Quicksilver Resources (KWK) 10-Q 2013 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2013
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	þ		Accelerated filer	¨
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, 2013
Common Stock, $0.01 par value	177,115,784 shares

DEFINITIONS

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

“ABR” means alternate base rate

“AECO” is a reference, in 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

“Bcf” means billion cubic feet

“Bcfe” means Bcf of natural gas equivalents

“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

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

“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

“PUD” means proved undeveloped reserve

“RSU” means restricted stock unit

“Tcfe” means trillion cubic feet of natural gas equivalents

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

“Amended and Restated Canadian Credit Facility” means our Canadian senior secured revolving credit facility, which was amended and restated as of 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 as of 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

“CMLP” means Crestwood Midstream Partners LP

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

“Crestwood” means Crestwood Holdings LLC

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

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

2

“Fortune Creek” means Fortune Creek Gathering and Processing Partnership, a midstream partnership formed with KKR 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

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

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

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

“Komie North Project” means the series of contracts with NGTL for the construction of a pipeline and meter station, which will serve our and others’ transportation needs in the Horn River basin

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

“NEB” means National Energy Board, an independent agency which regulates international and interprovincial aspects of the oil and gas industries in Canada and is accountable to Parliament through the Minister of Natural Resources Canada.

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

“Niobrara Asset” means our operations and our assets in the Niobrara formation in northwest Colorado

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

“Senior Secured Second Lien Credit Agreement” means our new senior secured term credit facility dated as of June 21, 2013

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

“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 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 subsidiary of Tokyo Gas Co., Ltd.

“VIE” means variable interest entity

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

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2013

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	32
Item 3. Quantitative and Qualitative Disclosures About Market Risk	55
Item 4. Controls and Procedures	57
PART II. OTHER INFORMATION	59
Item 1. Legal Proceedings	59
Item 1A. Risk Factors	59
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 3. Defaults Upon Senior Securities	59
Item 4. Mine Safety Disclosures	59
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.

4

Forward-Looking Information

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

• changes in general economic conditions;

• fluctuations in natural gas, NGL and oil prices;

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

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

• failure to comply with covenants under our Combined Credit Agreements and the resulting acceleration of debt thereunder and inability to make 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 and NGL prices;

• fluctuations in the value of certain of our assets and liabilities;

• competitive conditions in our industry;

• actions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters, customers and counterparties;

• changes in the availability and cost of capital;

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

• delays in construction of transportation pipelines and gathering, processing and treating facilities;

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

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

• failure or delay in completing strategic transactions;

• the effects of existing or future litigation; and

• additional factors described elsewhere in this Quarterly Report.

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

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

5

PART I    FINANCIAL INFORMATION

ITEM 1. Condensed Consolidated Interim Financial Statements (Unaudited)

QUICKSILVER RESOURCES INC.

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

In thousands, except for per share data – Unaudited

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012 (1)			2013			2012 (1)
				(Restated)						(Restated)
Revenue
Production	$	104,546		$	156,288		$	358,281		$	473,053
Sales of purchased natural gas	15,130			21,313			50,373			42,841
Net derivative gains (losses) (including realized gains of $8,009 and $12,376; $14,129 and $35,059, respectively)	32,733			(60,377		)	36,202			(33,902		)
Other	707			964			2,462			3,080
Total revenue	153,116			118,188			447,318			485,072
Operating expense
Lease operating	18,591			22,115			63,699			72,405
Gathering, processing and transportation	35,567			41,338			112,064			127,039
Production and ad valorem taxes	4,678			6,881			15,462			20,833
Costs of purchased natural gas	15,114			21,254			50,311			42,528
Depletion, depreciation and accretion	14,390			34,014			47,911			136,469
Impairment	—			551,132			—			2,068,787
General and administrative	10,471			17,335			43,509			54,835
Other operating	2,230			670			4,435			821
Total expense	101,041			694,739			337,391			2,523,717
Tokyo Gas Transaction gain	7,974			—			341,146			—
Crestwood earn-out	—			—			—			41,097
Operating income (loss)	60,049			(576,551		)	451,073			(1,997,548		)
Other income (expense)	667			(395		)	(14,588		)	(237		)
Fortune Creek accretion	(4,818		)	(4,978		)	(14,490		)	(14,549		)
Interest expense	(39,355		)	(42,102		)	(210,535		)	(122,348		)
Income (loss) before income taxes	16,543			(624,026		)	211,460			(2,134,682		)
Income tax (expense) benefit	(5,966		)	(166,494		)	(18,063		)	330,575
Net income (loss)	$	10,577		$	(790,520	)	$	193,397		$	(1,804,107	)
Reclassification adjustments related to settlements of derivative contracts into production revenue- net of income tax	(11,139		)	(34,145		)	(37,181		)	(99,726		)
Net change in derivative fair value - net of income tax	—			(11,905		)	—			60,305
Foreign currency translation adjustment	2,345			(565		)	(933		)	(5,495		)
Other comprehensive income (loss)	(8,794		)	(46,615		)	(38,114		)	(44,916		)
Comprehensive income (loss)	$	1,783		$	(837,135	)	$	155,283		$	(1,849,023	)
Earnings (loss) per common share - basic	$	0.06		$	(4.65	)	$	1.10		$	(10.61	)
Earnings (loss) per common share - diluted	$	0.06		$	(4.65	)	$	1.10		$	(10.61	)

⁽¹⁾ Note 1 contains additional information

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

6

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data – Unaudited

	September 30, 2013			December 31, 2012
ASSETS
Current assets
Cash and cash equivalents	$	56,478		$	4,951
Marketable securities	129,812			—
Total cash, cash equivalents and marketable securities	186,290			4,951
Accounts receivable - net of allowance for doubtful accounts	55,242			64,149
Derivative assets at fair value	86,003			113,367
Other current assets	22,413			25,046
Total current assets	349,948			207,513
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $291,147 and $307,267, respectively)	629,684			780,960
Other property and equipment	233,248			248,098
Property, plant and equipment - net	862,932			1,029,058
Derivative assets at fair value	75,328			105,270
Other assets	43,405			39,947
	$	1,331,613		$	1,381,788
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	12,745		$	37,131
Accrued liabilities	102,913			130,660
Total current liabilities	115,658			167,791
Long-term debt	1,926,167			2,063,206
Partnership liability	132,732			130,912
Asset retirement obligations	99,160			115,949
Derivative liabilities at fair value	3,172			17,485
Other liabilities	19,242			19,242
Commitments and contingencies (Note 8)
Stockholders' equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding	—			—
Common stock, $0.01 par value, 400,000,000 shares authorized, and 183,685,021 and 179,015,118 shares issued, respectively	1,837			1,790
Paid in capital in excess of par value	765,815			751,394
Treasury stock of 6,545,651 and 5,921,102 shares, respectively	(50,967		)	(49,495		)
Accumulated other comprehensive income	123,379			161,493
Retained deficit	(1,804,582		)	(1,997,979		)
Total stockholders' equity	(964,518		)	(1,132,797		)
	$	1,331,613		$	1,381,788

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

7

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

In thousands – Unaudited

	Quicksilver Resources Inc. Stockholders’ Equity
	Common Stock		Additional Paid-in Capital		Treasury Stock			Accumulated Other Comprehensive Income			Retained Earnings (Deficit)			Total
Balances at December 31, 2011	$	1,770	$	737,015	$	(46,351	)	$	214,858		$	354,627		$	1,261,919
Net loss	—		—		—			—			(1,804,107		)	(1,804,107		)
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $51,909	—		—		—			(99,726		)	—			(99,726		)
Net change in derivative fair value, net of income tax of $30,042	—		—		—			60,305			—			60,305
Foreign currency translation adjustment	—		—		—			(5,495		)	—			(5,495		)
Issuance and vesting of stock compensation	17		18,055		(2,810		)	—			—			15,262
Stock option exercises	1		10		—			—			—			11
Balances at September 30, 2012, restated (1)	$	1,788	$	755,080	$	(49,161	)	$	169,942		$	(1,449,480	)	$	(571,831	)
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	)

⁽¹⁾ Note 1 contains additional information

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

8

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

In thousands – Unaudited

	For the Nine Months Ended September 30,
	2013			2012 (1)
				(Restated)
Operating activities:
Net income (loss)	$	193,397		$	(1,804,107	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion	47,911			136,469
Impairment expense	—			2,068,787
Tokyo Gas Transaction gain	(341,146		)	—
Crestwood earn-out	—			(41,097		)
Deferred income tax expense (benefit)	17,833			(326,149		)
Non-cash (gain) loss from hedging and derivative activities	(12,223		)	88,913
Stock-based compensation	13,699			16,983
Non-cash interest expense	23,643			8,060
Fortune Creek accretion	14,490			14,549
Other	3,622			495
Changes in assets and liabilities
Accounts receivable	7,398			27,259
Prepaid expenses and other assets	344			(4,503		)
Accounts payable	(17,973		)	(24,329		)
Accrued and other liabilities	(32,098		)	(19,954		)
Net cash provided by (used in) operating activities	(81,103		)	141,376
Investing activities:
Purchases of property, plant and equipment	(78,549		)	(437,172		)
Proceeds from Tokyo Gas Transaction	463,418			—
Proceeds from Synergy Transaction	42,297			—
Proceeds from Crestwood earn-out	—			41,097
Proceeds from sale of properties and equipment	2,994			3,843
Purchases of marketable securities	(142,823		)	—
Maturities and sales of marketable securities	13,178			—
Net cash provided by (used in) investing activities	300,515			(392,232		)
Financing activities:
Issuance of debt	1,173,306			367,646
Repayments of debt	(1,308,382		)	(111,115		)
Debt issuance costs paid	(25,868		)	(3,048		)
Distribution of Fortune Creek Partnership funds	(8,079		)	(6,520		)
Proceeds from exercise of stock options	—			11
Excess tax deductions on stock compensation	—			1,089
Purchase of treasury stock	(1,472		)	(2,810		)
Net cash provided by (used in) financing activities	(170,495		)	245,253
Effect of exchange rate changes in cash	2,610			(107		)
Net increase (decrease) in cash	51,527			(5,710		)
Cash at beginning of period	4,951			13,146
Cash at end of period	$	56,478		$	7,436

⁽¹⁾ Note 1 contains additional information

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

9

QUICKSILVER RESOURCES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited

1. ACCOUNTING POLICIES AND DISCLOSURES

The accompanying condensed consolidated interim financial statements have not been audited. In management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to fairly present our financial position as of September 30, 2013 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 2012 Annual Report on Form 10-K.

Restatement of Previously Issued Unaudited Financial Statements

The consolidated financial statements as of and for the three and nine months ended September 30, 2012 were restated as more fully disclosed within Item 8, Note 2 and the Supplemental Selected Quarterly Financial Data in the 2012 Annual Report on Form 10-K. The restatement is the result of our hedge documentation failing to give consideration to all sources of ineffectiveness for derivatives entered into during 2012 that had fair value on the dates they were initially designated as hedges. These derivatives did not qualify for hedge accounting in 2012 and their changes in value required recognition in earnings. Because the derivatives did not qualify for hedge accounting, their inclusion in the U.S. and Canadian full cost ceiling was inappropriate. Also, we determined that the deferred taxes used in our Canadian ceiling test included temporary differences for non-property related items. Thus, we revised our full cost ceiling calculations, which resulted in restatements to increase impairment expense recognized. Income taxes have also been restated to reflect the foregoing restated items.

For the three months ended September 30, 2012, the derivative restatement adjustment decreased production revenue by $0.3 million and $1.1 million for the U.S. and Canada, respectively, while derivative losses increased $42.8 million and $15.3 million for the U.S. and Canada, respectively. Impairment expense increased as the result of these derivatives no longer being included in the cost center ceiling by $43.4 million for the U.S. but decreased by $39.1 million for Canada, while depletion expense decreased $3.3 million and $5.9 million for the U.S. and Canada, respectively. The income tax impact of these adjustments resulted in an increase to the tax expense of $75.3 million and $8.8 million for the U.S. and Canada, respectively. Our consolidated net loss increased $138.8 million, which decreased our retained earnings by the same amount. Other comprehensive income and AOCI increased $34.7 million as a result of these adjustments. The restatement increased diluted net loss per share by $0.82, from diluted net loss per share of $3.83 as previously reported, to diluted net loss per share of $4.65.

For the nine months ended September 30, 2012, the derivative restatement decreased production revenue by $2.6 million and $4.4 million for the U.S. and Canada, respectively, while derivative gains increased $0.1 million and $0.2 million for the U.S. and Canada, respectively. Impairment expense increased as the result of these derivatives no longer being included in the cost center ceiling by $303.1 million and $164.2 million for the U.S. and Canada, respectively, while depletion expense decreased $4.6 million and $8.5 million for the U.S. and Canada, respectively. The income tax impact of these adjustments resulted in an increase to the tax benefit of $0.9 million and $40.0 million for the U.S. and Canada, respectively. Our consolidated net loss increased $419.9 million, which decreased our retained earnings by the same amount. Other comprehensive income and AOCI decreased $5.2 million as a result of these adjustments. The restatement increased diluted net loss per share by $2.47, from diluted net loss per share of $8.14 as previously reported, to diluted net loss per share of $10.61.

