2,984	7,339	9,190
Operating income (loss)	2,144	2,984	7,339	9,190
Fortune Creek accretion	0	0	0	0
Interest expense and other	0	0	0	0
Income tax (expense) benefit	0	0	0	0
Net income (loss)	2,144	2,984	7,339	9,190
Other comprehensive income (loss)	0	0	0	0
Equity in OCI of subsidiaries	0	0	0	0
Comprehensive income (loss)	2,144	2,984	7,339	9,190
Fortune Creek [Member]
Revenue	4,271	5,674	13,349	16,736
Operating expenses	2,128	2,693	6,014	7,552
Equity in net earnings of subsidiaries	0	0	0	0
Operating income (loss)	2,143	2,981	7,335	9,184
Fortune Creek accretion	0	0	0	0
Interest expense and other	1	3	4	6
Income tax (expense) benefit	0	0	0	0
Net income (loss)	2,144	2,984	7,339	9,190
Other comprehensive income (loss)	0	0	0	0
Equity in OCI of subsidiaries	0	0	0	0
Comprehensive income (loss)	2,144	2,984	7,339	9,190
Consolidating Eliminations [Member]
Revenue	(4,271)	(5,674)	(13,349)	(16,736)
Operating expenses	(4,271)	(5,674)	(13,349)	(16,736)
Equity in net earnings of subsidiaries	(686)	(1,150)	(3,073)	(3,890)
Operating income (loss)	(686)	(1,150)	(3,073)	(3,890)
Fortune Creek accretion	(3,602)	(4,818)	(11,605)	(14,490)
Interest expense and other	0	0	0	0
Income tax (expense) benefit	0	0	0	0
Net income (loss)	(4,288)	(5,968)	(14,678)	(18,380)
Other comprehensive income (loss)	0	0	0	0
Equity in OCI of subsidiaries	0	0	0	0
Comprehensive income (loss)	(4,288)	(5,968)	(14,678)	(18,380)
Tokyo Gas [Member]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		7,974		341,146
Tokyo Gas [Member] | Quicksilver Resources Inc. [Member]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		7,974		341,146
Tokyo Gas [Member] | Restricted Guarantor Subsidiaries [Member]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		0		0
Tokyo Gas [Member] | Restricted Non-Guarantor Subsidiaries [Member]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		0		0
Tokyo Gas [Member] | Restricted Subsidiary Eliminations [Member]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		0		0
Tokyo Gas [Member] | Quicksilver And Restricted Subsidiaries [Member]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		7,974		341,146
Tokyo Gas [Member] | Unrestricted Non-Guarantor Subsidiaries [Member]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		0		0
Tokyo Gas [Member] | Fortune Creek [Member]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		0		0
Tokyo Gas [Member] | Consolidating Eliminations [Member]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		$ 0		$ 0

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Condensed Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Revenue
Production	$ 102,615		$ 104,546		$ 332,187		$ 358,281
Sales of purchased natural gas	16,660		15,130		53,401		50,373
Net derivative gains (losses)	43,310		32,733		(15,080)		36,202
Other	913		707		2,808		2,462
Total revenue	163,498		153,116		373,316		447,318
Operating expense
Lease operating	17,176		18,591		54,622		63,699
Gathering, processing and transportation	34,807		35,567		102,511		112,064
Production and ad valorem taxes	4,067		4,678		12,557		15,462
Costs of purchased natural gas	16,599		15,114		53,305		50,311
Depletion, depreciation and accretion	13,969		14,390		42,584		47,911
Impairment of Oil and Gas Properties	135		0		135		0
General and administrative	11,310		10,471		38,115		43,509
Other operating	651		2,230		2,221		4,435
Total expense	98,714		101,041		306,050		337,391
Operating income (loss)	64,784		60,049		67,266		451,073
Other income - net	(2,465)		667		(3,824)		(14,588)
Fortune Creek accretion	(3,602)		(4,818)		(11,605)		(14,490)
Interest expense	(39,899)		(39,355)		(121,927)		(210,535)
Income (loss) before income taxes	18,818		16,543		(70,090)		211,460
Income tax (expense) benefit	4,939		(5,966)		(1,081)		(18,063)
Net Income (Loss) Attributable to Parent	23,757		10,577		(71,171)		193,397
Reclassification adjustments related to settlements of derivative contracts into production revenue- net of income tax	(7,968)		(11,139)		(20,939)		(37,181)
Foreign currency translation adjustment	(6,921)		2,345		(6,162)		(933)
Other comprehensive income (loss)	(14,889)		(8,794)		(27,101)		(38,114)
Comprehensive income (loss)	8,868		1,783		(98,272)		155,283
Earnings (loss) per common share - basic	$ 0.13		$ 0.06		$ (0.41)		$ 1.10
Earnings (loss) per common share - diluted	$ 0.13	[1]	$ 0.06	[1]	$ (0.41)	[1]	$ 1.10	[1]
Tokyo Gas [Member]
Operating expense
Gain (Loss) on Disposition of Oil and Gas and Timber Property	$ 0		$ 7,974		$ 0		$ 341,146

[1] For the three months ended September 30, 2014, 6.6 million shares associated with our stock options and 1.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the three months ended September 30, 2013, 6.2 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2014, 6.6 million shares associated with our stock options and 0.8 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2013, 5.5 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations.

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Income Taxes Valuation Allowance (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Valuation Allowance [Line Items]
Income Taxes Receivable	$ 7.6
UNITED STATES
Valuation Allowance [Line Items]
Tax Valuation Allowance Expense, Federal	372.0
CANADA
Valuation Allowance [Line Items]
Tax Valuation Allowance Expense, Federal	$ 60.7

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Condensed Consolidated Statements Of Equity (Parenthetical) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Statement of Stockholders' Equity [Abstract]
Income tax effect related to hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income	$ (8,455)	$ (17,833)
Income tax effect related to net change in derivative fair value	$ 0	$ 0

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Derivatives And Fair Value Measurements (Estimated Fair Value Of Derivative Instruments) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Current derivative assets	$ 66,098	$ 57,523
Noncurrent derivative assets	25,968	73,357
Current derivative liabilities	846	3,125
Noncurrent derivative liabilities	0	323
Asset Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	142,189	165,378
Liability Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities	50,969	37,946
Not Designated as Hedging Instrument [Member] | Asset Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	66,278	60,063
Noncurrent derivative assets	75,911	105,315
Current derivative liabilities	0	0
Noncurrent derivative liabilities	0	0
Not Designated as Hedging Instrument [Member] | Liability Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	180	2,540
Noncurrent derivative assets	49,943	31,958
Current derivative liabilities	846	3,125
Noncurrent derivative liabilities	$ 0	$ 323

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Derivatives And Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2014

Credit Risk Derivatives, at Fair Value, Net [Abstract]

Estimated Fair Value Of Derivative Instruments Under Input Levels

	Asset Derivatives				Liability Derivatives
	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
	(in thousands)				(in thousands)
Level 2 derivative instruments	$	74,312	$	107,395	$	846	$	3,448
Level 3 derivative instruments	17,754		23,485		—		—
Total	$	92,066	$	130,880	$	846	$	3,448

Changes In Level 3 Fair Values

	For the Three Months Ended September 30,
	2014			2013
	(in thousands)
Balance at beginning of period	$	(5,533	)	$	(9,873	)
Total gains (losses) for the period:
Unrealized gain (loss) on derivatives	24,829			24,080
Settlements in net derivative gains (losses)	(1,542		)	(3,302		)
Balance at end of period	$	17,754		$	10,905
Total gains (losses) included in net derivative gains (losses) attributable to the change in unrealized gains (losses) related to assets still held at the reporting date	$	24,485		$	24,026

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
Balance at beginning of period	$	23,485		$	(4,931	)
Total gains (losses) for the period:
Unrealized gain (loss) on derivatives	(6,488		)	24,618
Settlements in net derivative gains (losses)	757			(8,782		)
Balance at end of period	$	17,754		$	10,905
Total gains (losses) included in net derivative gains (losses) attributable to the change in unrealized gains (losses) related to assets still held at the reporting date	$	(2,476	)	$	26,788

Marketable Securities

	December 31, 2013
	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Market Value
	(in thousands)
Marketable securities (held-to-maturity)
Time deposits	$	29,419	$	—	$	(22	)	$	29,397
Commercial paper	136,924		27		(25		)	136,926
Marketable securities	$	166,343	$	27	$	(47	)	$	166,323

Price Collars And Swaps For Anticipated Natural Gas And NGL Production

Production Year	Daily Production Volume
	Natural Gas	Natural Gas Basis Swaps
	MMcfd	MMcfd
Remaining 2014 (1)	170	40
2015	150	—
2016-2021	40	—

⁽¹⁾  Our natural gas basis swaps economically hedge the AECO basis adjustment from NYMEX.

Estimated Fair Value Of Derivative Instruments

	Asset Derivatives				Liability Derivatives
	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
	(in thousands)				(in thousands)
Derivatives not designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	66,278	$	60,063	$	180	$	2,540
Noncurrent derivative assets	75,911		105,315		49,943		31,958
Current derivative liabilities	—		—		846		3,125
Noncurrent derivative liabilities	—		—		—		323
Total derivatives not designated as hedges	$	142,189	$	165,378	$	50,969	$	37,946

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Derivatives And Fair Value Measurements (Carrying Value Of Derivatives) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivatives, Fair Value [Line Items]
Settlements in production revenue	$ (7,968)	$ (11,139)	$ (20,939)	$ (37,181)

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2014

Long-term Debt, Other Disclosures [Abstract]

Schedule Of Long-Term Debt Instruments

	September 30, 2014		December 31, 2013
	(in thousands)
Combined Credit Agreements	$	275,966	$	211,200
Second Lien Term Loan, net of unamortized discount	609,555		607,572
Second Lien Notes due 2019, net of unamortized discount	195,058		194,423
Senior notes due 2015, net of unamortized discount	—		10,472
Senior notes due 2016, net of unamortized discount	—		8,044
Senior notes due 2019, net of unamortized discount	293,744		293,243
Senior notes due 2021, net of unamortized discount	310,229		309,190
Senior subordinated notes due 2016	350,000		350,000
Total debt	2,034,552		1,984,144
Unamortized deferred gain-terminated interest rate swaps	3,292		4,802
Long-term debt	$	2,037,844	$	1,988,946

Schedule of Outstanding Debt

	Priority on Collateral and Structural Seniority (1)
	Highest priority						Lowest priority
	First Lien		Second Lien		Senior Unsecured		Senior Subordinated
	Combined Credit Agreements		Second Lien Term Loan	Second Lien Notes due 2019	2019 Senior Notes	2021 Senior Notes	Senior Subordinated Notes
Principal amount (1) (2)	$325 million		$625 million	$200 million	$298 million	$325 million	$350 million
Scheduled maturity date (3)	September 6, 2016		June 21, 2019	June 21, 2019	August 15, 2019	July 1, 2021	April 1, 2016
Springing maturity date (3)	October 1, 2015		January 1, 2016	January 1, 2016	N/A	N/A	N/A
Interest rate on outstanding borrowings at September 30, 2014 (4)	4.09%		7.00%	7.00%	9.125%	11.00%	7.125%
Base interest rate options (5) (6)	LIBOR, ABR, CDOR		LIBOR floor of 1.25%; ABR floor of 2.25%	LIBOR floor of 1.25%	N/A	N/A	N/A
Financial covenants (7) (9)	- Minimum current ratio of 1.0 - Minimum EBITDA to cash interest expense ratio of 1.10 - Maximum senior secured debt leverage ratio of 2.0		N/A	N/A	N/A	N/A	N/A
Significant restrictive covenants (8)(9)	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions - Limitations on derivatives and investments		- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens and 1st lien cap -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 (9)	Any time		Any time, subject to re-pricing event June 21, 2015: 101	Any time, subject to re-pricing event June 21, 2015: 101	August 15, 2014: 104.563 2015: 103.042 2016: 101.521 2017: par	July 1, 2019: 102.000 2020: par	Any time
Make-whole redemption (9)	N/A		N/A	N/A	N/A	Callable prior to July 1, 2019 at make-whole call price of Treasury +50 bps	N/A
Change of control (9)	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	Put at 101% of principal plus accrued interest
Equity clawback (9)	N/A		N/A	N/A	N/A	Redeemable until July 1, 2016 at 111.00%, plus accrued interest for up to 35%	N/A
Estimated fair value (10)	$276.0 million		$568.8 million	$182.0 million	$186.3 million	$213.7 million	$136.5 million

⁽¹⁾  Borrowings under the Amended and Restated U.S. Credit Facility, Second Lien Term Loan and Second Lien Notes due 2019 are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured (on a first priority basis with respect to the Amended and Restated U.S. Credit Facility and on a second priority basis with respect to the Second Lien Term Loan and the Second Lien Notes due 2019) 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, QPP Parent LLC and QPP Holdings LLC (collectively, the “Domestic Pledged Equity”), 65% of the equity interests of Quicksilver Resources Canada Inc. (“Quicksilver Canada”) and Quicksilver Production Partners Operating Ltd. (with respect to the Amended and Restated U.S. Credit Facility, on a ratable basis with borrowings under the Amended and Restated Canadian Credit Facility) and the majority of Quicksilver's domestic proved oil and gas properties and related assets, (the “Domestic Pledged Property”). 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, the Domestic Pledged Property, 100% of the equity interests of Quicksilver Canada (65% of which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and any Canadian restricted subsidiaries, under the Amended and Restated Canadian Credit Facility, and 65% of the equity interests of Quicksilver Production Partners Operating Ltd. (which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and the majority of Quicksilver Canada's oil and gas properties and related assets. 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, 2014.

⁽³⁾  The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the Senior Subordinated Notes, the Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Second Lien Term Loan and Second Lien Notes due 2019 are required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remain outstanding and (2) 91 days prior to the maturity of the Senior Subordinated Notes if on the applicable date the amount remaining outstanding is greater than $100 million. As of September 30, 2014, as presently structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would be due on October 1, 2015 and the Second Lien Term Loan and Second Lien Notes due 2019 would be due on January 1, 2016.

⁽⁴⁾  Represents the weighted average borrowing rate payable to lenders.

⁽⁵⁾  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 2.75% and 3.75%, (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 1.75% and 2.75%. 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 Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.50%.

⁽⁶⁾  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 2.75% and 3.75%, (ii) the Canadian Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75%, (iii) the U.S. Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75% and (iv) adjusted LIBOR (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%. 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 Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.50%.

⁽⁷⁾  As of September 30, 2014, the future minimum required interest coverage ratio for the Combined Credit Agreements is as follows:

Period	Interest Coverage Ratio	Period	Interest Coverage Ratio
Q4 2014	1.10	Q4 2015	1.20
Q1 2015	1.10	Q1 2016	1.50
Q2 2015	1.15	Q2 2016	2.00
Q3 2015	1.15

In November 2014, the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:

	Minimum EBITDAX Covenant
	(in millions)
Three months ending December 31, 2014	$	30.0
Six months ending March 31, 2015	59.0
Nine months ending June 30, 2015	87.25
Twelve months ending September 30, 2015	120.5
Twelve months ending December 31, 2015	122.0

⁽⁸⁾  Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.

⁽⁹⁾  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.

⁽¹⁰⁾  The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). Our Second Lien Term Loan and Second Lien Notes due 2019 feature variable interest rates and we estimate their fair value by using market quotations based on recent trade activity (“Level 3” input). We consider our Combined Credit Agreements which have a variable interest rate to have a fair value equal to their carrying value (“Level 1” input).

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Condensed Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Operating activities:
Net income (loss)	$ 71,171	$ (193,397)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion	42,584	47,911
Impairment of Oil and Gas Properties	135	0
Deferred income tax expense (benefit)	8,455	17,833
Non-cash (gain) loss from hedging and derivative activities	6,731	(12,223)
Stock-based compensation	9,146	13,699
Non-cash interest expense	8,441	23,643
Fortune Creek accretion	11,605	14,490
Other	(347)	3,622
Changes in assets and liabilities
Accounts receivable	(1,936)	7,398
Prepaid expenses and other assets	1,747	344
Accounts payable	(12,472)	(17,973)
Increase (Decrease) in Income Taxes Payable, Net of Income Taxes Receivable	(432)	(148)
Accrued and other liabilities	(7,469)	(31,950)
Net cash flow provided by (used in) by operating activities	(4,983)	(81,103)
Investing activities:
Purchases of property, plant and equipment	(111,444)	(78,549)
Proceeds from sale of properties and equipment	1,942	2,994
Payments to acquire marketable securities	(55,890)	(142,823)
Proceeds from Sale and Maturity of Held-to-maturity Securities	222,025	13,178
Net cash provided by (used in) investing activities	152,220	300,515
Financing activities:
Issuance of debt	243,184	1,173,306
Repayments of debt	(193,689)	(1,308,382)
Debt issuance costs paid	(225)	(25,868)
Distribution of Fortune Creek Partnership funds	(37,113)	(8,079)
Purchase of treasury stock	(2,388)	(1,472)
Net cash provided by financing activities	9,769	(170,495)
Effect of exchange rate changes in cash	2,216	2,610
Net increase (decrease) in cash	159,222	51,527
Cash at beginning of period	89,103	4,951
Cash at end of period	248,325	56,478
Tokyo Gas [Member]
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Gain (Loss) on Disposition of Oil and Gas and Timber Property	0	(341,146)
Investing activities:
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0	463,418
Sandwash Basin [Member]
Investing activities:
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	95,587	0
Synergy [Member]
Investing activities:
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	$ 0	$ 42,297

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Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets
Cash	$ 248,325	$ 89,103
Marketable Securities, Current	0	166,343
Cash, Cash Equivalents, and Short-term Investments	248,325	255,446
Accounts receivable - net of allowance for doubtful accounts	59,491	58,645
Derivative assets at fair value	66,098	57,523
Other current assets	22,386	22,346
Total current assets	396,300	393,960
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $218,398 and $221,605, respectively)	608,572	640,443
Property, Plant and Equipment, Other, Net	203,908	220,362
Property, plant and equipment, net of accumulated depletion and depreciation	812,480	860,805
Derivative assets at fair value	25,968	73,357
Other assets	33,509	41,604
Total assets	1,268,257	1,369,726
Current liabilities
Accounts payable	13,587	28,822
Accrued liabilities	94,091	102,850
Derivative liabilities at fair value	846	3,125
Total current liabilities	108,524	134,797
Long-term debt	2,037,844	1,988,946
Partnership liability	94,651	126,132
Asset retirement obligations	105,480	106,256
Derivative liabilities at fair value	0	323
Other liabilities	19,242	19,242
Commitments and contingencies (Note 7)
Stockholders' equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding	0	0
Common stock, $0.01 par value, 400,000,000 shares authorized, and 187,222,654 and 183,994,879 shares issued, respectively	1,872	1,840
Paid in capital in excess of par value	779,206	770,092
Treasury stock of 7,444,372 and 6,698,640 shares, respectively	(53,810)	(51,422)
Accumulated other comprehensive income	82,780	109,881
Retained deficit	(1,907,532)	(1,836,361)
Total stockholders' equity	(1,097,484)	(1,005,970)
Total liabilities and stockholders' equity	$ 1,268,257	$ 1,369,726

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Earnings Per Share

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Earnings Per Share

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,
	2014			2013			2014			2013
	(in thousands, except per share data)
Net income (loss) attributable to Quicksilver	$	23,757		$	10,577		$	(71,171	)	$	193,397
Basic income allocable to participating securities (1)	(772		)	(312		)	—			(5,111		)
Income (loss) available to shareholders	$	22,985		$	10,265		$	(71,171	)	$	188,286
Weighted average common shares – basic	173,936			171,682			173,783			171,403
Effect of dilutive securities (2)
Share-based compensation awards	216			311			—			170
Weighted average common shares – diluted	174,152			171,993			173,783			171,573
Earnings (loss) per common share – basic	$	0.13		$	0.06		$	(0.41	)	$	1.10
Earnings (loss) per common share – diluted	$	0.13		$	0.06		$	(0.41	)	$	1.10

⁽¹⁾  Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, should be included in computing earnings per share using the two-class method. Participating securities, however, do not participate in undistributed net losses because there is no contractual obligation to do so.