10

Recently Issued Accounting Standards

Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements materially affecting our financial statements have been issued since the filing of our 2012 Annual Report on Form 10-K.

2. DIVESTITURES

In October and November 2013, we executed two separate agreements involving our West Texas Asset, the largest of which is a joint venture with Eni whereby we will jointly evaluate, explore and develop approximately 52,500 gross acres currently held by us in Pecos County, Texas. Under the terms of the agreement, Eni will pay up to $52.0 million in three phases to earn a 50% interest in our acreage. In the first phase, Eni will fund 100% of the drilling and completion costs of up to a three-well program. Upon funding of the first phase, Eni will earn 50% of our interest in a 7,500 gross acre tract in Pecos County. Eni will then have the option to fund 100% of the drilling and completion costs of another two wells, and will then have the option to fully fund a 3-D seismic survey of the remaining, undeveloped acreage. Upon completion of the three phases, we will participate equally in all future revenue, operating cost and capital expenditures.

In August 2013, we completed the sale of our Southern Alberta Asset to Synergy with an effective date of January 1, 2013. The purchase price was $46.0 million, which was subject to customary purchase price adjustments, resulting in Synergy paying us $42.3 million. Under the full cost method of accounting, our U.S. exploration and production assets are considered a single asset. 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.

In March 2013, we entered into a Purchase and Sale Agreement with TGBR to sell an undivided 25% of our Barnett Shale Asset for a purchase price of $485 million. The transaction closed in April 2013, but was effective as of September 1, 2012. The purchase price was subject to customary purchase price adjustments, which resulted in TGBR paying us $464.0 million, including an estimated final payment of $0.6 million, which we expect to receive in the fourth quarter of 2013. We recognized a gain of $341.1 million before consideration of income taxes as a result of this transaction, including a revision of the gain calculation in the third quarter of 2013 of $7.8 million. The Tokyo Gas Transaction represented a significant disposal of reserves, which resulted in gain recognition for the transaction. Our U.S. oil and gas properties were reduced by $110.7 million as a result of the Tokyo Gas Transaction.

In October 2010, we completed the sale of all of our interests in KGS to Crestwood. As part of the sale, we had the right to collect future earn-out payments through 2013. In February 2012, we collected $41 million of these earn-out payments which is presented as “Crestwood earn-out” in the condensed consolidated statement of income. We will not receive additional earn-out payments in 2013.

Note 3 to the consolidated financial statements in our 2012 Annual Report on Form 10-K contains additional information regarding the Crestwood Transaction.

3. DERIVATIVES, MARKETABLE SECURITIES AND FAIR VALUE MEASUREMENTS

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

	Asset Derivatives				Liability Derivatives
	September 30, 2013		December 31, 2012		September 30, 2013			December 31, 2012
	(in thousands)				(in thousands)
Level 2 inputs	$	146,864	$	207,042	$	(390	)	$	959
Level 3 inputs	14,467		11,595		3,562			16,526
Total	$	161,331	$	218,637	$	3,172		$	17,485

The fair value of “Level 2” derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value reported by counterparties. The fair value of derivative instruments designated as “Level 3” was estimated using prices quoted in markets where

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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 inputs are the market prices for the estimated market values 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 $3.50 to $5.61 and are based upon prices quoted in active markets for the period of time available and applying the differential from this period of time to the market prices for the later years in the term.

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,
	2013			2012
	(In thousands)
Balance at beginning of period	$	(9,873	)	$	45,345
Total gains (losses) for the period:
Unrealized gain (loss) on derivatives	24,080			(51,685		)
Settlements in production revenue	—			(825		)
Settlements in net derivative gains (losses)	(3,302		)	(6,870		)
Unrealized gains reported in OCI	—			409
Balance at end of period	$	10,905		$	(13,626	)
Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date	$	24,026		$	(51,685	)

	For the Nine Months Ended September 30,
	2013			2012
	(In thousands)
Balance at beginning of period	$	(4,931	)	$	150,989
Total gains (losses) for the period:
Unrealized gain (loss) on derivatives	24,618			(16,160		)
Transfers out of Level 3	—			(153,418		)
Settlements in production revenue	—			(5,600		)
Settlements in net derivative gains (losses)	(8,782		)	(22,743		)
Unrealized gains reported in OCI	—			33,306
Balance at end of period	$	10,905		$	(13,626	)
Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date	$	26,788		$	(16,160	)

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

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Commodity Price Derivatives

As of September 30, 2013, we had natural gas and NGL swaps as follows:

Production Year	Daily Production Volume
	Natural Gas	NGL
	MMcfd	MBbld
Remainder of 2013	200	6
2014 (1)	170	4
2015	150	—
2016-2021	40	—

⁽¹⁾ Our 2014 NGL derivatives end in September. Our natural gas derivatives are in place until the end of the year.

In October 2013, we entered into 40 MMcfd AECO to NYMEX natural gas basis swaps for the calendar year 2014.

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 during the following periods in which we expect the underlying production to occur:

	(In thousands)
Remainder of 2013	$	15,254
2014	37,084
2015	33,191
2016	13,476
2017	12,531
2018 and thereafter	41,443
	$	152,979

Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months would result in a gain of $29.5 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 of our senior notes due 2015 and our senior subordinated notes. We received cash of $41.5 million in the settlements, including $10.7 million for interest previously accrued and earned. Upon the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain of $30.8 million as a reduction of interest expense over the lives of our senior notes due 2015 and our senior subordinated notes.

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In June 2013, we repurchased substantially all our senior notes due 2015 resulting in early recognition of the previously deferred gain of $8.3 million. During the nine months endedSeptember 30, 2013 and 2012, we recognized $11.5 million and $3.8 million, respectively, of those deferred gains as a reduction of interest expense. The remaining $5.3 million deferral of the 2010 early settlements from the senior subordinated notes interest rate swaps will continue to be recognized as a reduction of interest expense over the life of those instruments currently scheduled as follows:

	(In thousands)
Remainder of 2013	$	492
2014	2,039
2015	2,194
2016	569
	$	5,294

Fair Value Disclosures

The estimated fair values of our derivative instruments at September 30, 2013 and December 31, 2012 were as follows:

	Asset Derivatives				Liability Derivatives
	September 30, 2013		December 31, 2012		September 30, 2013		December 31, 2012
	(In thousands)				(In thousands)
Derivatives not designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	86,003	$	113,367	$	—	$	—
Noncurrent derivative assets	75,403		107,542		75		2,272
Current derivative liabilities	—		—		—		—
Noncurrent derivative liabilities	448		92		3,620		17,577
Total derivatives not designated as hedges	$	161,854	$	221,001	$	3,695	$	19,849

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 presentations 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, 2012 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.

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The changes in the carrying value of our derivatives accounted for as hedges for the three and nine months ended September 30, 2012 are presented below:

	For the Three Months Ended September 30,
	2012
	Commodity Hedges
	(In thousands)
Derivative fair value at beginning of period	$	176,726
Settlements in production revenue	(45,681		)
Ineffectiveness reported in net derivative gains	(547		)
Unrealized gains (losses) reported in OCI	(15,543		)
Derivative fair value at end of period	$	114,955
	For the Nine Months Ended September 30,
	2012
	Commodity Hedges
	(In thousands)
Derivative fair value at beginning of period	$	342,799
Settlements in production revenue	(137,417		)
Settlements in net derivative gains	(3,820		)
Ineffectiveness reported in net derivative gains	1,022
Unrealized gains reported in OCI	93,103
Derecognition of hedge	(180,732		)
Derivative fair value at end of period	$	114,955

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 sheet as of September 30, 2013 and December 31, 2012 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 held-to-maturity 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. At September 30, 2013, we had the following marketable securities:

	Amortized Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Market Value
	(In thousands)
Marketable securities (held-to-maturity)
Time deposits	$	19,902	$	—	$	(22	)	$	19,880
Commercial paper	109,910		34		(31		)	109,913
Marketable securities	$	129,812	$	34	$	(53	)	$	129,793

We had no marketable securities at December 31, 2012.

4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	September 30, 2013			December 31, 2012
	(In thousands)
Oil and gas properties
Subject to depletion	$	5,630,152		$	5,770,913
Unevaluated costs	291,147			307,267
Accumulated depletion	(5,291,615		)	(5,297,220		)
Net oil and gas properties	629,684			780,960
Other plant and equipment
Pipelines and processing facilities	358,186			375,248
General properties	79,619			75,147
Accumulated depreciation	(204,557		)	(202,297		)
Net other property and equipment	233,248			248,098
Property, plant and equipment, net of accumulated depletion and depreciation	$	862,932		$	1,029,058

Ceiling Test Analysis and Impairment

We recorded impairment expense of $479.9 million and $66.3 million for the three months ended September 30, 2012, $1,042.7 million and $157.0 million for the three months ended June 30, 2012 and $178.0 million and $139.9 million for the three months ended March 31, 2012 for our U.S. and Canadian oil and gas properties, respectively. We also recorded impairment expense of $4.9 million for the three months ended September 30, 2012 for other property and equipment.

Notes 2 and 8 to the consolidated financial statements in our 2012 Annual Report on Form 10-K contain additional information regarding our property, plant and equipment and our quarterly ceiling test analysis.

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5. LONG-TERM DEBT

Long-term debt consisted of the following:

	September 30, 2013		December 31, 2012
	(in thousands)
Combined Credit Agreements	$	149,736	$	388,150
Senior Secured Second Lien Credit Agreement, net of unamortized discount	606,593		—
Senior Secured Second Lien Notes due 2019, net of unamortized discount	194,110		—
Senior notes due 2015, net of unamortized discount	10,466		435,851
Senior notes due 2016, net of unamortized discount	8,032		579,795
Senior notes due 2019, net of unamortized discount	293,083		292,622
Senior notes due 2021, net of unamortized discount	308,853		—
Senior subordinated notes due 2016	350,000		350,000
Total debt	1,920,873		2,046,418
Unamortized deferred gain-terminated interest rate swaps	5,294		16,788
Current portion of long-term debt	—		—
Long-term debt	$	1,926,167	$	2,063,206

Combined Credit Facilities

The Combined Credit Agreements’ global borrowing base was $350 million and the global letter of credit capacity was $280 million as of September 30, 2013. At September 30, 2013, we had $157.8 million available under the Combined Credit Agreements.

We amended our Combined Credit Agreements in April and June 2013 for the following:

• Reduce the global borrowing base to $350 million from $850 million, including the reduction due to the Tokyo Gas Transaction

• Reduce the minimum required interest coverage ratio to the following:

Period	Interest Coverage Ratio	Period	Interest Coverage Ratio
Q3 2013	1.25	Q1 2015	1.10
Q4 2013	1.25	Q2 2015	1.15
Q1 2014	1.20	Q3 2015	1.15
Q2 2014	1.15	Q4 2015	1.20
Q3 2014	1.10	Q1 2016	1.50
Q4 2014	1.10	Q2 2016	2.00

• Permit up to $825 million of second lien debt, subject to customary intercreditor terms

• Permit redemption of junior debt with the proceeds from certain asset sales and permitted second lien debt, provided utilization under the global borrowing base after giving effect to such redemption is less than 75% and compliance with other customary conditions

• Reduce the maximum senior secured debt leverage ratio to 2.0 and exclude permitted second lien debt from the senior secured debt definition

• Increase the applicable margin by 0.75% for each type of loan and issued letters of credit

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• Increase the minimum mortgage properties requirement to 87.5% from 80% of proved hydrocarbon interests evaluated in the then most recent reserve report

• Amend certain definitions which impact the financial covenant calculations.

Debt Refinancing

During the quarter ended June 30, 2013, we executed multiple debt transactions, including payment of $51.4 million of cancellation premiums and discounts and tender premiums, which are more fully described below, to extend our debt maturities and reduce the weighted average interest costs. Deferred issuance costs related to the new debt were $23.4 million, and $4.1 million of incurred costs related to the repurchased debt were recognized as interest expense. Proceeds from the Senior Secured Second Lien Credit Agreement and the issuance of Senior Secured Second Lien Notes due 2019 and Senior Notes due 2021 were used to pay for validly tendered Senior Notes due 2015 and Senior Notes due 2016 and accrued interest thereon and transaction expenses.

Senior Secured Second Lien Credit Agreement

On June 21, 2013, we entered into a $625 million six-year Senior Secured Second Lien Credit Agreement. The loans thereunder were made at 97% of par, which resulted in net proceeds of $606.3 million. The Senior Secured Second Lien Credit Agreement has a margin of 5.75% plus the adjusted LIBOR (as defined in the Senior Secured Second Lien Credit Agreement, which is subject to a floor of 1.25%) or 4.75% plus the Alternate Base Rate (as defined in the Senior Secured Second Lien Credit Agreement, which is subject to a floor of 2.25%).

Senior Secured Second Lien Notes due 2019

On June 21, 2013, we issued $200 million of Senior Secured Second Lien Notes due 2019. The notes were issued at 97% of par, which resulted in net proceeds of $194 million. The Senior Secured Second Lien Notes have a margin of 5.75% plus LIBOR (as defined in the indenture governing the Senior Secured Second Lien Notes due 2019, which is subject to a floor of 1.25%). Interest is payable on the last day of each quarter.

Senior Notes due 2021

On June 21, 2013, we issued $325 million of Senior Notes due 2021, which are unsecured, senior obligations. The notes were issued at 94.928% of par, which resulted in proceeds of $308.5 million. Interest at the rate of 11.00% is payable semiannually on January 1 and July 1.

Senior Notes due 2015

During the quarter ended June 30, 2013, we announced a cash tender offer and consent solicitation for the Senior Notes due 2015 at a price of $1,027.90 plus interest of $32.08 per $1,000 outstanding. On June 21, 2013, we accepted and paid for all validly tendered notes, representing $425.2 million of the then outstanding $438.0 million, which resulted in an aggregate payment of $450.7 million for such repurchase. We also entered into a supplemental indenture to eliminate substantially all of the restrictive covenants and certain events of default with respect to such notes.

During the quarter ended September 30, 2013, we repurchased $2.3 million aggregate principal amount of the Senior Notes due 2015.

Senior Notes Due 2016

During the quarter ended June 30, 2013, we announced a cash tender offer and consent solicitation for the Senior Notes due 2016 at a price of $1,068 plus interest of $55.49 per $1,000 outstanding. On June 21, 2013, we accepted and paid for all validly tendered notes, representing $582.5 million of the then outstanding $590.6 million, which resulted in an aggregate payment of $654.4 million for such repurchase. We also entered into a supplemental indenture to eliminate substantially all of the restrictive covenants and certain events of default with respect to such notes.

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Senior Notes Due 2019

During the quarter ended June 30, 2013, we announced a consent solicitation for the Senior Notes due 2019. On June 21, 2013, we entered into supplemental indentures to permit the refinancing of the Senior Subordinated Notes due 2016 by incurring indebtedness that ranks equally in right of payment with the Senior Notes due 2019 provided such indebtedness has maturities longer than the Senior Notes due 2019, which resulted in the payment of an $11.5 million consent fee to the consenting holders of the Senior Notes due 2019.

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, 2013, 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 indentures. We are presently unable to 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 debt with net cash proceeds from 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, 2013.

	Priority on Collateral and Structural Seniority (1)
	Highest priority								Lowest priority
	First Lien		Second Lien		Senior Unsecured				Senior Subordinated
	Combined Credit Agreements		Senior Secured Second Lien Credit Agreement	Senior Secured Second Lien Notes due 2019	2015 Senior Notes	2016 Senior Notes	2019 Senior Notes	2021 Senior Notes	Senior Subordinated Notes
Principal amount (2)	$350 million		$625 million	$200 million	$11 million	$8 million	$298 million	$325 million	$350 million
Scheduled maturity date (3)	September 6, 2016		June 21, 2019	June 21, 2019	August 1, 2015	January 1, 2016	August 15, 2019	July 1, 2021	April 1, 2016
Interest rate on outstanding borrowings at September 30, 2013 (4)	4.00%		7.00%	7.00%	8.25%	11.75%	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	N/A	N/A
Financial covenants (7)	- Minimum current ratio of 1.0 - Minimum EBITDA to cash interest expense ratio of 1.25 - Maximum senior secured debt leverage ratio of 2.0		N/A	N/A	N/A	N/A	N/A	N/A	N/A
Significant restrictive covenants (7)	- 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	- Asset sales	- Asset sales	- 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 (7)	Any time		Any time, subject to re-pricing event June 21, 2014: 102 2015: 101	Any time, subject to re-pricing event June 21, 2014: 102 2015: 101	August 1, 2013: 101.938 2014: par	July 1, 2013: 105.875 2014: 102.938 2015: par	August 15, 2014: 104.563 2015: 103.042 2016: 101.521 2017: par	July 1, 2019: 102.000 2020: par	April 1, 2013: 101.188 2014: par
Make-whole redemption (7)	N/A		N/A	N/A	N/A	N/A	Callable prior to August 15, 2014 at make-whole call price of Treasury +50 bps	Callable prior to July 1, 2019 at make-whole call price of Treasury +50 bps	N/A
Change of control (7)	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	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest
Equity clawback (7)	N/A		N/A	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 (8)	$149.7 million		$600 million	$192 million	$10.1 million	$8.3 million	$271.6 million	$307.1 million	$332.9 million

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⁽¹⁾  Borrowings under the Amended and Restated U.S. Credit Facility, Senior Secured Second Lien Credit Agreement and Senior Secured 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 Senior Secured Second Lien Credit Agreement and the Senior Secured 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, 2013.

⁽³⁾  The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the 2015 Senior Notes, the 2016 Senior Notes, the 2016 Senior Subordinated Notes, the Senior Secured Second Lien Credit Agreement or the Senior Secured Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Senior Secured Second Lien Credit Agreement and Senior Secured 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 2015 Senior Notes, the 2016 Senior Notes or the 2016 Senior Subordinated Notes if on the applicable date the aggregate amount of all such notes remaining outstanding is greater than $100 million.

⁽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⁾  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.

⁽⁸⁾  The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). Our Senior Secured Second Lien Credit Agreement and Senior Secured 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. ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the nine months endedSeptember 30, 2013.

	(In thousands)
Beginning asset retirement obligations	$	116,526
Additional liability incurred	3,193
Change in estimates	586
Accretion expense	3,917
Asset retirement costs incurred	(1,539		)
Settlement of liability in excess of obligation recorded	867
Disposition	(21,910		)
Currency translation adjustment	(1,903		)
Ending asset retirement obligations	99,737
Less current portion	(577		)
Long-term asset retirement obligation	$	99,160

7. INCOME TAXES

Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that we expect will be in effect during years in which we expect the temporary differences will reverse. Net operating loss carry-forwards and other deferred tax assets are reviewed for recoverability, and if necessary, are recorded net of a valuation allowance. At September 30, 2013, our U.S. and Canadian valuation allowances are $445.9 million and $64.4 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 benefits primarily related to our cumulative net operating losses. Income tax recognized for the three and nine months ended September 30, 2013 is a result of hedge gains previously deferred in AOCI being realized during the periods and the net tax impact being recognized.

8. COMMITMENTS AND CONTINGENCIES

Contractual Obligations, Commitments and Contingencies

In August 2013, we subleased a portion of our corporate offices. The sublease will reduce our future office space commitment by $2.2 million over the term of the lease.

In July 2013, in light of the Canadian Governor in Council's failure to approve NGTL's construction of the Komie North Project, NGTL terminated the Project and Expenditure Authorization (PEA), which authorized NGTL to construct the Komie North Project and the related meter station. The PEA necessitated the construction of a treatment facility and required financial guarantees to cover NGTL's costs for the Komie North Project. We recognized $12.8 million in related actual costs incurred by NGTL, which is reflected in other income (expense) in our consolidated financial statements. We paid NGTL in August 2013 after which the related letter of credit was terminated. With the termination of the PEA described above, our agreement to deliver gas to the Komie North Project has also terminated. We maintain our ability to sell gas at the Station 2 and AECO hubs, as our current production is served by existing treating facilities and pipelines.

22

In April 2013, we increased our outstanding letter of credit by C$13 million for the step-up of treating commitments in the Horn River Basin. In August 2013, we reduced our outstanding letters of credit by C$14 million upon a payment to NGTL related to the Komie North Project.

In December 2012, Vantage Fort Worth Energy LLC (“Plaintiff”) served a lawsuit against us and others in the 352nd Judicial District Court of Texas in Tarrant County asserting claims for trespass to try title, suit to quiet title, trespass and conversion in connection with 16 wells located on a 158.75 acre tract located in Tarrant County, Texas. On May 8, 2013, all parties to the suit entered into a settlement agreement, effective April 1, 2013, whereby we assigned to Plaintiff various property and equipment and Plaintiff agreed to non-suit all of the Defendants in the matter. The court entered its Order of Dismissal with prejudice on May 13, 2013. We recognized an expense of $0.4 million in connection with this settlement.

In July 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arises out of press releases in 2011 questioning the projected decline curves and economics of shale gas wells. In June 2012, we received an additional request from the SEC for certain information regarding our assessment for impairment of unevaluated properties and plans for development of unevaluated properties. We provided responsive information and in February 2013 we met with the SEC.

Note 14 to the consolidated financial statements in our 2012 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, 2013.

9. FORTUNE CREEK

Note 16 to the consolidated financial statements in our 2012 Annual Report on Form 10-K contains additional information on Fortune Creek. We committed to minimum gross capital expenditures of $300 million for drilling and completion activities in our Horn River Asset between 2012 and 2014, of which we have achieved $170.9 million as of September 30, 2013, and pursuant to the partnership agreement will be required to achieve an additional $9.1 million by December 31, 2013, with the balance to be achieved through December 31, 2014; provided further that up to $20 million could be deferred until December 31, 2015. These minimum expenditure commitments include gross capital expenditures for wells in which we have a working interest regardless of our working interest percentage. To the extent these minimum capital expenditure commitments are not met, we will incur a penalty in an amount equal to the shortfall, which will be applied against the gathering agreement requirement. Additionally, we committed gas production from our Horn River Asset for ten years beginning 2012, as more fully described below. KKR contributed $125 million cash in exchange for a 50% interest in Fortune Creek. Our Canadian subsidiary has responsibility for the day-to-day operations of Fortune Creek.

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

10. 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, 2013 and December 31, 2012, we had 177.1 million and 173.1 million shares of common stock outstanding, respectively.

On May 15, 2013, our stockholders approved an amendment to the 2006 Equity Plan, which increased the shares available for issuance under the plan by 12 million shares. Note 17 to the consolidated financial statements in our 2012 Annual Report on Form 10-K contains additional information about our equity-based compensation plan.

23

Stock Options

Options to purchase shares of common stock were granted in 2013 with an estimated fair value of $1.6 million. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the nine months ended September 30:

	2013	2012
Weighted avg grant date fair value	$1.05	$4.21
Weighted avg risk-free interest rate	1.31%	1.14%
Expected life	4.9 years	6.0 years
Wtd avg volatility	69.0%	68.2%
Expected dividends	—	—

The following table summarizes our stock option activity for the nine months endedSeptember 30, 2013:

	Shares		Wtd Avg Exercise Price		Wtd Avg Remaining Contractual Life	Aggregate Intrinsic Value
					(In years)	(In thousands)
Outstanding at January 1, 2013	4,979,980		$	10.23
Granted	2,037,467		1.95
Expired	(151,867	)	7.76
Outstanding at September 30, 2013	6,865,580		$	7.83	7.1	$	—
Exercisable at September 30, 2013	4,670,679		$	9.28	6.2	$	—

As of September 30, 2013, we estimate that a total of 6.4 million stock options will become vested including those options already exercisable. As of September 30, 2013, the unrecognized compensation cost related to outstanding unvested stock options was $2.7 million, which is expected to be recognized in expense through June 2015. Compensation expense related to stock options of $3.2 million and $5.9 million was recognized for each of the nine months endedSeptember 30, 2013 and 2012, respectively.

Restricted Stock

The following table summarizes our restricted stock and stock unit activity for the nine months endedSeptember 30, 2013:

	Payable in shares				Payable in cash
	Shares		Wtd Avg Grant Date Fair Value		Shares		Wtd Avg Grant Date Fair Value
Outstanding at January 1, 2013	3,099,135		$	8.48	678,217		$	7.71
Granted	6,102,133		2.74		1,468,695		2.83
Vested	(2,018,457	)	7.57		(284,406	)	8.51
Forfeited	(1,303,113	)	3.63		(298,138	)	3.88
Outstanding at September 30, 2013	5,879,698		$	3.91	1,564,368		$	3.72

As of September 30, 2013, the unrecognized compensation cost related to outstanding unvested restricted stock was $15.6 million, which is expected to be recognized in expense through March 2016. Grants of restricted stock and RSUs during the nine months endedSeptember 30, 2013 had an estimated grant date fair value of $20.9 million. The fair value of outstanding RSUs to be settled in cash is $3.1 million at September 30, 2013. For the nine months endedSeptember 30, 2013 and 2012, compensation expense related to restricted stock and RSUs of $12.2 million and $11.9 million, respectively, was recognized. The total fair value of shares vested during the nine months endedSeptember 30, 2013 was $5.6 million.

In the second quarter of 2013, the Company recognized $3.6 million in stock-based compensation to correct for assumptions on forfeitures and vesting for retirement eligible and imminently retirement eligible individuals, including $2.2 million which pertains to periods before 2013.

24

11.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,
	2013			2012			2013			2012
				(Restated)						(Restated)
	(In thousands, except per share data)
Net income (loss) attributable to Quicksilver	$	10,577		$	(790,520	)	$	193,397		$	(1,804,107	)
Basic income allocable to participating securities (1)	(312		)	—			$	(5,111	)	$	—
Income (loss) available to shareholders	$	10,265		$	(790,520	)	$	188,286		$	(1,804,107	)
Weighted average common shares – basic	171,682			170,179			171,403			170,054
Effect of dilutive securities (2)
Share-based compensation awards	311			—			170			—
Weighted average common shares – diluted	171,993			170,179			171,573			170,054
Earnings (loss) per common share – basic	$	0.06		$	(4.65	)	$	1.10		$	(10.61	)
Earnings (loss) per common share – diluted	$	0.06		$	(4.65	)	$	1.10		$	(10.61	)

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

⁽²⁾  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 restricted stock units were antidilutive; therefore, excluded from the diluted share calculation. For the three months ended September 30, 2012, 5.0 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units were antidilutive; therefore, excluded from the diluted share calculation. 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 restricted stock units were antidilutive; therefore, excluded from the diluted share calculation. For the nine months ended September 30, 2012, 5.0 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units were antidilutive; therefore, excluded from the diluted share calculation.