⁽²⁾  For the three months ended September 30, 2014, 6.6 million shares associated with our stock options and 1.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the three months ended September 30, 2013, 6.2 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2014, 6.6 million shares associated with our stock options and 0.8 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2013, 5.5 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations.

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Document And Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Entity Registrant Name	QUICKSILVER RESOURCES INC
Entity Central Index Key	0001060990
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		179,983,515

XML

Condensed Consolidating Financial Information

9 Months Ended

Sep. 30, 2014

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Financial Information

CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Note 18 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains a more complete description of our guarantor, non-guarantor, restricted and unrestricted subsidiaries under the indentures for our Senior Notes and Senior Subordinated Notes.

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

Condensed Consolidating Balance Sheets

	September 30, 2014
	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)
ASSETS
Current assets	$	338,424		$	13,096		$	65,733		$	(23,193	)	$	394,060		$	(455	)	$	1,746	$	949		$	396,300
Property and equipment	417,921			14,625			305,197			—			737,743			—			74,737		—			812,480
Investment in subsidiaries (equity method)	(227,994		)	—			(23,409		)	227,994			(23,409		)	(23,429		)	—		46,838			—
Other assets	457,285			—			15,473			(413,281		)	59,477			—			—		—			59,477
Total assets	$	985,636		$	27,721		$	362,994		$	(208,480	)	$	1,167,871		$	(23,884	)	$	76,483	$	47,787		$	1,268,257
LIABILITIES AND EQUITY
Current liabilities	$	103,042		$	13,401		$	11,064		$	(23,193	)	$	104,314		$	(475	)	$	3,736	$	949		$	108,524
Long-term liabilities	1,980,078			19,241			575,003			(413,281		)	2,161,041			—			1,525		94,651			2,257,217
Stockholders' equity	(1,097,484		)	(4,921		)	(223,073		)	227,994			(1,097,484		)	(23,409		)	71,222		(47,813		)	(1,097,484		)
Total liabilities and equity	$	985,636		$	27,721		$	362,994		$	(208,480	)	$	1,167,871		$	(23,884	)	$	76,483	$	47,787		$	1,268,257

	December 31, 2013
	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)
ASSETS
Current assets	$	349,586		$	10,735		$	53,034		$	(19,642	)	$	393,713		$	909		$	1,110	$	(1,772	)	$	393,960
Property and equipment	455,822			15,486			307,865			—			779,173			—			81,632		—			860,805
Investment in subsidiaries (equity method)	(217,852		)	—			(33,840		)	217,852			(33,840		)	(33,840		)	—		67,680			—
Other assets	472,792			—			32,892			(390,723		)	114,961			—			—		—			114,961
Total assets	$	1,060,348		$	26,221		$	359,951		$	(192,513	)	$	1,254,007		$	(32,931	)	$	82,742	$	65,908		$	1,369,726
LIABILITIES AND EQUITY
Current liabilities	$	124,275		$	12,210		$	17,167		$	(19,642	)	$	134,010		$	888		$	1,671	$	(1,772	)	$	134,797
Long-term liabilities	1,942,043			19,242			542,659			(390,723		)	2,113,221			—			1,546		126,132			2,240,899
Stockholders' equity	(1,005,970		)	(5,231		)	(199,875		)	217,852			(993,224		)	(33,819		)	79,525		(58,452		)	(1,005,970		)
Total liabilities and equity	$	1,060,348		$	26,221		$	359,951		$	(192,513	)	$	1,254,007		$	(32,931	)	$	82,742	$	65,908		$	1,369,726

Condensed Consolidating Statements of Income

	For the Three Months Ended September 30, 2014
	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	$	120,513		$	427		$	42,558		$	—		$	163,498		$	—	$	4,271	$	(4,271	)	$	163,498
Operating expenses	72,868			341			27,648			—			100,857			—		2,128		(4,271		)	98,714
Equity in net earnings of subsidiaries	8,821			—			(1,458		)	(8,821		)	(1,458		)	2,144		—		(686		)	—
Operating income (loss)	56,466			86			13,452			(8,821		)	61,183			2,144		2,143		(686		)	64,784
Fortune Creek accretion	—			—			—			—			—			—		—		(3,602		)	(3,602		)
Interest expense and other	(37,613		)	86			(4,838		)	—			(42,365		)	—		1		—			(42,364		)
Income tax (expense) benefit	4,826			(30		)	65			78			4,939			—		—		—			4,939
Net income (loss)	$	23,679		$	142		$	8,679		$	(8,743	)	$	23,757		$	2,144	$	2,144	$	(4,288	)	$	23,757
Other comprehensive income (loss)	(11,564		)	—			(3,325		)	—			(14,889		)	—		—		—			(14,889		)
Equity in OCI of subsidiaries	(3,325		)	—			—			3,325			—			—		—		—			—
Comprehensive income (loss)	$	8,790		$	142		$	5,354		$	(5,418	)	$	8,868		$	2,144	$	2,144	$	(4,288	)	$	8,868

	For the Three Months Ended September 30, 2013
	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	$	114,021		$	192	$	38,903		$	—		$	153,116		$	—	$	5,674	$	(5,674	)	$	153,116
Operating expenses	73,594			68		30,360			—			104,022			—		2,693		(5,674		)	101,041
Tokyo Gas Transaction gain	7,974			—		—			—			7,974			—		—		—			7,974
Equity in net earnings of subsidiaries	3,854			—		(1,834		)	(3,854		)	(1,834		)	2,984		—		(1,150		)	—
Operating income (loss)	52,255			124		6,709			(3,854		)	55,234			2,984		2,981		(1,150		)	60,049
Fortune Creek accretion	—			—		—			—			—			—		—		(4,818		)	(4,818		)
Interest expense and other	(36,922		)	—		(1,769		)	—			(38,691		)	—		3		—			(38,688		)
Income tax (expense) benefit	(4,756		)	—		(1,210		)	—			(5,966		)	—		—		—			(5,966		)
Net income (loss)	$	10,577		$	124	$	3,730		$	(3,854	)	$	10,577		$	2,984	$	2,984	$	(5,968	)	$	10,577
Other comprehensive income (loss)	(6,114		)	—		(2,680		)	—			(8,794		)	—		—		—			(8,794		)
Equity in OCI of subsidiaries	(2,680		)	—		—			2,680			—			—		—		—			—
Comprehensive income (loss)	$	1,783		$	124	$	1,050		$	(1,174	)	$	1,783		$	2,984	$	2,984	$	(5,968	)	$	1,783

	For the Nine Months Ended September 30, 2014
	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	$	269,321		$	1,212		$	102,783		$	—		$	373,316		$	—	$	13,349	$	(13,349	)	$	373,316
Operating expenses	225,906			988			86,491			—			313,385			—		6,014		(13,349		)	306,050
Equity in net earnings of subsidiaries	2,864			—			(4,266		)	(2,864		)	(4,266		)	7,339		—		(3,073		)	—
Operating income (loss)	46,279			224			12,026			(2,864		)	55,665			7,339		7,335		(3,073		)	67,266
Fortune Creek accretion	—			—			—			—			—			—		—		(11,605		)	(11,605		)
Interest expense and other	(117,315		)	86			(8,526		)	—			(125,755		)	—		4		—			(125,751		)
Income tax (expense) benefit	(213		)	(78		)	(868		)	78			(1,081		)	—		—		—			(1,081		)
Net income (loss)	$	(71,249	)	$	232		$	2,632		$	(2,786	)	$	(71,171	)	$	7,339	$	7,339	$	(14,678	)	$	(71,171	)
Other comprehensive income (loss)	(20,252		)	—			(6,849		)	—			(27,101		)	—		—		—			(27,101		)
Equity in OCI of subsidiaries	(6,849		)	—			—			6,849			—			—		—		—			—
Comprehensive income (loss)	$	(98,350	)	$	232		$	(4,217	)	$	4,063		$	(98,272	)	$	7,339	$	7,339	$	(14,678	)	$	(98,272	)

	For the Nine Months Ended September 30, 2013
	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	$	334,848		$	608	$	111,862		$	—	$	447,318		$	—	$	16,736	$	(16,736	)	$	447,318
Operating expenses	256,810			206		89,559			—		346,575			—		7,552		(16,736		)	337,391
Tokyo Gas Transaction gain	341,146			—		—			—		341,146			—		—		—			341,146
Equity in net earnings of subsidiaries	(9,227		)	—		(5,300		)	9,227		(5,300		)	9,190		—		(3,890		)	—
Operating income (loss)	409,957			402		17,003			9,227		436,589			9,190		9,184		(3,890		)	451,073
Fortune Creek accretion	—			—		—			—		—			—		—		(14,490		)	(14,490		)
Interest expense and other	(200,639		)	—		(24,490		)	—		(225,129		)	—		6		—			(225,123		)
Income tax (expense) benefit	(15,921		)	—		(2,142		)	—		(18,063		)	—		—		—			(18,063		)
Net income (loss)	$	193,397		$	402	$	(9,629	)	$	9,227	$	193,397		$	9,190	$	9,190	$	(18,380	)	$	193,397
Other comprehensive income (loss)	(29,014		)	—		(9,100		)	—		(38,114		)	—		—		—			(38,114		)
Equity in OCI of subsidiaries	(9,100		)	—		—			9,100		—			—		—		—			—
Comprehensive income (loss)	$	155,283		$	402	$	(18,729	)	$	18,327	$	155,283		$	9,190	$	9,190	$	(18,380	)	$	155,283