25

12. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Note 19 to the consolidated financial statements in our 2012 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 nine-month period covered by the consolidated financial statements. Under the indentures for our senior notes and senior subordinated notes, Fortune Creek is not considered to be a subsidiary and therefore it is presented separately from the other subsidiaries for these purposes.

Condensed Consolidating Balance Sheets

	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)
ASSETS
Current assets	$	315,788		$	10,016		$	61,101		$	(35,986	)	$	350,919		$	2,443		$	1,428		$	(4,842	)	$	349,948
Property and equipment	457,139			15,757			304,754			—			777,650			—			85,282			—			862,932
Investment in subsidiaries (equity method)	(211,041		)	—			(33,931		)	211,041			(33,931		)	(33,931		)	—			67,862			—
Other assets	476,322			—			33,134			(390,723		)	118,733			—			—			—			118,733
Total assets	$	1,038,208		$	25,773		$	365,058		$	(215,668	)	$	1,213,371		$	(31,488	)	$	86,710		$	63,020		$	1,331,613
LIABILITIES AND EQUITY
Current liabilities	$	107,325		$	11,802		$	35,835		$	(35,986	)	$	118,976		$	2,423		$	(899	)	$	(4,842	)	$	115,658
Long-term liabilities	1,895,402			19,242			522,245			(390,723		)	2,046,166			—			1,575			132,732			2,180,473
Stockholders' equity	(964,519		)	(5,271		)	(193,022		)	211,041			(951,771		)	(33,911		)	86,034			(64,870		)	(964,518		)
Total liabilities and equity	$	1,038,208		$	25,773		$	365,058		$	(215,668	)	$	1,213,371		$	(31,488	)	$	86,710		$	63,020		$	1,331,613

	December 31, 2012
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non- Guarantor Subsidiaries			Restricted Subsidiary Eliminations			Quicksilver and Restricted Subsidiaries			Unrestricted Non- Guarantor Subsidiaries			Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
ASSETS
Current assets	$	261,130		$	105,695		$	76,088		$	(222,586	)	$	220,327		$	13,250		$	391	$	(26,455	)	$	207,513
Property and equipment	621,073			20,007			296,462			—			937,542			—			91,516		—			1,029,058
Investment in subsidiaries (equity method)	(191,725		)	—			(42,883		)	191,725			(42,883		)	(42,905		)	—		85,788			—
Other assets	346,972			—			41,865			(243,620		)	145,217			—			—		—			145,217
Total assets	$	1,037,450		$	125,702		$	371,532		$	(274,481	)	$	1,260,203		$	(29,655	)	$	91,907	$	59,333		$	1,381,788
LIABILITIES AND EQUITY
Current liabilities	$	255,678		$	112,133		$	33,475		$	(222,586	)	$	178,700		$	13,230		$	2,316	$	(26,455	)	$	167,791
Long-term liabilities	1,914,568			19,242			524,107			(243,620		)	2,214,297			—			1,585		130,912			2,346,794
Stockholders' equity	(1,132,796		)	(5,673		)	(186,050		)	191,725			(1,132,794		)	(42,885		)	88,006		(45,124		)	(1,132,797		)
Total liabilities and equity	$	1,037,450		$	125,702		$	371,532		$	(274,481	)	$	1,260,203		$	(29,655	)	$	91,907	$	59,333		$	1,381,788

26

Condensed Consolidating Statements of Income

	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 Three Months Ended September 30, 2012 (Restated)
	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	$	108,366		$	1,182	$	9,336		$	(696	)	$	118,188		$	—	$	4,422	$	(4,422	)	$	118,188
Operating expenses	600,696			739		95,412			(696		)	696,151			—		3,010		(4,422		)	694,739
Equity in net earnings of subsidiaries	(71,911		)	—		(2,269		)	71,911			(2,269		)	1,443		—		826			—
Operating income (loss)	(564,241		)	443		(88,345		)	71,911			(580,232		)	1,443		1,412		826			(576,551		)
Fortune Creek accretion	—			—		—			—			—			—		—		(4,978		)	(4,978		)
Interest expense and other	(37,964		)	—		(4,586		)	—			(42,550		)	22		31		—			(42,497		)
Income tax (expense) benefit	(188,457		)	142		20,577			—			(167,738		)	—		—		1,244			(166,494		)
Net income	$	(790,662	)	$	585	$	(72,354	)	$	71,911		$	(790,520	)	$	1,465	$	1,443	$	(2,908	)	$	(790,520	)
Other comprehensive income (loss)	(40,955		)	—		(5,660		)	—			(46,615		)	—		—		—			(46,615		)
Equity in OCI of subsidiaries	(5,660		)	—		—			5,660			—			—		—		—			—
Comprehensive income (loss)	$	(837,277	)	$	585	$	(78,014	)	$	77,571		$	(837,135	)	$	1,465	$	1,443	$	(2,908	)	$	(837,135	)

27

	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

	For the Nine Months Ended September 30, 2012 (Restated)
	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	$	429,774		$	3,390	$	54,202		$	(2,294	)	$	485,072		$	—	$	10,021	$	(10,021	)	$	485,072
Operating expenses	2,082,777			2,541		444,621			(2,294		)	2,527,645			—		6,093		(10,021		)	2,523,717
Crestwood earn-out	41,097			—		—			—			41,097			—		—		—			41,097
Equity in net earnings of subsidiaries	(305,205		)	—		(6,931		)	305,205			(6,931		)	3,959		—		2,972			—
Operating income (loss)	(1,917,111		)	849		(397,350		)	305,205			(2,008,407		)	3,959		3,928		2,972			(1,997,548		)
Fortune Creek accretion	—			—		—			—			—			—		—		(14,549		)	(14,549		)
Interest expense and other	(114,578		)	—		(8,060		)	—			(122,638		)	22		31		—			(122,585		)
Income tax (expense) benefit	227,582			—		99,356			—			326,938			—		—		3,637			330,575
Net income	$	(1,804,107	)	$	849	$	(306,054	)	$	305,205		$	(1,804,107	)	$	3,981	$	3,959	$	(7,940	)	$	(1,804,107	)
Other comprehensive income (loss)	(48,694		)	—		3,778			—			(44,916		)	—		—		—			(44,916		)
Equity in OCI of subsidiaries	3,778			—		—			(3,778		)	—			—		—		—			—
Comprehensive income (loss)	$	(1,849,023	)	$	849	$	(302,276	)	$	301,427		$	(1,849,023	)	$	3,981	$	3,959	$	(7,940	)	$	(1,849,023	)

28

Condensed Consolidating Statements of Cash Flows

	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 (decrease) 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

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

29

13. SEGMENT INFORMATION

We operate in two geographic segments, the U.S. and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. Additionally, we operate a significantly smaller midstream segment in the U.S. and Canada, where we provide natural gas gathering and processing services, primarily to our U.S. and Canadian exploration and production segments. Following the formation of our partnership with KKR, beginning in January 2012, we have additional midstream operations in Canada through Fortune Creek. 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)
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
2012 (Restated)
Revenue	$	108,365		$	8,859		$	6,082	$	—		$	(5,118	)	$	118,188
DD&A	23,205			8,938			1,281		590			—			34,014
Impairment expense	479,905			66,282			4,945		—			—			551,132
Operating income (loss)	(476,542		)	(82,528		)	443		(17,924		)	—			(576,551		)
Property and equipment costs incurred	43,722			21,382			1,824		837			—			67,765
For the Nine Months Ended September 30:
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
2012 (Restated)
Revenue	$	429,776		$	52,249		$	15,363	$	—		$	(12,316	)	485,072
DD&A	101,432			29,454			3,810		1,773			—			136,469
Impairment expense	1,700,682			363,160			4,945		—			—			2,068,787
Operating income (loss)	(1,559,594		)	(382,194		)	849		(56,609		)	—			(1,997,548		)
Property and equipment costs incurred	160,699			178,783			13,263		6,284			—			359,029
Property, plant and equipment-net
September 30, 2013	$	452,023		$	303,265		$	101,038	$	6,606		$	—		$	862,932
December 31, 2012	614,071			294,921			111,523		8,543			—			1,029,058
Total assets
September 30, 2013	847,466			365,058			112,483		6,606			—			$	1,331,613
December 31, 2012	784,104			371,532			217,609		8,543			—			1,381,788

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14. SUPPLEMENTAL CASH FLOW INFORMATION

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

	For the Nine Months Ended September 30,
	2013		2012
	(In thousands)
Interest, net of capitalized interest	$	227,189	$	141,811
Income taxes	1,217		(1,528		)

Other significant non-cash transactions were as follows:

	For the Nine Months Ended September 30,
	2013		2012
	(In thousands)
Working capital related to capital expenditures	$	4,867	$	37,386

15. TRANSACTIONS AND OTHER MATTERS WITH RELATED PARTIES

As of September 30, 2013, 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 and Thomas Darden is an employee and director of Quicksilver.

During the first nine months of 2013 and 2012, we paid $0.3 million and $0.4 million, respectively, for use of an airplane owned by an entity controlled by members of the Darden family. Usage rates were determined based upon comparable rates charged by third parties.

Payments received from Mercury, a company owned by members of the Darden family, for sublease rentals, employee insurance coverage and administrative services were less than $0.1 million for the first nine months of 2013 and 2012.

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

In May 2013, we entered into an agreement with Thomas F. Darden with respect to Mr. Darden’s retirement and Mr. Darden’s provision of consulting services following his retirement. Effective May 15, 2013, Mr. Darden retired from his executive position and is expected to remain an employee that does not serve as an officer through December 31, 2013 and a member of the Board of Directors as Chairman Emeritus. While an employee, Mr. Darden will continue to receive his same base salary, benefits and, subject to the execution of a general release and waiver of claims, annual incentive compensation opportunity. In addition, he will be entitled to $12,500 per month, and additional reimbursements, with respect to certain business expenses. In recognition of his contributions to the Tokyo Gas Transaction, Mr. Darden received a cash bonus of $1.1 million paid in two equal installments in May 2013 and August 2013, and a stock option grant with an aggregate grant date fair value of $1.1 million granted in May 2013. Both the cash bonus and the stock option grant are included in the Tokyo Gas Transaction gain on our consolidated financial statements. In connection with his retirement, he is entitled to full vesting of his outstanding unvested equity awards (242,724 shares of restricted stock and 304,407 options); reimbursement of legal fees in connection with the agreement, up to $40,000; and payment of accrued and unused vacation and estimated COBRA premiums. Mr. Darden will be engaged as a consultant for the three-year period following his retirement and will receive a monthly consulting fee of $45,000. In addition, while a consultant, Mr. Darden will be entitled to an office allowance of $12,500 per month, and additional reimbursements, with respect to certain business expenses. In addition, Mr. Darden will be eligible to receive bonuses of up to $2.5 million in the aggregate under certain circumstances in connection with certain possible future strategic transactions occurring on or before December 31, 2016.

31

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 2012 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:

• 2013 Highlights – a summary of significant activities and events affecting Quicksilver

• 2013 Capital Program – a summary of our planned capital expenditures during 2013

• 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

2013 HIGHLIGHTS

Joint Venture Update

In March 2013, we entered into a Purchase and Sale Agreement with TGBR to sell an undivided 25% of our Barnett Shale Asset for a purchase price of $485 million. The transaction closed in April 2013, but was effective as of September 1, 2012. The purchase price was subject to customary purchase price adjustments, which resulted in TGBR paying us $464.0 million, including an estimated final payment of $0.6 million, which we expect to receive in the fourth quarter of 2013. We recognized a gain of $341.1 million before consideration of income taxes as a result of this transaction, including a revision of the gain calculation in the third quarter of 2013 of $7.8 million.

In August 2013, we completed the sale of our Southern Alberta Asset to Synergy with an effective date of January 1, 2013. The purchase price was $46.0 million, which was subject to customary purchase price adjustments, resulting in Synergy paying us $42.3 million. Under the full cost method of accounting, our U.S. exploration and production assets are considered a single asset. 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.

In October and November 2013, we executed two separate agreements involving our West Texas Asset, the largest of which is a joint venture with Eni whereby we will jointly evaluate, explore and develop approximately 52,500 gross acres currently held by us in Pecos County, Texas. Under the terms of the agreement, Eni will pay up to $52.0 million in three phases to earn a 50% interest in our acreage. In the first phase, Eni will fund 100% of the drilling and completion costs of up to a three-well program. Upon funding of the first phase, Eni will earn 50% of our interest in a 7,500 gross acre tract in Pecos County. Eni will then have the option to fund 100% of the drilling and completion costs of another two wells, and will then have the option to fully fund a 3-D seismic survey of the remaining, undeveloped acreage. Upon completion of the three phases, we will participate equally in all future revenue, operating cost and capital expenditures.

We are in negotiations to monetize a portion of our Horn River Asset. We are also considering other asset dispositions or other business combinations.

We cannot provide any assurance that we will be successful in consummating any such prospective transactions.