Condensed Consolidating Statements of Cash Flows

	For the Nine Months Ended September 30, 2014
	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)
Net cash flow provided by (used in) operating activities	$	(39,474	)	$	(688	)	$	28,843		$	—		$	(11,319	)	$	—		$	6,336		$	—		$	(4,983	)
Purchases of property, plant and equipment	(88,119		)	(57		)	(23,247		)	—			(111,423		)	—			(21		)	—			(111,444		)
Investment in subsidiary	(1,246		)	—			(26,395		)	1,246			(26,395		)	(26,395		)	—			52,790			—
Proceeds from Southwestern Transaction	95,587			—			—			—			95,587			—			—			—			95,587
Proceeds from sale of properties and equipment	1,445			—			497			—			1,942			—			—			—			1,942
Purchases of marketable securities	(55,890		)	—			—			—			(55,890		)	—			—			—			(55,890		)
Maturities and sales of marketable securities	222,025			—			—			—			222,025			—			—			—			222,025
Net cash flow provided by (used in) investing activities	173,802			(57		)	(49,145		)	1,246			125,846			(26,395		)	(21		)	52,790			152,220
Issuance of debt	174,000			—			69,184			—			243,184			—			—			—			243,184
Repayments of debt	(138,651		)	—			(55,038		)	—			(193,689		)	—			—			—			(193,689		)
Debt issuance costs paid	(225		)	—			—			—			(225		)	—			—			—			(225		)
Intercompany note	(22,558		)	—			22,558			—			—			—			—			—			—
Intercompany financing	—			745			501			(1,246		)	—			—			—			—			—
Contribution received	—			—			—			—			—			26,395			26,395			(52,790		)	—
Distribution of Fortune Creek Partnership funds	—			—			—			—			—			—			(37,113		)	—			(37,113		)
Purchase of treasury stock	(2,388		)	—			—			—			(2,388		)	—			—			—			(2,388		)
Net cash flow provided by (used in) financing activities	10,178			745			37,205			(1,246		)	46,882			26,395			(10,718		)	(52,790		)	9,769
Effect of exchange rates on cash	—			—			(2,718		)	—			(2,718		)	—			4,934			—			2,216
Net increase (decrease) in cash and equivalents	144,506			—			14,185			—			158,691			—			531			—			159,222
Cash and equivalents at beginning of period	83,893			—			4,135			—			88,028			22			1,053			—			89,103
Cash and equivalents at end of period	$	228,399		$	—		$	18,320		$	—		$	246,719		$	22		$	1,584		$	—		$	248,325

	For the Nine Months Ended September 30, 2013
	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 by (used in) operating activities	$	(113,029	)	$	(19	)	$	25,517		$	(87,531	)	$	—	$	6,428		$	(81,103	)
Purchases of property, plant and equipment	(53,291		)	19			(24,752		)	(78,024		)	—		(525		)	(78,549		)
Proceeds from Tokyo Gas Transaction	463,418			—			—			$	463,418		—		—			463,418
Proceeds from Synergy transaction	42,297			—			—			42,297			—		—			42,297
Proceeds from sale of properties and equipment	2,977			—			17			2,994			—		—			2,994
Purchases of marketable securities	(142,823		)	—			—			$	(142,823	)	—		—			(142,823		)
Maturities and sales of marketable securities	13,178			—			—			$	13,178		—		—			13,178
Net cash flow provided by (used in)  investing activities	325,756			19			(24,735		)	301,040			—		(525		)	300,515
Issuance of debt	1,170,266			—			3,040			1,173,306			—		—			1,173,306
Repayments of debt	(1,157,969		)	—			(150,413		)	(1,308,382		)	—		—			(1,308,382		)
Debt issuance costs paid	(25,868		)	—			—			(25,868		)	—		—			(25,868		)
Intercompany note	(147,103		)	—			147,103			—			—		—			—
Distribution of Fortune Creek Partnership funds	—			—			—			—			—		(8,079		)	(8,079		)
Purchase of treasury stock	(1,472		)	—			—			(1,472		)	—		—			(1,472		)
Net cash flow used in financing activities	(162,146		)	—			(270		)	(162,416		)	—		(8,079		)	(170,495		)
Effect of exchange rates on cash	—			—			(512		)	(512		)	—		3,122			2,610
Net increase in cash and equivalents	50,581			—			—			50,581			—		946			51,527
Cash and equivalents at beginning of period	4,618			—			—			4,618			—		333			4,951
Cash and equivalents at end of period	$	55,199		$	—		$	—		$	55,199		$	—	$	1,279		$	56,478

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, par value	$ 0.01	$ 0.01
Unevaluated costs of oil and gas properties	$ 218,398	$ 221,605
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares issued	187,222,654	183,994,879
Treasury stock, shares	7,444,372	6,698,640

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Long-Term Debt

9 Months Ended

Sep. 30, 2014

Long-term Debt, Other Disclosures [Abstract]

Long-Term Debt

LONG-TERM DEBT

Long-term debt consisted of the following:

	September 30, 2014		December 31, 2013
	(in thousands)
Combined Credit Agreements	$	275,966	$	211,200
Second Lien Term Loan, net of unamortized discount	609,555		607,572
Second Lien Notes due 2019, net of unamortized discount	195,058		194,423
Senior notes due 2015, net of unamortized discount	—		10,472
Senior notes due 2016, net of unamortized discount	—		8,044
Senior notes due 2019, net of unamortized discount	293,744		293,243
Senior notes due 2021, net of unamortized discount	310,229		309,190
Senior subordinated notes due 2016	350,000		350,000
Total debt	2,034,552		1,984,144
Unamortized deferred gain-terminated interest rate swaps	3,292		4,802
Long-term debt	$	2,037,844	$	1,988,946

Combined Credit Agreements

The Combined Credit Agreements’ global borrowing base was $325 million and the global letter of credit capacity was $280 million as of September 30, 2014. At September 30, 2014, we had $6.7 million available under the Combined Credit Agreements.

In November 2014, the Combined Credit Agreements' global borrowing base was reaffirmed at $325 million and the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:

	Minimum EBITDAX Covenant
	(in millions)
Three months ending December 31, 2014	$	30.0
Six months ending March 31, 2015	59.0
Nine months ending June 30, 2015	87.25
Twelve months ending September 30, 2015	120.5
Twelve months ending December 31, 2015	122.0

Additionally, the Combined Credit Agreements were amended changing certain definitions that impact the calculation of EBITDAX in both the November 2014 amendment and the April 2014 amendment and we permanently reduced the aggregate maximum credit amounts under the Combined Credit Agreements from $1.75 billion to $650 million in April 2014 and to $450 million in November 2014.

Senior Notes due 2015 and Senior Notes due 2016

In April 2014, we redeemed all remaining outstanding notes under our Senior Notes due 2015 and Senior Notes due 2016. Our Senior Notes due 2015 were redeemed at 101.938% of the principal amount plus accrued and unpaid interest representing a total payment of $10.9 million and our Senior Notes due 2016 were redeemed at 105.875% of the principal amount plus accrued and unpaid interest representing a total payment of $8.9 million.

Indenture Restrictions

We have an incurrence test under our indentures applicable to debt, restricted payments, mergers and consolidations and designation of unrestricted subsidiaries that requires EBITDA to exceed interest expense by 2.25 times. At September 30, 2014, we did not meet this test and, as a result, we are limited in our ability to, among other things, incur additional debt, except for specific baskets. We do retain, however, the ability to utilize the full borrowing capacity under our Combined Credit Agreements and to refinance existing debt. Not meeting this ratio does not represent an event of default under our debt. We cannot predict when or if we will meet the incurrence test.

We retained a portion of the cash received from our asset sales. Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.

Summary of All Outstanding Debt

The following table summarizes certain significant aspects of our long-term debt outstanding at September 30, 2014.

	Priority on Collateral and Structural Seniority (1)
	Highest priority						Lowest priority
	First Lien		Second Lien		Senior Unsecured		Senior Subordinated
	Combined Credit Agreements		Second Lien Term Loan	Second Lien Notes due 2019	2019 Senior Notes	2021 Senior Notes	Senior Subordinated Notes
Principal amount (1) (2)	$325 million		$625 million	$200 million	$298 million	$325 million	$350 million
Scheduled maturity date (3)	September 6, 2016		June 21, 2019	June 21, 2019	August 15, 2019	July 1, 2021	April 1, 2016
Springing maturity date (3)	October 1, 2015		January 1, 2016	January 1, 2016	N/A	N/A	N/A
Interest rate on outstanding borrowings at September 30, 2014 (4)	4.09%		7.00%	7.00%	9.125%	11.00%	7.125%
Base interest rate options (5) (6)	LIBOR, ABR, CDOR		LIBOR floor of 1.25%; ABR floor of 2.25%	LIBOR floor of 1.25%	N/A	N/A	N/A
Financial covenants (7) (9)	- Minimum current ratio of 1.0 - Minimum EBITDA to cash interest expense ratio of 1.10 - Maximum senior secured debt leverage ratio of 2.0		N/A	N/A	N/A	N/A	N/A
Significant restrictive covenants (8)(9)	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions - Limitations on derivatives and investments		- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens and 1st lien cap -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 (9)	Any time		Any time, subject to re-pricing event June 21, 2015: 101	Any time, subject to re-pricing event June 21, 2015: 101	August 15, 2014: 104.563 2015: 103.042 2016: 101.521 2017: par	July 1, 2019: 102.000 2020: par	Any time
Make-whole redemption (9)	N/A		N/A	N/A	N/A	Callable prior to July 1, 2019 at make-whole call price of Treasury +50 bps	N/A
Change of control (9)	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	Put at 101% of principal plus accrued interest
Equity clawback (9)	N/A		N/A	N/A	N/A	Redeemable until July 1, 2016 at 111.00%, plus accrued interest for up to 35%	N/A
Estimated fair value (10)	$276.0 million		$568.8 million	$182.0 million	$186.3 million	$213.7 million	$136.5 million

⁽¹⁾  Borrowings under the Amended and Restated U.S. Credit Facility, Second Lien Term Loan and Second Lien Notes due 2019 are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured (on a first priority basis with respect to the Amended and Restated U.S. Credit Facility and on a second priority basis with respect to the Second Lien Term Loan and the Second Lien Notes due 2019) 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, QPP Parent LLC and QPP Holdings LLC (collectively, the “Domestic Pledged Equity”), 65% of the equity interests of Quicksilver Resources Canada Inc. (“Quicksilver Canada”) and Quicksilver Production Partners Operating Ltd. (with respect to the Amended and Restated U.S. Credit Facility, on a ratable basis with borrowings under the Amended and Restated Canadian Credit Facility) and the majority of Quicksilver's domestic proved oil and gas properties and related assets, (the “Domestic Pledged Property”). 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, the Domestic Pledged Property, 100% of the equity interests of Quicksilver Canada (65% of which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and any Canadian restricted subsidiaries, under the Amended and Restated Canadian Credit Facility, and 65% of the equity interests of Quicksilver Production Partners Operating Ltd. (which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and the majority of Quicksilver Canada's oil and gas properties and related assets. 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, 2014.