32

Significant Contract Revisions

In the second quarter of 2013, we refinanced a portion of our debt to extend maturities and reduce the weighted average interest costs on outstanding debt. We also amended our Combined Credit Agreements primarily to loosen the financial covenants through the second quarter of 2016 and to permit the incurrence of up to $825 million of second lien debt. Specific refinancing activities and changes to the Combined Credit Agreements are outlined in Note 5 to the condensed consolidated financial statements in Item 1 of this Quarterly Report.

In July 2013, in light of the Canadian Governor in Council's failure to approve NGTL's construction of the Komie North Project, NGTL terminated the Project and Expenditure Authorization (PEA), which authorized NGTL to construct the Komie North Project and the related meter station. The PEA necessitated the construction of a treatment facility and required financial guarantees to cover NGTL's costs for the Komie North Project. We recognized $12.8 million in related actual costs incurred by NGTL, which is reflected in other income (expense) in our consolidated financial statements. We paid NGTL in August 2013 after which the related letter of credit was terminated. With the termination of the PEA as described above, our agreement to deliver gas to the Komie North Project has also terminated. We maintain our ability to sell gas at the Station 2 and AECO hubs, as our current production is served by existing treating facilities and pipelines.

2013 CAPITAL PROGRAM

We incurred costs related to our capital program of $72.5 million for the first nine months of 2013. We continue to anticipate full-year 2013 spending to be $120 million.

33

RESULTS OF OPERATIONS

Three Months Ended September 30, 2013 and 2012

The following discussion compares the results of operations for the three months ended September 30, 2013 and 2012, or the 2013 quarter and 2012 quarter, respectively. “Other U.S.” refers to the combined amounts for our Niobrara Asset, West Texas Asset and Southern Alberta Asset. The impact of the Synergy Transaction was 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 views 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
	2013		2012		2013			2012		2013		2012		2013		2012
	(In millions)
Barnett Shale	$	39.7	$	48.6	$	18.4		$	29.9	$	1.3	$	2.6	$	59.4	$	81.1
Other U.S.	0.1		0.2		0.1			0.1		2.2		3.3		2.4		3.6
Hedging	13.5		37.9		—			8.5		—		—		13.5		46.4
U.S.	53.3		86.7		18.5			38.5		3.5		5.9		75.3		131.1
Horseshoe Canyon	13.2		11.0		—			—		—		—		13.2		11.0
Horn River	12.3		8.7		—			—		—		—		12.3		8.7
Hedging	3.7		5.5		—			—		—		—		3.7		5.5
Canada	29.2		25.2		—			—		—		—		29.2		25.2
Consolidated production revenue	$	82.5	$	111.9	$	18.5		$	38.5	$	3.5	$	5.9	$	104.5	$	156.3
U.S. realized cash derivative gains (losses)	$	4.3	$	6.6	$	(0.2	)	$	—	$	—	$	—	$	4.1	$	6.6
Canada realized cash derivative gains	3.9		5.8		—			—		—		—		3.9		5.8
Consolidated realized cash derivative gains (losses)	8.2		12.4		(0.2		)	—		—		—		8.0		12.4
Consolidated production revenue and realized cash derivative gains (losses) (1)	$	90.7	$	124.3	$	18.3		$	38.5	$	3.5	$	5.9	$	112.5	$	168.7

⁽¹⁾  Realized cash derivative gains (losses) from derivatives not treated as hedges are included in net derivative gains (losses). Unrealized derivative gains and losses, non-cash loss in fair value from restructured natural gas derivatives and hedge ineffectiveness 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.

34

Average Daily Production Volume:

	Natural Gas		NGL		Oil		Equivalent Total
	2013	2012	2013	2012	2013	2012	2013	2012
	(MMcfd)		(Bbld)		(Bbld)		(MMcfed)
Barnett Shale	124.8	193.2	6,873	11,052	142	322	166.9	261.5
Other U.S.	0.1	0.6	16	18	258	439	1.8	3.4
Total U.S.	124.9	193.8	6,889	11,070	400	761	168.7	264.9
Horseshoe Canyon	49.5	53.9	6	3	—	—	49.5	53.9
Horn River	55.7	43.6	—	—	—	—	55.7	43.6
Total Canada	105.2	97.5	6	3	—	—	105.2	97.5
Total	230.1	291.3	6,895	11,073	400	761	273.9	362.4

Average Realized Price:

	Natural Gas				NGL					Oil				Equivalent Total
	2013		2012		2013			2012		2013		2012		2013		2012
	(per Mcf)				(per Bbl)					(per Bbl)				(per Mcfe)
Barnett Shale	$	3.47	$	2.74	$	29.02		$	29.43	$	99.84	$	87.29	$	3.88	$	3.38
Other U.S.	4.53		2.73		50.05			36.33		95.18		81.39		14.63		11.30
Hedging	1.17		2.12		—			8.31		—		—		0.87		1.90
Total U.S.	4.64		4.87		29.07			37.75		96.83		83.88		4.86		5.38
Horseshoe Canyon	$	2.90	$	2.22	$	34.46		$	45.92	$	—	$	—	$	2.90	$	2.22
Horn River	2.40		2.17		—			—		—		—		2.40		2.17
Hedging	0.38		0.61		—			—		—		—		0.38		0.61
Total Canada	$	3.01	$	2.81	$	42.46		$	45.92	$	—	$	—	$	3.02	$	2.81
Consolidated production revenue	$	3.90	$	4.18	$	29.08		$	37.75	$	96.83	$	83.88	$	4.15	$	4.69
U.S. realized cash derivative gains (losses)	$	0.38	$	0.37	$	(0.26	)	$	—	$	—	$	—	$	0.27	$	0.27
Canada realized cash derivative gains	0.40		0.65		—			—		—		—		0.40		0.65
Consolidated realized cash derivative gains (losses)	0.39		0.46		(0.26		)	—		—		—		0.32		0.37
Consolidated production revenue and realized cash derivative gains	$	4.29	$	4.64	$	28.82		$	37.75	$	96.83	$	83.88	$	4.47	$	5.06

35

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 2012 quarter	$	124,335		$	38,456		$	5,873		$	168,664
Volume variances	(14,403		)	(11,316		)	(2,787		)	(28,506		)
Hedge revenue variances	(26,221		)	(8,465		)	—			(34,686		)
Realized cash derivative variance (1)	(4,202		)	(165		)	—			(4,367		)
Price variances	11,204			(229		)	475			11,450
Consolidated production revenue and realized cash derivative gains for the 2013 quarter	$	90,713		$	18,281		$	3,561		$	112,555

⁽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 derivatives decreased for the 2013 quarter from the 2012 quarter due to lower volumes produced partially offset by an increase in our realized price. Our hedge and realized cash derivative decreased for the 2013 quarter compared to the 2012 quarter due to the expiration of a portion of our derivatives, a lower average strike price on the remaining portfolio and an increase in the natural gas price, all of which reduced our derivative revenue. Consolidated production revenue and realized cash derivative gains from NGL revenue for the 2013 quarter decreased from the 2012 quarter due to lower volumes produced, decreased realized prices and the 2013 quarter including an NGL derivative loss. The decrease in natural gas and NGL volumes is primarily due to the Tokyo Gas Transaction and is partially offset by an increase in volumes in our Horn River Asset as we increased production as wells were completed. The decrease in oil volumes is primarily due to the Synergy Transaction.

At September 30, 2013, we had $2.1 million in deferred revenue related to NGLs held in storage by the purchaser of the NGLs. The title and risk of loss of the NGL volumes have transferred to the purchaser. However, the sales price of the NGLs will not be determined until the NGLs undergo further processing by the purchaser, which began in the third quarter 2013 and is expected to be completed in the fourth quarter of 2013. We have deferred recognition of production and revenue on these NGL volumes as of September 30, 2013.

Our production revenue and realized derivative cash gain (loss) for the 2013 quarter and 2012 quarter was higher by $25.2 million and $64.3 million, respectively, because of our derivative activities.

36

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas

	For the Three Months Ended September 30,
	2013		2012
	(In thousands)
Sales of purchased natural gas
Purchases from Eni	$	14,405	$	20,383
Purchases from others	725		930
Total	15,130		21,313
Costs of purchased natural gas sold
Purchases from Eni	14,405		20,383
Purchases from others	709		871
Total	15,114		21,254
Net sales and purchases of natural gas	$	16	$	59

Net Derivative Gains (Losses)

The following table summarizes our net derivative gains and losses:

	For the Three Months Ended September 30,
	2013			2012
	(In thousands)
Unrealized mark-to-market changes in fair value of natural gas derivative gains (losses) (1)	$	24,385		$	(72,206	)
Realized cash settlements of natural gas derivative gains	8,174			12,376
Unrealized mark-to-market changes in fair value of NGL derivative gains (1)	339			—
Realized cash settlements of NGL derivative losses	(165		)	—
Gain (loss) from hedge ineffectiveness	—			(547		)
Derivative gains (losses), net	$	32,733		$	(60,377	)

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

In 2012 we began to account for the fair value changes of certain natural gas derivatives in the income statement as reflected in the above table.

Other Revenue

	For the Three Months Ended September 30,
	2013		2012
	(In thousands)
Midstream revenue from third parties:
Canada	$	496	$	478
Texas	211		486
Total	$	707	$	964

37

Operating Expense

Lease Operating

	For the Three Months Ended September 30,
	2013						2012
	(In thousands, except per unit amounts)
				Per Mcfe					Per Mcfe
Barnett Shale
Expense	$	10,351		$	0.67		$	11,464	$	0.48
Equity compensation expense	99			0.01			201		0.01
	$	10,450		$	0.68		$	11,665	$	0.49
Other U.S.
Expense	$	889		$	5.46		$	2,149	$	6.94
Equity compensation expense	(23		)	(0.14		)	39		0.13
	$	866		$	5.32		$	2,188	$	7.07
Total U.S.
Expense	$	11,240		$	0.72		$	13,613	$	0.56
Equity compensation expense	76			—			240		0.01
	$	11,316		$	0.72		$	13,853	$	0.57
Horseshoe Canyon
Expense	$	6,408		$	1.41		$	7,378	$	1.49
Equity compensation expense	84			0.02			85		0.02
	$	6,492		$	1.43		$	7,463	$	1.51
Horn River
Expense	$	783		$	0.15		$	799	$	0.20
Equity compensation expense	—			—			—		—
	$	783		$	0.15		$	799	$	0.20
Total Canada
Expense	$	7,191		$	0.74		$	8,177	$	0.91
Equity compensation expense	84			0.01			85		0.01
	$	7,275		$	0.75		$	8,262	$	0.92
Total Company
Expense	$	18,431		$	0.73		$	21,790	$	0.65
Equity compensation expense	160			0.01			325		0.01
	$	18,591		$	0.74		$	22,115	$	0.66

Lease operating expense for the 2013 quarter in the Barnett Shale decreased in total primarily due to the Tokyo Gas Transaction, partially offset by a non-cash inventory impairment in the 2013 quarter. On a unit basis, the increase is primarily due to the non-cash inventory impairment and, to a lesser extent, fixed lease operating charges being distributed over lower volumes due to natural well decline curves compared to the 2012 quarter. In Other U.S., the decrease on a gross and unit basis is primarily due to the Synergy Transaction.

38

Gathering, Processing and Transportation

	For the Three Months Ended September 30,
	2013				2012
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale	$	23,398	$	1.52	$	33,894	$	1.41
Other U.S.	2		0.01		3		0.01
Total U.S.	23,400		1.51		33,897		1.39
Horseshoe Canyon	718		0.16		822		0.17
Horn River	11,449		2.23		6,619		1.65
Total Canada	12,167		1.26		7,441		0.83
Total	$	35,567	$	1.41	$	41,338	$	1.24

U.S. GPT on a gross basis decreased primarily due to lower volumes in our Barnett Shale Asset, with the Tokyo Gas Transaction contributing to this decline. On a unit basis, the 2013 quarter was higher primarily due to unused firm capacity for our natural gas transportation contracts and higher fuel transportation charges. Canadian GPT increased in total for the 2013 quarter as compared to the 2012 quarter as a result of increased volumes in our Horn River Asset, and increased on a unit basis in the Horn River primarily as a result of higher fixed costs under our firm agreements with third parties. Canadian GPT includes payments made for unused firm capacity of $1.7 million and $1.4 million for the 2013 quarter and the 2012 quarter, respectively.