⁽³⁾  The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the Senior Subordinated Notes, the Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Second Lien Term Loan and Second Lien Notes due 2019 are required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remain outstanding and (2) 91 days prior to the maturity of the Senior Subordinated Notes if on the applicable date the amount remaining outstanding is greater than $100 million. As of September 30, 2014, as presently structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would be due on October 1, 2015 and the Second Lien Term Loan and Second Lien Notes due 2019 would be due on January 1, 2016.

⁽⁴⁾  Represents the weighted average borrowing rate payable to lenders.

⁽⁵⁾  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 2.75% and 3.75%, (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 1.75% and 2.75%. 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 Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.50%.

⁽⁶⁾  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 2.75% and 3.75%, (ii) the Canadian Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75%, (iii) the U.S. Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75% and (iv) adjusted LIBOR (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%. 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 Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.50%.

⁽⁷⁾  As of September 30, 2014, the future minimum required interest coverage ratio for the Combined Credit Agreements is as follows:

Period	Interest Coverage Ratio	Period	Interest Coverage Ratio
Q4 2014	1.10	Q4 2015	1.20
Q1 2015	1.10	Q1 2016	1.50
Q2 2015	1.15	Q2 2016	2.00
Q3 2015	1.15

In November 2014, the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:

	Minimum EBITDAX Covenant
	(in millions)
Three months ending December 31, 2014	$	30.0
Six months ending March 31, 2015	59.0
Nine months ending June 30, 2015	87.25
Twelve months ending September 30, 2015	120.5
Twelve months ending December 31, 2015	122.0

⁽⁸⁾  Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.

⁽⁹⁾  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.

⁽¹⁰⁾  The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). Our Second Lien Term Loan and Second Lien Notes due 2019 feature variable interest rates and we estimate their fair value by using market quotations based on recent trade activity (“Level 3” input). We consider our Combined Credit Agreements which have a variable interest rate to have a fair value equal to their carrying value (“Level 1” input).

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Property, Plant And Equipment

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

Property, Plant And Equipment

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	September 30, 2014			December 31, 2013
	(in thousands)
Oil and gas properties
Subject to depletion	$	5,635,307		$	5,687,557
Unevaluated costs	218,398			221,605
Accumulated depletion	(5,245,133		)	(5,268,719		)
Net oil and gas properties	608,572			640,443
Other property and equipment
Pipelines and processing facilities	332,710			347,093
General properties	71,049			72,125
Accumulated depreciation	(199,851		)	(198,856		)
Net other property and equipment	203,908			220,362
Property, plant and equipment, net of accumulated depletion and depreciation	$	812,480		$	860,805

We recognized other property and equipment impairment charges of $0.1 million in 2014 for pipeline in Texas.

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Property, Plant And Equipment (Tables)

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

	September 30, 2014			December 31, 2013
	(in thousands)
Oil and gas properties
Subject to depletion	$	5,635,307		$	5,687,557
Unevaluated costs	218,398			221,605
Accumulated depletion	(5,245,133		)	(5,268,719		)
Net oil and gas properties	608,572			640,443
Other property and equipment
Pipelines and processing facilities	332,710			347,093
General properties	71,049			72,125
Accumulated depreciation	(199,851		)	(198,856		)
Net other property and equipment	203,908			220,362
Property, plant and equipment, net of accumulated depletion and depreciation	$	812,480		$	860,805

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Segment Information

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Segment Information

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. In Canada, our midstream operation is the Fortune Creek partnership. Revenue earned by Fortune Creek for the gathering and processing of our gas is eliminated on a consolidated basis as is the GPT recognized by our producing properties. Based on the immateriality of our midstream segment, we have combined our U.S. and Canadian midstream information. We evaluate performance based on operating income and property and equipment costs incurred.

	Exploration & Production												Quicksilver Consolidated
	U.S.		Canada		Midstream		Corporate			Elimination
For the Three Months Ended September 30:	(in thousands)
2014
Revenue	$	120,513	$	42,072	$	5,184	$	—		$	(4,271	)	$	163,498
DD&A	8,096		4,171		1,256		446			—			13,969
Impairment expense	—		—		135		—			—			135
Operating income (loss)	57,809		16,364		2,367		(11,756		)	—			64,784
Property and equipment costs incurred	20,912		7,254		72		218			—			28,456
2013
Revenue	$	114,002	$	38,407	$	6,381	$	—		$	(5,674	)	$	153,116
DD&A	8,402		4,114		1,300		574			—			14,390
Operating income (loss)	56,911		11,076		3,107		(11,045		)	—			60,049
Property and equipment costs incurred	15,147		4,288		1,615		(329		)	—			20,721
For the Nine Months Ended September 30:
2014
Revenue	$	269,310	$	101,198	$	16,157	$	—		$	(13,349	)	$	373,316
DD&A	23,652		13,779		3,744		1,409			—			42,584
Impairment expense	—		—		135		—			—			135
Operating income (loss)	78,891		20,199		7,700		(39,524		)	—			67,266
Property and equipment costs incurred	85,814		20,924		83		763			—			107,584
2013
Revenue	$	334,804	$	110,052	$	19,198	$	—		$	(16,736	)	$	447,318
DD&A	29,745		12,458		3,947		1,761			—			47,911
Operating income (loss)	456,624		30,126		9,593		(45,270		)	—			451,073
Property and equipment costs incurred	50,459		9,972		2,369		9,655			—			72,455
Property, plant and equipment-net
September 30, 2014	$	415,163	$	303,827	$	89,362	$	4,128		$	—		$	812,480
December 31, 2013	451,840		306,423		97,118		5,424			—			860,805
Total assets
September 30, 2014	796,931		362,994		104,204		4,128			—			$	1,268,257
December 31, 2013	895,388		359,951		108,963		5,424			—			1,369,726

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Fortune Creek

9 Months Ended

Sep. 30, 2014

Equity Method Investments and Joint Ventures [Abstract]

Fortune Creek

FORTUNE CREEK

Note 15 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains additional information on Fortune Creek. In March 2014, we agreed with KKR to an amendment to extend the ending date of the minimum gross capital expenditures requirement, of which C$120 million remains, to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset and to broaden allowable spending to include acquisitions of producing properties that utilize partnership assets. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by C$0.13 per Mcf until at least 2016. We do not expect to be able to satisfy these capital expenditure requirements with our cash on hand, committed financing or cash flow from operations and will need to obtain additional debt or equity financing or sell assets, which we may not be able to do on satisfactory terms, or at all.

We committed gas production from our Horn River Asset for ten years beginning 2012, as more fully described below. KKR contributed C$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.

The firm gathering agreement with Fortune Creek is guaranteed by us. 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. Fortune Creek has made cash distributions to KKR, which are reported as cash used in financing activities.

Based on a quarterly 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.

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Income Taxes

9 Months Ended

Sep. 30, 2014

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

Note 13 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains additional information about our income taxes. At September 30, 2014, our U.S. and Canadian valuation allowances are $372.0 million and $60.7 million, respectively, which reduce our net deferred tax assets to a zero value as we continue to believe that it is not more likely than not that we will realize the deferred tax assets primarily related to our cumulative net operating losses. Income tax recognized for the three and nine months ended September 30, 2014 is a result of hedge gains previously deferred in AOCI being realized during the periods and the net tax impact being recognized, partially offset by a refund of $7.6 million filed in September 2014.

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Commitments And Contingencies

9 Months Ended

Sep. 30, 2014

Loss Contingency [Abstract]

Commitments And Contingencies

COMMITMENTS AND CONTINGENCIES

In each of July 2011 and June 2012, we received a subpoena duces tecum from the SEC requesting certain documents. In July 2014, the SEC notified us that the staff has completed its investigation and does not intend to recommend an enforcement action by the SEC against us.

Note 14 to the consolidated financial statements in our 2013 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, 2014.

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Quicksilver Stockholders' Equity

9 Months Ended

Sep. 30, 2014

Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]

Quicksilver Stockholders' Equity

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, 2014 and December 31, 2013, we had 179.8 million and 177.3 million shares of common stock outstanding, respectively.

Stock Options

No options have been granted during 2014. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the nine months endedSeptember 30, 2013:

Weighted avg grant date fair value	$1.05
Weighted avg risk-free interest rate	1.31%
Expected life	4.9 years
Wtd avg volatility	69.0%
Expected dividends	—

The following table summarizes our stock option activity for the nine months endedSeptember 30, 2014:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
					(in years)	(in thousands)
Outstanding at January 1, 2014	6,771,578		$	7.82
Forfeited	(44,950	)	1.65
Expired	(111,494	)	9.83
Outstanding at September 30, 2014	6,615,134		$	7.83	5.4	$	—
Exercisable at September 30, 2014	5,232,903		$	9.18	4.6	$	—

As of September 30, 2014, we estimate that a total of 6.3 million stock options will vest including those options already exercisable. As of September 30, 2014, the unrecognized compensation cost related to outstanding unvested stock options was $1.0 million, which is expected to be recognized in expense through August 2016. Compensation expense related to stock options of $1.1 million and $3.2 million was recognized for the nine months endedSeptember 30, 2014 and 2013, respectively.