Production and Ad Valorem Taxes

	For the Three Months Ended September 30,
	2013						2012
	(In thousands, except per unit amounts)
				Per Mcfe					Per Mcfe
Production taxes
Barnett Shale	$	848		$	0.06		$	961	$	0.04
Other U.S.	172			1.05			231		0.74
Total U.S.	1,020			0.07			1,192		0.05
Horseshoe Canyon	(66		)	(0.01		)	50		0.01
Horn River	—			—			—		—
Total Canada	(66		)	(0.01		)	50		0.01
Total production taxes	954			0.04			1,242		0.04
Ad valorem taxes
Barnett Shale	$	2,645		$	0.17		$	4,653	$	0.19
Other U.S.	178			1.09			94		0.28
Total U.S.	2,823			0.18			4,747		0.19
Horseshoe Canyon	948			0.21			795		0.16
Horn River	(47		)	(0.01		)	97		0.02
Total Canada	901			0.09			892		0.10
Total ad valorem taxes	3,724			0.15			5,639		0.17
Total	$	4,678		$	0.19		$	6,881	$	0.21

39

Depletion, Depreciation and Accretion

	For the Three Months Ended September 30,
	2013				2012
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Depletion
U.S.	$	7,880	$	0.51	$	22,362	$	0.92
Canada	1,058		0.11		5,906		0.66
Total depletion	8,938		0.35		28,268		0.85
Depreciation of other fixed assets
U.S.	$	1,802	$	0.12	$	2,146	$	0.09
Canada	2,377		0.25		2,536		0.28
Total depreciation	4,179		0.17		4,682		0.14
Accretion	1,273		0.05		1,064		0.03
Total	$	14,390	$	0.57	$	34,014	$	1.02

U.S. depletion for the 2013 quarter, when compared to the 2012 quarter, reflected a decrease in production and a decrease in the current year depletion rate due to impairments recognized in 2012. Canadian depletion decreased for the 2013 quarter, when compared to the 2012 quarter, due to a decrease in the current year depletion rate as a result of impairment recognized in 2012 partially offset by an increase in production.

Impairment Expense

We perform quarterly ceiling tests to assess impairment of our oil and gas properties. We also assess our fixed assets reported outside the full-cost pool when circumstances indicate impairment may have occurred. The calculation of impairment expense is more fully described in Note 4 to the condensed consolidated interim financial statements in Item 1 of this Quarterly Report.

In the 2012 quarter, we recognized $479.9 million and $66.3 million in non-cash charges for impairment of our U.S. and Canadian oil and gas properties, respectively, and $4.9 million for impairment of other property and equipment in the U.S. No impairment was recognized in the 2013 quarter.

General and Administrative

	For the Three Months Ended September 30,
	2013				2012
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Expense	$	6,965	$	0.28	$	8,856	$	0.27
Audit and accounting fees	334		0.01		845		0.03
Strategic transaction costs	823		0.03		998		0.03
Equity compensation	2,349		0.09		6,636		0.20
Total	$	10,471	$	0.41	$	17,335	$	0.53

The decrease in general and administrative expense is primarily due to reduced employee incentive compensation during the 2013 quarter compared to the 2012 quarter. The decrease in equity compensation is primarily due to reduced headcount during the 2013 quarter.

Tokyo Gas Transaction Gain

In the 2013 quarter, we revised our Tokyo Gas Transaction gain which resulted in an increase of $7.8 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.

40

Fortune Creek Accretion

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

Interest Expense

	For the Three Months Ended September 30,
	2013			2012
	(In thousands)
Interest costs on debt outstanding	$	39,443		$	44,081
Add:
Fees paid on letters of credit outstanding	71			—
Discount received on senior notes repurchased	(28		)	—
Non-cash interest (1)	1,870			4,592
Total interest costs incurred	41,356			48,673
Less:
Interest capitalized	(2,001		)	(6,571		)
Interest expense	$	39,355		$	42,102

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

Interest costs incurred for the 2013 quarter were lower when compared to the 2012 quarter primarily because of the refinancing of our debt securities in 2013, which reduced our weighed average interest rate.

Income Taxes

The effective tax rates for the three months ended September 30, 2013 and 2012 are as follows:

	For the Three Months Ended September 30,
	2013			2012
	(in thousands)
Income tax (benefit) expense - U.S.	$	4,755		$	188,316
Effective tax rate-U.S.	41.0		%	(35.5		)%
Income tax (benefit) expense - Canada	$	1,211		$	(21,822	)
Effective tax rate-Canada	25.0		%	23.2		%
Income tax (benefit) expense - total	$	5,966		$	166,494
Effective tax rate-total	36.1		%	(26.7		)%

Income tax expense for the 2013 quarter included a reduction in the U.S. valuation allowance of $26.3 million and an increase in the Canadian valuation allowance of $1.9 million. During the latter half of 2012, we determined a reduced likelihood of realizing deferred tax benefits primarily related to our cumulative net operating losses. Income tax recognized for the 2013 quarter is a result of hedge gains previously deferred in AOCI being realized during the quarter and the net tax impact being recognized. The effective rate for the 2012 quarter reflected a projection of a full year of Canadian taxable losses and a valuation allowance in the U.S.

41

RESULTS OF OPERATIONS

Nine Months EndedSeptember 30, 2013 and 2012

The following discussion compares the results of operations for the nine months ended September 30, 2013 and 2012, or the 2013 period and 2012 period, respectively. “Other U.S.” refers to the combined amounts for our Niobrara Asset, West Texas Asset and Southern Alberta Asset. The impact of the Synergy Transaction was 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 views 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
	2013		2012		2013			2012		2013		2012		2013		2012
	(In millions)
Barnett Shale	$	141.8	$	145.5	$	59.6		$	108.8	$	4.9	$	8.8	$	206.3	$	263.1
Other U.S.	0.1		0.5		0.3			0.3		8.7		10.6		9.1		11.4
Hedging	43.2		122.9		—			15.1		—		—		43.2		138.0
U.S.	185.1		268.9		59.9			124.2		13.6		19.4		258.6		412.5
Horseshoe Canyon	43.1		33.4		0.1			0.1		—		—		43.2		33.5
Horn River	46.8		13.4		—			—		—		—		46.8		13.4
Hedging	9.7		13.7		—			—		—		—		9.7		13.7
Canada	99.6		60.5		0.1			0.1		—		—		99.7		60.6
Consolidated production revenue	$	284.7	$	329.4	$	60.0		$	124.3	$	13.6	$	19.4	$	358.3	$	473.1
U.S. realized cash derivative gains (losses)	$	5.8	$	19.1	$	(0.2	)	$	—	$	—	$	—	$	5.6	$	19.1
Canada realized cash derivative gains	8.5		16.0		—			—		—		—		8.5		16.0
Consolidated realized cash derivative gains (losses)	14.3		35.1		(0.2		)	—		—		—		14.1		35.1
Consolidated production revenue and realized cash derivative gains (1)	$	299.0	$	364.5	$	59.8		$	124.3	$	13.6	$	19.4	$	372.4	$	508.2

⁽¹⁾  Realized cash derivative gains from derivatives not treated as hedges are included in net derivative gains (losses). Unrealized derivative gains and losses, non-cash loss in fair value from restructured natural gas derivatives and hedge ineffectiveness 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.

42

Average Daily Production Volume:

	Natural Gas		NGL		Oil		Equivalent Total
	2013	2012	2013	2012	2013	2012	2013	2012
	(MMcfd)		(Bbld)		(Bbld)		(MMcfed)
Barnett Shale	145.9	214.2	7,852	11,293	193	349	194.2	284.1
Other U.S.	0.1	0.7	20	23	363	455	2.4	3.6
Total U.S.	146.0	214.9	7,872	11,316	556	804	196.6	287.7
Horseshoe Canyon	49.9	55.0	6	5	—	—	49.9	55.0
Horn River	59.4	23.3	—	—	—	—	59.3	23.3
Total Canada	109.3	78.3	6	5	—	—	109.2	78.3
Total	255.3	293.2	7,878	11,321	556	804	305.8	366.0

Average Realized Price:

	Natural Gas				NGL					Oil				Equivalent Total
	2013		2012		2013			2012		2013		2012		2013		2012
	(per Mcf)				(per Bbl)					(per Bbl)				(per Mcfe)
Barnett Shale	$	3.56	$	2.48	$	27.78		$	35.15	$	92.38	$	92.01	$	3.90	$	3.38
Other U.S.	4.72		2.38		51.00			49.74		87.43		85.35		13.08		11.66
Hedging	1.08		2.09		—			4.86		—		—		0.80		1.75
Total U.S.	$	4.64	$	4.57	$	27.84		$	40.05	$	89.15	$	88.24	$	4.82	$	5.23
Horseshoe Canyon	$	3.16	$	2.21	$	55.62		$	66.18	$	—	$	—	$	3.17	$	2.22
Horn River	2.89		2.10		—			—		—		—		2.89		2.10
Hedging	0.32		0.64		—			—		—		—		0.32		0.64
Total Canada	$	3.34	$	2.82	$	55.62		$	66.18	$	—	$	—	$	3.34	$	2.82
Consolidated production revenue	$	4.09	$	4.10	$	27.87		$	40.06	$	89.15	$	88.24	$	4.29	$	4.72
U.S. realized cash derivative gains (losses)	$	0.15	$	0.32	$	(0.08	)	$	—	$	—	$	—	$	0.10	$	0.24
Canada realized cash derivative gains	0.29		0.75		—			—		—		—		0.29		0.74
Consolidated realized cash derivative gains (losses)	$	0.21	$	0.44	$	(0.08	)	$	—	$	—	$	—	$	0.17	$	0.35
Consolidated production revenue and realized cash derivative gains	$	4.30	$	4.54	$	27.79		$	40.06	$	89.15	$	88.24	$	4.46	$	5.07

43

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 2012 period	$	364,396		$	124,265		$	19,451		$	508,112
Volume variances	(25,530		)	(33,492		)	(6,049		)	(65,071		)
Hedge revenue variances	(83,714		)	(15,072		)	—			(98,786		)
Realized cash derivative variance (1)	(20,765		)	(165		)	—			(20,930		)
Price variances	64,724			(15,773		)	134			49,085
Consolidated production revenue and realized cash derivative gains for the 2013 period	$	299,111		$	59,763		$	13,536		$	372,410

⁽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 derivatives decreased for the 2013 period from the 2012 period due to lower volumes produced partially offset by an increase in our realized price. Our hedge and realized cash derivative decreased for the 2013 period compared to the 2012 period due to the expiration of a portion of our derivatives, a lower average strike price on the remaining portfolio and an increase in the natural gas price, all of which reduced our derivative revenue. Consolidated production revenue and realized cash derivative gains from NGL revenue for the 2013 period decreased from the 2012 period due to lower volumes produced, decreased realized prices and the 2013 period including an NGL derivative loss. The decrease in natural gas and NGL volumes is primarily due to the Tokyo Gas Transaction and is partially offset by an increase in volumes in our Horn River Asset as we increased production as wells were completed in 2012.

At September 30, 2013, we had $2.1 million in deferred revenue related to NGLs held in storage by the purchaser of the NGLs. The title and risk of loss of the NGL volumes have transferred to the purchaser. However, the sales price of the NGLs will not be determined until the NGLs undergo further processing by the purchaser, which began in the third quarter of 2013 and is expected to be completed in the fourth quarter of 2013. We have deferred recognition of production and revenue on these NGL volumes as of September 30, 2013.

Our production revenue for the 2013 period and 2012 period was higher by $67.0 million and $186.8 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,
	2013		2012
	(In thousands)
Sales of purchased natural gas
Purchases from Eni	$	48,208	$	40,253
Purchases from others	2,165		2,588
Total	50,373		42,841
Costs of purchased natural gas sold
Purchases from Eni	48,207		40,288
Purchases from others	2,104		2,240
Total	50,311		42,528
Net sales and purchases of natural gas	$	62	$	313

44

Net Derivative Gains (Losses)

The following table summarizes our net derivative gains and losses:

	For the Nine Months Ended September 30,
	2013			2012
	(In thousands)
Unrealized mark-to-market changes in fair value of natural gas derivative gains (losses) (1)	$	21,734		$	(56,147	)
Realized cash settlements of natural gas derivative gains	14,294			35,059
Non-cash loss in fair value from restructured natural gas derivatives	—			(13,836		)
Unrealized mark-to-market changes in fair value of NGL gains (1)	339			—
Realized cash settlements of NGL derivative losses	(165		)	—
Gain (loss) from hedge ineffectiveness	—			1,022
Derivative gains (losses), net	36,202			(33,902		)

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

In 2012 we began to account for the fair value changes of certain natural gas derivatives in the income statement as reflected in the above table. In 2012 we terminated a number of our ten-year derivative instruments in exchange for derivative instruments with shorter durations at above market terms. The decrease in the fair value between the terminated ten-year instrument and the new shorter term instrument was recognized as a non-cash loss in fair value from restructured derivatives.

Other Revenue

	For the Nine Months Ended September 30,
	2013		2012
	(In thousands)
Midstream revenue from third parties
Canada	$	1,810	$	1,952
Texas	652		1,096
Total midstream revenue	2,462		3,048
Other	—		32
Total	$	2,462	$	3,080

45

Operating Expense

Lease Operating

	For the Nine Months Ended September 30,
	2013				2012
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale
Expense	$	33,785	$	0.64	$	41,633	$	0.53
Equity compensation expense	568		0.01		842		0.01
	$	34,353	$	0.65	$	42,475	$	0.54
Other U.S.
Expense	$	3,911	$	5.96	$	6,448	$	6.59
Equity compensation expense	174		0.27		126		0.13
	$	4,085	$	6.23	$	6,574	$	6.72
Total U.S.
Expense	$	37,696	$	0.70	$	48,081	$	0.61
Equity compensation expense	742		0.01		968		0.01
	$	38,438	$	0.71	$	49,049	$	0.62
Horseshoe Canyon
Expense	$	21,793	$	1.60	$	21,011	$	1.39
Equity compensation expense	197		0.01		293		0.02
	$	21,990	$	1.61	$	21,304	$	1.41
Horn River
Expense	$	3,271	$	0.20	$	2,052	$	0.32
Equity compensation expense	—		—		—		—
	$	3,271	$	0.20	$	2,052	$	0.32
Total Canada
Expense	$	25,064	$	0.84	$	23,063	$	1.07
Equity compensation expense	197		0.01		293		0.01
	$	25,261	$	0.85	$	23,356	$	1.08
Total Company
Expense	$	62,760	$	0.75	$	71,144	$	0.71
Equity compensation expense	939		0.01		1,261		0.01
	$	63,699	$	0.76	$	72,405	$	0.72

Lease operating expense for the 2013 period in the Barnett Shale decreased in total primarily due to the Tokyo Gas Transaction, partially offset by a non-cash inventory impairment in the 2013 quarter. On a unit basis, the Barnett Shale increased primarily due to fixed lease operating charges being distributed over lower volume compared to the 2012 period. In Canada, the increase in lease operating expense on a gross basis compared to the 2012 period is primarily due to increased volumes in our Horn River Asset. The reduction on a unit basis is due to the increased volumes in our Horn River Asset as fixed lease operating costs were distributed over higher volumes compared to the 2012 period.

46

Gathering, Processing and Transportation

	For the Nine Months Ended September 30,
	2013				2012
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale	$	80,136	$	1.51	$	108,996	$	1.40
Other U.S.	8		0.01		11		0.01
Total U.S.	80,144		1.49		109,007		1.38
Horseshoe Canyon	2,335		0.17		2,850		0.19
Horn River	29,585		1.82		15,182		2.37
Total Canada	31,920		1.07		18,032		0.84
Total	$	112,064	$	1.34	$	127,039	$	1.27

U.S. GPT on a gross basis decreased primarily due to lower volumes in our Barnett Shale Asset, with the Tokyo Gas Transaction also contributing to this decline. On a unit basis, the 2013 period was higher primarily due to higher unused firm capacity for our natural gas transportation in the 2013 period compared to the 2012 period and higher transportation fuel charges in the 2013 period as the price of natural gas has increased. To a lesser extent the increase was a result of deferred NGL sales production to later in 2013 without a reduction in transportation expense as the NGLs were transported to a third-party facility for storage. Canadian GPT increased in total for the 2013 period as compared to the 2012 period as a result of increased volumes in our Horn River Asset, and decreased on a unit basis in the Horn River primarily as a result of fixed costs under our firm agreements with third parties being spread over increased volumes in the 2013 period. Canadian GPT includes payments made for unused firm capacity of $4.6 million and $5.2 million for the 2013 period and the 2012 period, respectively.

Production and Ad Valorem Taxes

	For the Nine Months Ended September 30,
	2013					2012
	(In thousands, except per unit amounts)
				Per Mcfe				Per Mcfe
Production taxes
Barnett Shale	$	2,807		$	0.05	$	3,608	$	0.05
Other U.S.	650			0.99		639		0.65
Total U.S.	3,457			0.06		4,247		0.05
Horseshoe Canyon	(30		)	—		102		0.01
Horn River	—			—		—		—
Total Canada	(30		)	—		102		0.01
Total production taxes	3,427			0.04		4,349		0.04
Ad valorem taxes
Barnett Shale	$	9,102		$	0.17	$	13,823	$	0.18
Other U.S.	444			0.68		368		0.37
Total U.S.	9,546			0.18		14,191		0.18
Horseshoe Canyon	2,006			0.15		2,052		0.14
Horn River	483			0.03		241		0.04
Total Canada	2,489			0.08		2,293		0.11
Total ad valorem taxes	12,035			0.14		16,484		0.16
Total	$	15,462		$	0.19	$	20,833	$	0.20

47

Depletion, Depreciation and Accretion

	For the Nine Months Ended September 30,
	2013				2012
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Depletion
U.S.	$	27,580	$	0.51	$	98,593	$	1.25
Canada	3,350		0.11		20,905		0.97
Total depletion	30,930		0.37		119,498		1.19
Depreciation of other fixed assets
U.S.	$	5,833	0.11		$	6,825	0.09
Canada	7,231		0.24		7,113		0.33
Total depreciation	13,064		0.16		13,938		0.14
Accretion	3,917		0.05		3,033		0.03
Total	$	47,911	$	0.58	$	136,469	$	1.36

U.S. depletion for the 2013 period, when compared to the 2012 period, reflects a decrease in production and a decrease in the current year depletion rate due to impairments recognized in 2012. Canadian depletion decreased for the 2013 period, when compared to the 2012 period, due to a decrease in the current year depletion rate as a result of impairment recognized in 2012 partially offset by an increase in production.

Impairment Expense

We perform quarterly ceiling tests to assess impairment of our oil and gas properties. We also assess our fixed assets reported outside the full-cost pool when circumstances indicate impairment may have occurred. The calculation of impairment expense is more fully described in Note 4 to the condensed consolidated interim financial statements in Item 1 of this Quarterly Report.

In the 2012 period, we recognized $1.7 billion and $363.2 million in non-cash charges for impairment of our U.S. and Canadian oil and gas properties, respectively, and $4.9 million for impairment of other property and equipment. No impairment was recognized in the 2013 period.

General and Administrative

	For the Nine Months Ended September 30,
	2013				2012
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Expense	$	26,280	$	0.31	$	32,727	$	0.33
Audit and accounting fees	1,918		0.02		5,389		0.05
Strategic transaction costs	2,693		0.03		998		0.01
Equity compensation	12,618		0.15		15,721		0.16
Total	$	43,509	$	0.51	$	54,835	$	0.55

The decrease in general and administrative expense is primarily due to reduced headcount during the 2013 period, which also decreased equity compensation, and reduced employee incentive compensation during the third quarter.

48

Tokyo Gas Transaction Gain

In April 2013, we recognized a $341.1 million gain upon closing of the Tokyo Gas Transaction. 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.

Crestwood Earn-Out

In February 2012, we collected $41 million of earn-out payments from Crestwood, which is presented as Crestwood earn-out in the condensed consolidated statement of income for the nine months ended September 30, 2013.

Other Income (Expense)

In June 2013, we recognized an expense of $12.8 million in connection with the termination of the PEA with NGTL. Further information regarding the transaction can be found in Note 8 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report. In the 2013 period the Canadian foreign currency exchange rate change resulted in a loss of $2.3 million.

Fortune Creek Accretion

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

Interest Expense

	For the Nine Months Ended September 30,
	2013			2012
	(In thousands)
Interest costs on debt outstanding	$	125,589		$	128,592
Add:
Fees paid on letters of credit outstanding	174			74
Net expense paid on debt refinancing	67,010			—
Non-cash interest (1)	23,643			8,060
Total interest costs incurred	216,416			136,726
Less:
Interest capitalized	(5,881		)	(14,378		)
Interest expense	$	210,535		$	122,348

⁽¹⁾  Represents amortization of deferred financing costs and original issue discount net of interest swap settlement amortization, including portions related to the early redemption of our Senior Notes due 2015 and Senior Notes due 2016 of $18.9 million.

Interest costs incurred for the 2013 period were higher when compared to the 2012 period primarily because of the refinancing of our debt securities in June 2013, which is more fully discussed in Note 5 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report.

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Income Taxes

The effective tax rates for the nine months ended September 30, 2013 and 2012 are as follows:

	For the Nine Months Ended September 30,
	2013			2012
	(in thousands)
Income tax (benefit) expense - U.S.	$	15,921		$	(227,581	)
Effective tax rate - U.S.	7.3		%	13.2		%
Income tax (benefit) expense - Canada	$	2,142		$	(102,994	)
Effective tax rate - Canada	(28.6		)%	25.2		%
Income tax (benefit) expense - total	$	18,063		$	(330,575	)
Effective tax rate - total	8.5		%	15.5		%

Income tax expense for the 2013 period included a reduction in the U.S. valuation allowance of $88.1 million and an increase in the Canadian valuation allowance of $3.1 million. During the latter half of 2012, we determined a reduced likelihood of realizing deferred tax benefits primarily related to our cumulative net operating losses. Income tax recognized for the 2013 period is a result of hedge gains previously deferred in AOCI being realized during the quarter and the net tax impact being recognized. The effective rate for the 2012 period reflected a projection of a full year of Canadian taxable losses and a valuation allowance in the U.S.

Quicksilver Resources Inc. and its Restricted Subsidiaries

Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 12 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, 2013. 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

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activities through cash flow from our operations, borrowings and other sources may be affected by instability in the capital markets.

For the remainder of 2013 through 2021, swaps economically hedge a portion of our natural gas and NGL revenue. The following summarizes future production hedged with commodity derivatives as of September 30, 2013.

Production	Daily Production
Year	Natural Gas	NGL
	MMcfd	MBbld
Remainder of 2013	200	6
2014 (1)	170	4
2015	150	—
2016-2021	40	—

⁽¹⁾ Our 2014 NGL derivatives end in September. Our natural gas derivatives are in place until the end of the year.

In October 2013, we entered into 40 MMcfd AECO to NYMEX natural gas basis swaps for the 2014 calendar year.

The following summarizes our cash flow activity for the 2013 period and 2012 period:

	For the Nine Months Ended September 30,
	2013			2012
	(In thousands)
Net cash provided by (used in) operating activities	$	(81,103	)	$	141,376
Net cash provided by (used in) investing activities	300,515			(392,232		)
Net cash provided by (used in) financing activities	(170,495		)	245,253

Operating Cash Flows

Net cash provided by (used in) operating activities for the 2013 period decreased from the 2012 period due to expenses related to our debt refinancing, lower realized prices (including derivative effects), lower production volumes and negative changes in working capital, including the payment to NGTL.

Net cash provided by (used in) operating activities for the 2013 period also includes hedge cash settlements of $9.8 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.

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Investing Cash Flows

Costs incurred for property, plant and equipment for the 2013 period and 2012 period were as follows:

	United States		Canada		Consolidated
	(In thousands)
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
For the Nine Months Ended September 30, 2012
Exploration and development	$	160,699	$	178,783	$	339,482
Midstream	824		12,439		13,263
Administrative	2,989		3,295		6,284
Total	$	164,512	$	194,517	$	359,029

Costs incurred reflect the activity of the 2013 capital program, while capital expenditures shown in the condensed consolidated statement of cash flows also reflect the related changes in working capital. Our 2013 capital costs incurred have decreased for the U.S. and Canada as a result of our overall decrease in capital spend in 2013 compared to 2012. Changes in working capital are driven by the reduction in accounts payable from prior year activities.

We received a $463.4 million payment from the Tokyo Gas Transaction in April 2013, a $42.3 million payment from the Synergy Transaction in August 2013 and a $41.1 million earn-out payment from Crestwood in February 2012.

A portion of the cash received from the Tokyo Gas Transaction was invested in interest bearing time deposits and commercial paper with maturities of less than one year. We intend to hold these investments until maturity.

Financing Cash Flows

Net financing cash flows in the 2013 period include net payments of $135.1 million under our Combined Credit Agreements. During the quarter ended June 30, 2013, we executed a number of refinancing transactions, which are more fully described in Note 5 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report, to extend our debt maturities and reduce the weighted average interest costs. Issuance costs related to these transactions were $23.4 million. Proceeds from the Senior Secured Second Lien Credit Agreement and the issuance of the Senior Secured Second Lien Notes due 2019 and Senior Notes due 2021 were used to pay for validly tendered Senior Notes due 2015 and Senior Notes due 2016 and accrued interest and transaction expenses.

During the quarter ended September 30, 2013, we repurchased $2.3 million aggregate principal amount of our Senior Notes due 2015.

Distributions of Fortune Creek partnership funds of $8.1 million were paid in the 2013 period to our partner based on our partner's preferential distribution rights.

Liquidity and Borrowing Capacity

At September 30, 2013, the Combined Credit Agreements’ global borrowing base was $350 million and the global letter of credit capacity was $280 million. At September 30, 2013, there was $157.8 million available under the Combined Credit Agreements.

We amended our Combined Credit Agreements in April and June 2013 for the following:

• Permit the sale and transfer of a 25% interest in Quicksilver’s Barnett Shale assets to TGBR

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• Reduce the global borrowing base to $350 million from $850 million, including a reduction due to the Tokyo Gas Transaction

• Reduce the minimum required interest coverage ratio to the following:

Period	Interest Coverage Ratio	Period	Interest Coverage Ratio
Q3 2013	1.25	Q1 2015	1.10
Q4 2013	1.25	Q2 2015	1.15
Q1 2014	1.20	Q3 2015	1.15
Q2 2014	1.15	Q4 2015	1.20
Q3 2014	1.10	Q1 2016	1.50
Q4 2014	1.10	Q2 2016	2.00

• Permit up to $825 million of second lien debt, subject to customary intercreditor terms

• Permit redemption of junior debt with the proceeds from certain asset sales and permitted second lien debt, provided utilization under the global borrowing base after giving effect to such redemption is less than 75% and compliance with other customary conditions

• Reduce the maximum senior secured debt leverage ratio to 2.0 and exclude permitted second lien debt from the senior secured debt definition

• Increase the applicable margin by 0.75% for each type of loan and issued letters of credit

• Increase the minimum mortgage properties requirement to 87.5% from 80% of proved hydrocarbon interests evaluated in the then most recent reserve report

• Amend certain definitions which impact the financial covenant calculations.