Restricted Stock and Stock Units

The following table summarizes our restricted stock and stock unit activity for the nine months endedSeptember 30, 2014:

	Payable in shares				Payable in cash
	Shares		Weighted Average Grant Date Fair Value		Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2014	5,668,090		$	3.90	1,572,341		$	3.69
Granted	4,765,425		2.64		—		—
Vested	(2,559,959	)	4.86		(631,275	)	4.29
Forfeited	(348,554	)	3.09		(33,458	)	3.20
Outstanding at September 30, 2014	7,525,002		$	2.82	907,608		$	3.32

As of September 30, 2014, the unrecognized compensation cost related to outstanding unvested restricted stock was $14.8 million, which is expected to be recognized in expense through July 2017. Grants of restricted stock and RSUs during the nine months endedSeptember 30, 2014 had an estimated grant date fair value of $12.6 million. The fair value of outstanding RSUs to be settled in cash was $0.5 million at September 30, 2014. For the nine months endedSeptember 30, 2014 and 2013, compensation expense related to restricted stock and RSUs of $8.4 million and $12.2 million, respectively, was recognized. The total fair value of shares vested during the nine months endedSeptember 30, 2014 was $10.2 million.

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Derivatives And Fair Value Measurements (Price Collars And Swaps For Anticipated Natural Gas And NGL Production) (Details)	9 Months Ended
	Sep. 30, 2014 MMcf
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Gas 2014, MMcfd	170
Gas 2015, MMcfd	150
Gas 2016-2021, MMcfd	40
Anticipated Natural Gas Basis Swap Production For 2014	40
Anticipated Natural Gas Basis Swap Production For 2015	0
Anticipated Natural Gas Basis Swap Production for 2016-2021	0

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Earnings Per Share (Reconciliation Of Components Used To Compute Basic And Diluted Net Income Per Common Share) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income (loss) attributable to Quicksilver	$ 23,757		$ 10,577		$ (71,171)		$ 193,397
Undistributed Earnings (Loss) Allocated to Participating Securities, Basic	772	[1]	312	[1]	0	[1]	5,111	[1]
Income (loss) available to shareholders	$ 22,985		$ 10,265		$ (71,171)		$ 188,286
Weighted Average Number of Shares Outstanding, Basic	173,936,000		171,682,000		173,783,000		171,403,000
Share-based compensation awards	216,000	[2]	311,000	[2]	0	[2]	170,000	[2]
Weighted Average Number of Shares Outstanding, Diluted	174,152,000		171,993,000		173,783,000		171,573,000
Earnings (loss) per common share - basic	$ 0.13		$ 0.06		$ (0.41)		$ 1.10
Earnings (loss) per common share - diluted	$ 0.13	[2]	$ 0.06	[2]	$ (0.41)	[2]	$ 1.10	[2]
Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive shares excluded from the diluted share calculation	6,600,000		6,200,000		6,600,000		5,500,000
Restricted Stock Units (RSUs) [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive shares excluded from the diluted share calculation	1,200,000		200,000		800,000		200,000

[1] Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, should be included in computing earnings per share using the two-class method. Participating securities, however, do not participate in undistributed net losses because there is no contractual obligation to do so.

[2] For the three months ended September 30, 2014, 6.6 million shares associated with our stock options and 1.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the three months ended September 30, 2013, 6.2 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2014, 6.6 million shares associated with our stock options and 0.8 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2013, 5.5 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations.

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Transactions With Related Parties

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

Transactions With Related Parties

TRANSACTIONS AND OTHER MATTERS WITH RELATED PARTIES

As of September 30, 2014, members of the Darden family and entities controlled by them beneficially owned approximately 30% of our outstanding common stock. Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.

During the first nine months of 2013, we paid $0.3 million 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 less than $0.1 million for the first nine months of 2014 and 2013.

In August 2013, we paid $0.2 million in commission to an entity controlled by members of the Darden family in connection with the sublease of a portion of our office space.

Thomas Darden, brother of Glenn Darden and Anne Darden Self, retired as an employee on December 31, 2013, and resigned from the board of directors effective September 1, 2014. During the first nine months of 2014, consulting fee payments of $405,000, office allowance payments of $112,500 and COBRA payments of $39,000 were made to Mr. Darden. Additionally, in accordance with the agreement related to his retirement signed in May 2013 and following the execution and non-revocation of a release agreement satisfactory to us, we paid Mr. Darden a cash bonus of $286,650 and an equity bonus in the form of 72,662 fully vested shares having a grant date fair value equal to $191,100 in March 2014.

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Reconciliation Of Components Used To Compute Basic And Diluted Earnings (Loss) Per Common Share

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands, except per share data)
Net income (loss) attributable to Quicksilver	$	23,757		$	10,577		$	(71,171	)	$	193,397
Basic income allocable to participating securities (1)	(772		)	(312		)	—			(5,111		)
Income (loss) available to shareholders	$	22,985		$	10,265		$	(71,171	)	$	188,286
Weighted average common shares – basic	173,936			171,682			173,783			171,403
Effect of dilutive securities (2)
Share-based compensation awards	216			311			—			170
Weighted average common shares – diluted	174,152			171,993			173,783			171,573
Earnings (loss) per common share – basic	$	0.13		$	0.06		$	(0.41	)	$	1.10
Earnings (loss) per common share – diluted	$	0.13		$	0.06		$	(0.41	)	$	1.10

⁽¹⁾  Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, should be included in computing earnings per share using the two-class method. Participating securities, however, do not participate in undistributed net losses because there is no contractual obligation to do so.

⁽²⁾  For the three months ended September 30, 2014, 6.6 million shares associated with our stock options and 1.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the three months ended September 30, 2013, 6.2 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2014, 6.6 million shares associated with our stock options and 0.8 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the nine months ended September 30, 2013, 5.5 million shares associated with our stock options and 0.2 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations.

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Quicksilver Stockholders' Equity (Stock Option Activity) (Details) (USD $)	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Equity Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 1,100,000	$ 3,200,000
Outstanding at end of period, Shares	6,300,000
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at beginning of period, Shares	6,771,578
Forfeited, Shares	(44,950)
Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price	$ 1.65
Expired, Shares	(111,494)
Outstanding at end of period, Shares	6,615,134
Outstanding at beginning of period, Wtd Avg Exercise Price	$ 7.82
Exercisable at end of period, Shares	5,232,903
Expired, Wtd Avg Exercise Price	$ 9.83
Outstanding at end of period, Wtd Avg Exercise Price	$ 7.83
Exercisable at end of period, Wtd Avg Exercise Price	$ 9.18
Outstanding at end of period, Wtd Avg Remaining Contractual Life, Years	5 years 164 days
Exercisable at end of period, Wtd Avg Remaining Contractual Life, Years	4 years 236 days
Outstanding at end of period, Aggregate Intrinsic Value	0
Exercisable at end of period, Aggregate Intrinsic Value	$ 0

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Long-Term Debt (Schedule Of Long-Term Debt Instruments) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt	$ 2,034,552	$ 1,984,144
Deferred Gain (Loss) on Discontinuation of Interest Rate Fair Value Hedge	3,292	4,802
Long-term Debt, Excluding Current Maturities	2,037,844	1,988,946
Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	275,966	211,200
Senior Secured Second Lien Credit Facility [Member]
Debt Instrument [Line Items]
Secured Long-term Debt, Noncurrent	609,555	607,572
Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Secured Long-term Debt, Noncurrent	195,058	194,423
Senior Notes Due 2015 [Member]
Debt Instrument [Line Items]
Senior Notes	0	10,472
Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Senior Notes	0	8,044
Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Senior Notes	293,744	293,243
Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Senior Notes	310,229	309,190
Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Subordinated Long-term Debt, Noncurrent	$ 350,000	$ 350,000

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Condensed Consolidated Statements Of Equity (USD $) In Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Stockholders' Equity, Total [Member]
Balances at Dec. 31, 2012		$ 1,790	$ 751,394	$ (49,495)	$ 161,493	$ (1,997,979)	$ (1,132,797)
Net income (loss)	193,397					193,397	193,397
Hedge derivative contract settlements reclassified into earnings from AOCI, net of income tax					(37,181)		(37,181)
Foreign currency translation adjustment	(933)				(933)		(933)
Issuance and vesting of stock compensation		47	14,421	(1,472)			12,996
Balances at Sep. 30, 2013		1,837	765,815	(50,967)	123,379	(1,804,582)	(964,518)
Balances at Dec. 31, 2013		1,840	770,092	(51,422)	109,881	(1,836,361)	(1,005,970)
Net income (loss)	(71,171)					(71,171)	(71,171)
Hedge derivative contract settlements reclassified into earnings from AOCI, net of income tax					(20,939)		(20,939)
Foreign currency translation adjustment	(6,162)				(6,162)		(6,162)
Issuance and vesting of stock compensation		32	9,114	(2,388)			6,758
Balances at Sep. 30, 2014		$ 1,872	$ 779,206	$ (53,810)	$ 82,780	$ (1,907,532)	$ (1,097,484)

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Derivatives And Fair Value Measurements

9 Months Ended

Sep. 30, 2014

Credit Risk Derivatives, at Fair Value, Net [Abstract]

Derivatives And Fair Value Measurements

DERIVATIVES, MARKETABLE SECURITIES AND FAIR VALUE MEASUREMENTS

The following table categorizes our commodity derivative instruments based upon the level of the inputs used in estimating the fair value:

	Asset Derivatives				Liability Derivatives
	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
	(in thousands)				(in thousands)
Level 2 derivative instruments	$	74,312	$	107,395	$	846	$	3,448
Level 3 derivative instruments	17,754		23,485		—		—
Total	$	92,066	$	130,880	$	846	$	3,448

The fair value of “Level 2” derivative instruments included in these disclosures was estimated using inputs quoted in active markets for the periods covered by the derivatives. The fair value of derivative instruments designated as “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 the derivatives, and the credit adjusted risk-free interest rates. The “Level 3” unobservable input is the market prices for natural gas for the period from 2018 to 2021, as there is not an active market for that period of time. These unobservable inputs included within the fair value calculation range from $3.85 to $4.90 and are based upon prices quoted in active markets for the period of time available. A decrease of these unobservable inputs would increase the fair value, while an increase would decrease the fair value.