In April 2013, we increased our outstanding letters of credit by C$13 million for the step-up of treating commitments in the Horn River Basin. In August 2013, we reduced our outstanding letters of credit by C$14 million upon a payment to NGTL related to the Komie North Project.

Our ability to remain in compliance with the financial covenants in our Combined Credit Agreements may be affected by events beyond our control. While we believe that we will be able to comply with these covenants for the next 12 months, we do not expect to exceed the required levels by a significant margin. Accordingly, even a modest decline in prices for natural gas and NGLs, our failure to achieve anticipated cost savings or the inaccuracy in any material respect of any of the other assumptions underlying our forecast could cause us to fail to comply with the covenants contained in the Combined Credit Agreements. Any future inability to comply with these covenants, unless waived or amended by the requisite lenders, could materially and adversely affect our liquidity by rendering us unable to borrow further under our credit facilities and by accelerating the maturity of our debt.

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, 2013, 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 our ability to refinance existing debt. Not meeting this ratio does not represent an event of default under our indentures. We are presently unable to predict when or if we will meet the incurrence test.

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.

We anticipate that our remaining 2013 capital program will be funded by cash flow from operations or cash on hand and supplemented by proceeds from additional asset sales, although we could also borrow under the Combined Credit Agreements. If our capital resources are insufficient to fund our 2013 capital expenditure plan,

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we will need to reduce our capital expenditures or seek other financing alternatives. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we limit or defer our 2013 capital expenditure plan, we could adversely affect the recoverability and ultimate value of our oil and gas properties.

We retained a portion of the cash received from our asset sales. Our indentures require us to reinvest or repay debt with net cash proceeds from asset sales within one year. If certain capital spending and debt repayment thresholds are not met, we could be required to make an offer to repay our notes, which amount could be material.

We committed to minimum gross capital expenditures related to our Fortune Creek partnership with KKR. Our remaining gross capital expenditure requirement in 2013 is $9.1 million, which we expect to achieve within our 2013 capital budget. Our gross capital expenditure commitment in 2014 is $120 million, of which $20 million can be deferred into 2015 at our election. These minimum expenditure commitments include gross capital expenditures for wells in which we have a working interest regardless of our working interest percentage. To the extent these minimum capital expenditure commitments are not met, we will incur a penalty in an amount equal to the shortfall, which will be applied against the gathering agreement requirement. Our 2014 budget has not been approved by our board of directors; however, we may not be able to fully meet the capital commitment in 2014 without a successful transaction for our Horn River Asset or an amendment governing the capital commitment.

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

Financial Position

The following impacted our balance sheet as of September 30, 2013, as compared to our balance sheet as of December 31, 2012:

• Cash, cash equivalents and marketable securities increased $181.3 million as we retained a portion of the Tokyo Gas Transaction payment in cash, cash equivalents and marketable securities.

• Our accounts receivable balance decreased $8.9 million from December 31, 2012 to September 30, 2013, primarily due to lower production volumes compared to December 31, 2012 as well as a decrease of $3.1 million related to NGL hedge settlement accruals in 2012.

• Our net property, plant and equipment balance decreased $166.1 million from December 31, 2012 to September 30, 2013. The decrease was primarily due to the Tokyo Gas Transaction, which resulted in a decrease of $130.2 million, the Synergy Transaction, which resulted in a decrease of $50.5 million, and additional decreases due to DD&A incurred of $44.0 million and $13.2 million related to U.S.-Canadian exchange rate changes. Offsetting these decreases, we incurred capital cost of $72.5 million during 2013.

• The $24.4 million decrease in accounts payable was due primarily to a reduction in accrued capital expenditures of $5.2 million from the December 31, 2012 amount and a decrease in trade payables of $18.6 million from December 31, 2012 as activity has decreased from year‑end.

• Our accrued liabilities decreased $27.7 million, primarily due to early payment of accrued interest of $46.6 million, partially offset by an increase in the ad valorem tax accrual.

• Long-term debt decreased $137.0 million primarily from net payments under the Combined Credit Agreements of $233.9 million, recognition of $11.5 million of interest rate swaps and changes to the U.S.-Canadian exchange rate resulting in a decrease of $4.5 million, partially offset by net borrowings of $98.8 million as a result of our refinancing of our debt and $14.1 million of amortized discounts, including the impact of the redemption from the refinancing of our debt.

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Contractual Obligations and Commercial Commitments

There have been no significant changes to our contractual obligations and commitments as reported in our 2012 Annual Report on Form 10-K, other than the termination of the PEA with NGTL and the office sublease as described in Note 8 to our condensed consolidated interim financial statements included in Item 1 of this Quarterly Report.

Critical Accounting Estimates

Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated 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 2012 Annual Report on Form 10-K. These critical estimates, for which no significant changes occurred during the nine months ended September 30, 2013, 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

In July 2013, in light of the Canadian Governor in Council's failure to approve NGTL's construction of the Komie North Project, NGTL terminated the Project and Expenditure Authorization (PEA), which authorized NGTL to construct the Komie North Project and the related meter station. The PEA necessitated the construction of a treatment facility and required financial guarantees to cover NGTL's costs for the Komie North Project. We recognized $12.8 million in related actual costs incurred by NGTL, which is reflected in other income (expense) in our consolidated financial statements. We paid NGTL in August 2013 after which the related letter of credit was terminated. With the termination of the PEA described above, our agreement to deliver gas to the Komie North Project has also terminated. We maintain our ability to sell gas at the Station 2 and AECO hubs, as our current production is served by existing treating facilities and pipelines.

RECENTLY ISSUED ACCOUNTING STANDARDS

Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements materially affecting our financial statements have been issued since the filing of our 2012 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.

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

55

prices. As a result of settlements of derivative contracts, our revenue from natural gas and NGL production was greater by $67.0 million and $186.8 million for the 2013 period and 2012 period, respectively, and a gain was recognized in net derivative gains of $14.1 million and $35.1 million for the 2013 period and 2012 period, respectively. An unrealized gain of $22.1 million and an unrealized loss of $56.1 million were recognized for the 2013 period and 2012 period, respectively.

The following table details our open derivative positions at September 30, 2013:

Product	Type	Segment	Remaining Contract Period	Volume	Price Per Mcf or Bbl
Gas	Swap	Canada	Oct 2013 - Dec 2013	10 MMcfd	5.00
Gas	Swap	Canada	Oct 2013 - Dec 2015	10 MMcfd	6.42
Gas	Swap	Canada	Oct 2013 - Dec 2015	10 MMcfd	6.45
Gas	Swap	Canada	Oct 2013 - Dec 2015	10 MMcfd	4.04
Gas	Swap	Canada	Oct 2013 -Dec 2021	10 MMcfd	4.625
Gas	Swap	U.S.	Oct 2013 - Dec 2013	20 MMcfd	5.00
Gas	Swap	U.S.	Oct 2013 - Dec 2013	10 MMcfd	5.00
Gas	Swap	U.S	Oct 2013 - Dec 2014	10 MMcfd	3.91
Gas	Swap	U.S	Oct 2013 - Dec 2014	10 MMcfd	3.89
Gas	Swap	U.S.	Oct 2013 - Dec 2015	5 MMcfd	6.23
Gas	Swap	U.S.	Oct 2013 - Dec 2015	5 MMcfd	6.20
Gas	Swap	U.S.	Oct 2013 - Dec 2015	20 MMcfd	6.00
Gas	Swap	U.S.	Oct 2013 - Dec 2015	10 MMcfd	6.00
Gas	Swap	U.S.	Oct 2013 - Dec 2015	5 MMcfd	5.68
Gas	Swap	U.S.	Oct 2013 - Dec 2015	7.5 MMcfd	5.48
Gas	Swap	U.S.	Oct 2013 - Dec 2015	7.5 MMcfd	5.50
Gas	Swap	U.S.	Oct 2013 - Dec 2015	5 MMcfd	4.15
Gas	Swap	U.S.	Oct 2013 - Dec 2015	5 MMcfd	4.13
Gas	Swap	U.S.	Jan 2014 - Dec 2015	5 MMcfd	4.26
Gas	Swap	U.S.	Jan 2014 - Dec 2015	5 MMcfd	4.25
Gas	Swap	U.S.	Oct 2013 - Dec 2021	10 MMcfd	4.54
Gas	Swap	U.S.	Oct 2013 - Dec 2021	5 MMcfd	4.38
Gas	Swap	U.S.	Oct 2013 - Dec 2021	10 MMcfd	4.37
Gas	Swap	U.S.	Oct 2013 - Dec 2021	5 MMcfd	4.35
NGL	Swap	U.S.	Oct 2013 - Dec 2013	1 MBbld	31.55
NGL	Swap	U.S.	Oct 2013 - Dec 2013	1 MBbld	31.67
NGL	Swap	U.S.	Oct 2013 - Sept 2014	1 MBbld	30.43
NGL	Swap	U.S.	Oct 2013 - Sept 2014	2 MBbld	30.55
NGL	Swap	U.S.	Oct 2013 - Sept 2014	1 MBbld	30.55

These open derivative positions had a net fair value of $158.2 million as of September 30, 2013.

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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In October 2013, we added the following AECO to NYMEX basis swaps:

Product	Type	Segment	Remaining Contract Period	Volume	Price Per Mcf
Gas Basis	Swap	Canada	Jan 2014 - Dec 2014	5 MMcfd	0.475
Gas Basis	Swap	Canada	Jan 2014 - Dec 2014	5 MMcfd	0.475
Gas Basis	Swap	Canada	Jan 2014 - Dec 2014	10 MMcfd	0.475
Gas Basis	Swap	Canada	Jan 2014 - Dec 2014	10 MMcfd	0.47
Gas Basis	Swap	Canada	Jan 2014 - Dec 2014	10 MMcfd	0.45

Interest Rate Risk

Changes in interest rates affect the interest rate we pay on borrowings under the Combined Credit Agreements, Senior Secured Second Lien Credit Agreement and Senior Secured 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 2013 period and the 2012 period, we recognized $11.5 million and $3.8 million, respectively, of those deferred gains as a reduction of interest expense. In June 2013, we repurchased substantially all our senior notes due 2015 resulting in early recognition of the associated deferred gain.

Should we be required to borrow under our Combined Credit Agreements and based on interest rates as of September 30, 2013, 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 2013 at interest rates as of September 30, 2013, we estimate that annual interest payments would increase by $6.3 million. If interest rates change by 1% on our September 30, 2013 variable debt balances of $149.7 million, our annual pre-tax income would decrease or increase by $1.5 million.

Our Senior Secured Second Lien Credit Agreement and Senior Secured 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, 2013, 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, 2013.

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 2013 period and the 2012 period resulted in a loss of $2.3 million and a gain of less than $0.1 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

57

Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2013, our disclosure controls and procedures were not effective, due to the outstanding remediation of the income tax material weakness identified at December 31, 2012, 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 2012 Annual Report on Form 10-K, two material weaknesses were identified related to the design and operating effectiveness of our controls. Our controls failed to detect that, for contracts designated as hedges that had a fair value on the date of designation, there were undocumented potential sources of ineffectiveness. Specifically, our documentation in 2012 did not include an assessment of whether interest rate changes could cause the instruments to not be effective over the life of the derivative, which was required due to the presence of fair value on the designation date. Effective December 31, 2012, we no longer account for our derivatives as hedges and have clarified our policies regarding application of hedge accounting if we apply this election in the future and have therefore remediated this material weakness.

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 this 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, 2013, 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 December 2012, Vantage Fort Worth Energy LLC (“Plaintiff”) served a lawsuit against us and others in the 352nd Judicial District Court of Texas in Tarrant County asserting claims for trespass to try title, suit to quiet title, trespass and conversion in connection with 16 wells located on a 158.75 acre tract located in Tarrant County, Texas. They seek declaratory and injunctive relief, an accounting and an unspecified amount of actual damages, interest and court costs. We filed our answer in January 2013. In January 2013, Vantage filed its Motion for Non-suit with respect to certain defendants and First Amended Petition. Vantage's current complaint also seeks an unspecified amount of actual damages, interests and costs.

On May 8, 2013, all parties to the suit entered into a settlement agreement, effective April 1, 2013, whereby we assigned to Plaintiff various property and equipment and Plaintiff agreed to non-suit all of the Defendants in the matter. The court entered its Order of Dismissal with prejudice on May 13, 2013. The final resolution of this matter did not have a material effect on our financial condition, results of operations, or cash flows.

There have been no other material changes in the legal proceedings described in Part I, Item 3 included in our 2012 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 2012 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, 2013.

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 2013	181,288	$	1.67	—	—
August 2013	25,781	$	1.67	—	—
September 2013	882	$	1.67	—	—
Total	207,951	$	1.67	—	—

⁽¹⁾  Represents shares of common stock surrendered by employees to satisfy income tax withholding obligations arising upon the vesting of restricted stock issued under our stock plan.

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

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

ITEM 3. Defaults Upon Senior Securities

None.

ITEM 4. Mine Safety Disclosures

None.

ITEM 5. Other Information

None.

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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	Letter to John C. Regan dated July 15, 2013					†
10.2	Letter to Stan G. Page dated July 15, 2013					†
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 5, 2013	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	Letter to John C. Regan dated July 15, 2013					†
10.2	Letter to Stan G. Page dated July 15, 2013					†
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					‡

62