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,
	2014			2013
	(in thousands)
Balance at beginning of period	$	(5,533	)	$	(9,873	)
Total gains (losses) for the period:
Unrealized gain (loss) on derivatives	24,829			24,080
Settlements in net derivative gains (losses)	(1,542		)	(3,302		)
Balance at end of period	$	17,754		$	10,905
Total gains (losses) included in net derivative gains (losses) attributable to the change in unrealized gains (losses) related to assets still held at the reporting date	$	24,485		$	24,026

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
Balance at beginning of period	$	23,485		$	(4,931	)
Total gains (losses) for the period:
Unrealized gain (loss) on derivatives	(6,488		)	24,618
Settlements in net derivative gains (losses)	757			(8,782		)
Balance at end of period	$	17,754		$	10,905
Total gains (losses) included in net derivative gains (losses) attributable to the change in unrealized gains (losses) related to assets still held at the reporting date	$	(2,476	)	$	26,788

Commodity Price Derivatives

As of September 30, 2014, we had natural gas swaps as follows:

Production Year	Daily Production Volume
	Natural Gas	Natural Gas Basis Swaps
	MMcfd	MMcfd
Remaining 2014 (1)	170	40
2015	150	—
2016-2021	40	—

⁽¹⁾  Our natural gas basis swaps economically hedge the AECO basis adjustment from NYMEX.

Effective December 31, 2012, we discontinued the use of hedge accounting. Changes in value subsequent to this date are recognized in net derivative gains (losses) in the period in which they occur. The net deferred hedge gain that was included in AOCI as of December 31, 2012 is being released into revenue from natural gas, NGL and oil production over the original term of the hedging relationship (through 2021). Gains from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months will result in production revenue of $22.7 million net of income taxes.

Interest Rate Derivatives

In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges. Upon the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain as a reduction of interest expense over the lives of the respective notes. During the nine months endedSeptember 30, 2014 and 2013, we recognized $1.5 million and $11.5 million, respectively, of those deferred gains as a reduction of interest expense. Gains from the effective portion of these interest rate swaps expected to reduce interest expense during the following twelve months are $2.2 million.

Fair Value Disclosures

The estimated fair value of our derivative instruments at September 30, 2014 and December 31, 2013 were as follows:

	Asset Derivatives				Liability Derivatives
	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
	(in thousands)				(in thousands)
Derivatives not designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	66,278	$	60,063	$	180	$	2,540
Noncurrent derivative assets	75,911		105,315		49,943		31,958
Current derivative liabilities	—		—		846		3,125
Noncurrent derivative liabilities	—		—		—		323
Total derivatives not designated as hedges	$	142,189	$	165,378	$	50,969	$	37,946

Derivative assets and liabilities shown in the table above are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in the accompanying condensed consolidated balance sheets. The change in carrying value of our commodity price derivatives since December 31, 2013 principally resulted from the overall increase in market prices for natural gas relative to the prices in our open derivative instruments, offset by settlements during the period.

Financial instruments not carried at fair value

Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets as of September 30, 2014 and December 31, 2013 are included in Note 5.

Investments

We hold certain short-term marketable securities related to interest bearing time deposits and commercial paper. These marketable securities are included in Cash and Cash Equivalents if the maturities at the time we made the investment were three months or less. For maturities greater than three months but less than a year, the marketable securities are included in current Marketable Securities. During June 2014, we sold $10.0 million and transferred $10.0 million of held-to-maturity marketable securities to available-for-sale. Proceeds from these sales were used to reduce the outstanding balance on the Combined Credit Agreements. The estimated fair value of available-for-sale marketable securities is determined using market quotations based on recent trade activity (“Level 2” inputs). At September 30, 2014 we did not own any marketable securities. At December 31, 2013, we had the following marketable securities:

	December 31, 2013
	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Market Value
	(in thousands)
Marketable securities (held-to-maturity)
Time deposits	$	29,419	$	—	$	(22	)	$	29,397
Commercial paper	136,924		27		(25		)	136,926
Marketable securities	$	166,343	$	27	$	(47	)	$	166,323

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Transactions With Related Parties (Details) (USD $)	9 Months Ended			1 Months Ended	9 Months Ended	1 Months Ended	9 Months Ended
	Sep. 30, 2014 Mercury Exploration Company [Member]	Sep. 30, 2013 Mercury Exploration Company [Member]	Sep. 30, 2014 Darden Family [Member]	Mar. 31, 2014 Thomas F. Darden [Member]	Sep. 30, 2014 Thomas F. Darden [Member]	Mar. 31, 2014 Restricted Stock [Member] Thomas F. Darden [Member]	Sep. 30, 2013 Use Of Airplane [Member] Darden Family [Member]	Sep. 30, 2014 Commissions Paid [Member] Darden Family [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	$ 100,000	$ 100,000
Consulting fee payments					405,000
Office allowance payments					112,500
COBRA payments					39,000
Cash bonus				286,650
Vested equity awards						72,662
Percentage of ownership interest			30.00%
Payments to related parties							300,000	200,000
Options issued, fair value				$ 191,100

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Condensed Consolidating Financial Information (Tables)

9 Months Ended

Sep. 30, 2014

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Balance Sheets

	September 30, 2014
	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)
ASSETS
Current assets	$	338,424		$	13,096		$	65,733		$	(23,193	)	$	394,060		$	(455	)	$	1,746	$	949		$	396,300
Property and equipment	417,921			14,625			305,197			—			737,743			—			74,737		—			812,480
Investment in subsidiaries (equity method)	(227,994		)	—			(23,409		)	227,994			(23,409		)	(23,429		)	—		46,838			—
Other assets	457,285			—			15,473			(413,281		)	59,477			—			—		—			59,477
Total assets	$	985,636		$	27,721		$	362,994		$	(208,480	)	$	1,167,871		$	(23,884	)	$	76,483	$	47,787		$	1,268,257
LIABILITIES AND EQUITY
Current liabilities	$	103,042		$	13,401		$	11,064		$	(23,193	)	$	104,314		$	(475	)	$	3,736	$	949		$	108,524
Long-term liabilities	1,980,078			19,241			575,003			(413,281		)	2,161,041			—			1,525		94,651			2,257,217
Stockholders' equity	(1,097,484		)	(4,921		)	(223,073		)	227,994			(1,097,484		)	(23,409		)	71,222		(47,813		)	(1,097,484		)
Total liabilities and equity	$	985,636		$	27,721		$	362,994		$	(208,480	)	$	1,167,871		$	(23,884	)	$	76,483	$	47,787		$	1,268,257

	December 31, 2013
	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)
ASSETS
Current assets	$	349,586		$	10,735		$	53,034		$	(19,642	)	$	393,713		$	909		$	1,110	$	(1,772	)	$	393,960
Property and equipment	455,822			15,486			307,865			—			779,173			—			81,632		—			860,805
Investment in subsidiaries (equity method)	(217,852		)	—			(33,840		)	217,852			(33,840		)	(33,840		)	—		67,680			—
Other assets	472,792			—			32,892			(390,723		)	114,961			—			—		—			114,961
Total assets	$	1,060,348		$	26,221		$	359,951		$	(192,513	)	$	1,254,007		$	(32,931	)	$	82,742	$	65,908		$	1,369,726
LIABILITIES AND EQUITY
Current liabilities	$	124,275		$	12,210		$	17,167		$	(19,642	)	$	134,010		$	888		$	1,671	$	(1,772	)	$	134,797
Long-term liabilities	1,942,043			19,242			542,659			(390,723		)	2,113,221			—			1,546		126,132			2,240,899
Stockholders' equity	(1,005,970		)	(5,231		)	(199,875		)	217,852			(993,224		)	(33,819		)	79,525		(58,452		)	(1,005,970		)
Total liabilities and equity	$	1,060,348		$	26,221		$	359,951		$	(192,513	)	$	1,254,007		$	(32,931	)	$	82,742	$	65,908		$	1,369,726

Condensed Consolidating Statements Of Income

	For the Three Months Ended September 30, 2014
	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	$	120,513		$	427		$	42,558		$	—		$	163,498		$	—	$	4,271	$	(4,271	)	$	163,498
Operating expenses	72,868			341			27,648			—			100,857			—		2,128		(4,271		)	98,714
Equity in net earnings of subsidiaries	8,821			—			(1,458		)	(8,821		)	(1,458		)	2,144		—		(686		)	—
Operating income (loss)	56,466			86			13,452			(8,821		)	61,183			2,144		2,143		(686		)	64,784
Fortune Creek accretion	—			—			—			—			—			—		—		(3,602		)	(3,602		)
Interest expense and other	(37,613		)	86			(4,838		)	—			(42,365		)	—		1		—			(42,364		)
Income tax (expense) benefit	4,826			(30		)	65			78			4,939			—		—		—			4,939
Net income (loss)	$	23,679		$	142		$	8,679		$	(8,743	)	$	23,757		$	2,144	$	2,144	$	(4,288	)	$	23,757
Other comprehensive income (loss)	(11,564		)	—			(3,325		)	—			(14,889		)	—		—		—			(14,889		)
Equity in OCI of subsidiaries	(3,325		)	—			—			3,325			—			—		—		—			—
Comprehensive income (loss)	$	8,790		$	142		$	5,354		$	(5,418	)	$	8,868		$	2,144	$	2,144	$	(4,288	)	$	8,868

	For the Three Months Ended September 30, 2013
	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	$	114,021		$	192	$	38,903		$	—		$	153,116		$	—	$	5,674	$	(5,674	)	$	153,116
Operating expenses	73,594			68		30,360			—			104,022			—		2,693		(5,674		)	101,041
Tokyo Gas Transaction gain	7,974			—		—			—			7,974			—		—		—			7,974
Equity in net earnings of subsidiaries	3,854			—		(1,834		)	(3,854		)	(1,834		)	2,984		—		(1,150		)	—
Operating income (loss)	52,255			124		6,709			(3,854		)	55,234			2,984		2,981		(1,150		)	60,049
Fortune Creek accretion	—			—		—			—			—			—		—		(4,818		)	(4,818		)
Interest expense and other	(36,922		)	—		(1,769		)	—			(38,691		)	—		3		—			(38,688		)
Income tax (expense) benefit	(4,756		)	—		(1,210		)	—			(5,966		)	—		—		—			(5,966		)
Net income (loss)	$	10,577		$	124	$	3,730		$	(3,854	)	$	10,577		$	2,984	$	2,984	$	(5,968	)	$	10,577
Other comprehensive income (loss)	(6,114		)	—		(2,680		)	—			(8,794		)	—		—		—			(8,794		)
Equity in OCI of subsidiaries	(2,680		)	—		—			2,680			—			—		—		—			—
Comprehensive income (loss)	$	1,783		$	124	$	1,050		$	(1,174	)	$	1,783		$	2,984	$	2,984	$	(5,968	)	$	1,783

	For the Nine Months Ended September 30, 2014
	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	$	269,321		$	1,212		$	102,783		$	—		$	373,316		$	—	$	13,349	$	(13,349	)	$	373,316
Operating expenses	225,906			988			86,491			—			313,385			—		6,014		(13,349		)	306,050
Equity in net earnings of subsidiaries	2,864			—			(4,266		)	(2,864		)	(4,266		)	7,339		—		(3,073		)	—
Operating income (loss)	46,279			224			12,026			(2,864		)	55,665			7,339		7,335		(3,073		)	67,266
Fortune Creek accretion	—			—			—			—			—			—		—		(11,605		)	(11,605		)
Interest expense and other	(117,315		)	86			(8,526		)	—			(125,755		)	—		4		—			(125,751		)
Income tax (expense) benefit	(213		)	(78		)	(868		)	78			(1,081		)	—		—		—			(1,081		)
Net income (loss)	$	(71,249	)	$	232		$	2,632		$	(2,786	)	$	(71,171	)	$	7,339	$	7,339	$	(14,678	)	$	(71,171	)
Other comprehensive income (loss)	(20,252		)	—			(6,849		)	—			(27,101		)	—		—		—			(27,101		)
Equity in OCI of subsidiaries	(6,849		)	—			—			6,849			—			—		—		—			—
Comprehensive income (loss)	$	(98,350	)	$	232		$	(4,217	)	$	4,063		$	(98,272	)	$	7,339	$	7,339	$	(14,678	)	$	(98,272	)

	For the Nine Months Ended September 30, 2013
	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	$	334,848		$	608	$	111,862		$	—	$	447,318		$	—	$	16,736	$	(16,736	)	$	447,318
Operating expenses	256,810			206		89,559			—		346,575			—		7,552		(16,736		)	337,391
Tokyo Gas Transaction gain	341,146			—		—			—		341,146			—		—		—			341,146
Equity in net earnings of subsidiaries	(9,227		)	—		(5,300		)	9,227		(5,300		)	9,190		—		(3,890		)	—
Operating income (loss)	409,957			402		17,003			9,227		436,589			9,190		9,184		(3,890		)	451,073
Fortune Creek accretion	—			—		—			—		—			—		—		(14,490		)	(14,490		)
Interest expense and other	(200,639		)	—		(24,490		)	—		(225,129		)	—		6		—			(225,123		)
Income tax (expense) benefit	(15,921		)	—		(2,142		)	—		(18,063		)	—		—		—			(18,063		)
Net income (loss)	$	193,397		$	402	$	(9,629	)	$	9,227	$	193,397		$	9,190	$	9,190	$	(18,380	)	$	193,397
Other comprehensive income (loss)	(29,014		)	—		(9,100		)	—		(38,114		)	—		—		—			(38,114		)
Equity in OCI of subsidiaries	(9,100		)	—		—			9,100		—			—		—		—			—
Comprehensive income (loss)	$	155,283		$	402	$	(18,729	)	$	18,327	$	155,283		$	9,190	$	9,190	$	(18,380	)	$	155,283

Condensed Consolidating Statements Of Cash Flows

	For the Nine Months Ended September 30, 2014
	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)
Net cash flow provided by (used in) operating activities	$	(39,474	)	$	(688	)	$	28,843		$	—		$	(11,319	)	$	—		$	6,336		$	—		$	(4,983	)
Purchases of property, plant and equipment	(88,119		)	(57		)	(23,247		)	—			(111,423		)	—			(21		)	—			(111,444		)
Investment in subsidiary	(1,246		)	—			(26,395		)	1,246			(26,395		)	(26,395		)	—			52,790			—
Proceeds from Southwestern Transaction	95,587			—			—			—			95,587			—			—			—			95,587
Proceeds from sale of properties and equipment	1,445			—			497			—			1,942			—			—			—			1,942
Purchases of marketable securities	(55,890		)	—			—			—			(55,890		)	—			—			—			(55,890		)
Maturities and sales of marketable securities	222,025			—			—			—			222,025			—			—			—			222,025
Net cash flow provided by (used in) investing activities	173,802			(57		)	(49,145		)	1,246			125,846			(26,395		)	(21		)	52,790			152,220
Issuance of debt	174,000			—			69,184			—			243,184			—			—			—			243,184
Repayments of debt	(138,651		)	—			(55,038		)	—			(193,689		)	—			—			—			(193,689		)
Debt issuance costs paid	(225		)	—			—			—			(225		)	—			—			—			(225		)
Intercompany note	(22,558		)	—			22,558			—			—			—			—			—			—
Intercompany financing	—			745			501			(1,246		)	—			—			—			—			—
Contribution received	—			—			—			—			—			26,395			26,395			(52,790		)	—
Distribution of Fortune Creek Partnership funds	—			—			—			—			—			—			(37,113		)	—			(37,113		)
Purchase of treasury stock	(2,388		)	—			—			—			(2,388		)	—			—			—			(2,388		)
Net cash flow provided by (used in) financing activities	10,178			745			37,205			(1,246		)	46,882			26,395			(10,718		)	(52,790		)	9,769
Effect of exchange rates on cash	—			—			(2,718		)	—			(2,718		)	—			4,934			—			2,216
Net increase (decrease) in cash and equivalents	144,506			—			14,185			—			158,691			—			531			—			159,222
Cash and equivalents at beginning of period	83,893			—			4,135			—			88,028			22			1,053			—			89,103
Cash and equivalents at end of period	$	228,399		$	—		$	18,320		$	—		$	246,719		$	22		$	1,584		$	—		$	248,325

	For the Nine Months Ended September 30, 2013
	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 by (used in) operating activities	$	(113,029	)	$	(19	)	$	25,517		$	(87,531	)	$	—	$	6,428		$	(81,103	)
Purchases of property, plant and equipment	(53,291		)	19			(24,752		)	(78,024		)	—		(525		)	(78,549		)
Proceeds from Tokyo Gas Transaction	463,418			—			—			$	463,418		—		—			463,418
Proceeds from Synergy transaction	42,297			—			—			42,297			—		—			42,297
Proceeds from sale of properties and equipment	2,977			—			17			2,994			—		—			2,994
Purchases of marketable securities	(142,823		)	—			—			$	(142,823	)	—		—			(142,823		)
Maturities and sales of marketable securities	13,178			—			—			$	13,178		—		—			13,178
Net cash flow provided by (used in)  investing activities	325,756			19			(24,735		)	301,040			—		(525		)	300,515
Issuance of debt	1,170,266			—			3,040			1,173,306			—		—			1,173,306
Repayments of debt	(1,157,969		)	—			(150,413		)	(1,308,382		)	—		—			(1,308,382		)
Debt issuance costs paid	(25,868		)	—			—			(25,868		)	—		—			(25,868		)
Intercompany note	(147,103		)	—			147,103			—			—		—			—
Distribution of Fortune Creek Partnership funds	—			—			—			—			—		(8,079		)	(8,079		)
Purchase of treasury stock	(1,472		)	—			—			(1,472		)	—		—			(1,472		)
Net cash flow used in financing activities	(162,146		)	—			(270		)	(162,416		)	—		(8,079		)	(170,495		)
Effect of exchange rates on cash	—			—			(512		)	(512		)	—		3,122			2,610
Net increase in cash and equivalents	50,581			—			—			50,581			—		946			51,527
Cash and equivalents at beginning of period	4,618			—			—			4,618			—		333			4,951
Cash and equivalents at end of period	$	55,199		$	—		$	—		$	55,199		$	—	$	1,279		$	56,478

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Derivatives And Fair Value Measurements Derivatives, Investments And Fair Value Measurements (Held-to-maturity securities) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Fixed Income Securities [Member]
Schedule of Held-to-maturity Securities [Line Items]
Held-to-maturity Securities, Amortized Cost before Other than Temporary Impairment	$ 29,419,000
Held-to-maturity Securities, Unrecognized Holding Gain	0
Held-to-maturity Securities, Unrecognized Holding Loss	(22,000)
Held-to-maturity Securities, Fair Value	29,397,000
Commercial Paper, Not Included with Cash and Cash Equivalents [Member]
Schedule of Held-to-maturity Securities [Line Items]
Held-to-maturity Securities, Amortized Cost before Other than Temporary Impairment	136,924,000
Held-to-maturity Securities, Unrecognized Holding Gain	27,000
Held-to-maturity Securities, Unrecognized Holding Loss	(25,000)
Held-to-maturity Securities, Fair Value	136,926,000
Debt Securities [Member]
Schedule of Held-to-maturity Securities [Line Items]
Held-to-maturity Securities, Amortized Cost before Other than Temporary Impairment	166,343,000
Held-to-maturity Securities, Unrecognized Holding Gain	27,000
Held-to-maturity Securities, Unrecognized Holding Loss	(47,000)
Held-to-maturity Securities, Fair Value	$ 166,323,000

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Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2014

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
Interest, net of capitalized interest	$	124,408		$	227,189
Income taxes	(7,844		)	1,217

Other significant non-cash transactions are as follows:

	For the Nine Months Ended September 30,
	2014		2013
	(in thousands)
Working capital related to capital expenditures	$	7,612	$	4,867