Quicksilver Resources (KWK) 10-Q 2014 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2014
or
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from  to

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)

Delaware	75-2756163
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
801 Cherry Street, Suite 3700, Unit 19, Fort Worth, Texas	76102
(Address of principal executive offices)	(Zip Code)

(817) 665-5000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  þ  No  ¨

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

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

Large accelerated filer	¨		Accelerated filer	þ
Non-accelerated filer	¨	(Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ¨  No   þ

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

Title of Class	Outstanding as of April 30, 2014
Common Stock, $0.01 par value	177,335,940 shares

DEFINITIONS

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

“ABR” means alternate base rate

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

“AOCI” means accumulated other comprehensive income

“Bbl” or “Bbls” means barrel or barrels

“Bbld” means barrel or barrels per day

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

“C$” means Canadian dollars

“DD&A” means depletion, depreciation and accretion

“GPT” means gathering, processing and transportation expense

“LIBOR” means London Interbank Offered Rate

“MBbl” or “MBbls” means thousand barrels

“MBbld” means thousands barrels per day

“MMBtu” means million BTUs

“Mcf” means thousand cubic feet

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

“MMcf” means million cubic feet

“MMcfd” means million cubic feet per day

“MMcfe” means MMcf of natural gas equivalent

“MMcfed” means MMcfe per day

“NGL” or “NGLs” means natural gas liquids

“NYMEX” means New York Mercantile Exchange

“OCI” means other comprehensive income

“Oil” includes crude oil and condensate

“RSU” means restricted stock unit

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

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

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

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

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

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

“Fortune Creek” means Fortune Creek Gathering and Processing Partnership, a midstream partnership formed with KKR and dedicated to the construction and operation of natural gas midstream services within the Horn River basin of northeast British Columbia

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

“Horn River Asset” means our operations and our assets in the Horn River basin of northeast British Columbia

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

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

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

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

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

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

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

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

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

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

“Synergy” means Synergy Offshore LLC

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

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

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

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

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INDEX TO QUARTERLY REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2014

PART I. FINANCIAL INFORMATION	6
Item 1. Condensed Consolidated Interim Financial Statements (Unaudited)	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3. Quantitative and Qualitative Disclosures About Market Risk	37
Item 4. Controls and Procedures	39
PART II. OTHER INFORMATION	41
Item 1. Legal Proceedings	41
Item 1A. Risk Factors	41
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 3. Defaults Upon Senior Securities	41
Item 4. Mine Safety Disclosures	41
Item 5. Other Information	41
Item 6. Exhibits	42
Signature	43

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

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Forward-Looking Information

Certain statements contained in this Quarterly Report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “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;

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

• fluctuations in natural gas, NGL and oil prices;

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

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

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

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

• effects of hedging natural gas 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, particularly in contracting for a transaction involving our Horn River Asset;

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

• the effects of existing or future litigation; and

• additional factors described elsewhere in this Quarterly Report.

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

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

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PART I    FINANCIAL INFORMATION

ITEM 1. Condensed Consolidated Interim Financial Statements (Unaudited)

QUICKSILVER RESOURCES INC.

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

In thousands, except for per share data – Unaudited

	For the Three Months Ended March 31,
	2014			2013
Revenue
Production	$	115,676		$	132,614
Sales of purchased natural gas	17,222			16,558
Net derivative losses	(42,033		)	(31,369		)
Other	921			900
Total revenue	91,786			118,703
Operating expense
Lease operating	18,757			24,895
Gathering, processing and transportation	32,783			39,824
Production and ad valorem taxes	4,184			5,484
Costs of purchased natural gas	17,192			16,518
Depletion, depreciation and accretion	13,955			18,256
General and administrative	15,320			16,163
Other operating	649			1,437
Total expense	102,840			122,577
Operating loss	(11,054		)	(3,874		)
Other income (expense) - net	69			(150		)
Fortune Creek accretion	(4,401		)	(4,845		)
Interest expense	(40,796		)	(43,942		)
Loss before income taxes	(56,182		)	(52,811		)
Income tax expense	(2,651		)	(6,896		)
Net loss	$	(58,833	)	$	(59,707	)
Reclassification adjustments related to settlements of derivative contracts into production revenue- net of income tax	(7,850		)	(14,755		)
Foreign currency translation adjustment	(4,255		)	301
Other comprehensive loss	(12,105		)	(14,454		)
Comprehensive loss	$	(70,938	)	$	(74,161	)
Earnings (loss) per common share - basic	$	(0.34	)	$	(0.35	)
Earnings (loss) per common share - diluted	$	(0.34	)	$	(0.35	)

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

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data – Unaudited

	March 31, 2014			December 31, 2013
ASSETS
Current assets
Cash and cash equivalents	$	69,254		$	89,103
Marketable securities	97,441			166,343
Total cash, cash equivalents and marketable securities	166,695			255,446
Accounts receivable - net of allowance for doubtful accounts	63,426			58,645
Derivative assets at fair value	43,379			57,523
Other current assets	20,746			22,346
Total current assets	294,246			393,960
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $217,481 and $221,605, respectively)	662,393			640,443
Other property and equipment	212,725			220,362
Property, plant and equipment - net	875,118			860,805
Derivative assets at fair value	50,880			73,357
Other assets	39,583			41,604
	$	1,259,827		$	1,369,726
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	20,782		$	28,822
Accrued liabilities	97,506			102,850
Derivative liabilities at fair value	9,540			3,125
Total current liabilities	127,828			134,797
Long-term debt	1,986,378			1,988,946
Partnership liability	96,328			126,132
Asset retirement obligations	105,235			106,256
Derivative liabilities at fair value	181			323
Other liabilities	19,242			19,242
Commitments and contingencies (Note 7)
Stockholders' equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding	—			—
Common stock, $0.01 par value, 400,000,000 shares authorized, and 184,761,865 and 183,994,879 shares issued, respectively	1,848			1,840
Paid in capital in excess of par value	773,898			770,092
Treasury stock of 7,404,835 and 6,698,640 shares, respectively	(53,693		)	(51,422		)
Accumulated other comprehensive income	97,776			109,881
Retained deficit	(1,895,194		)	(1,836,361		)
Total stockholders' equity	(1,075,365		)	(1,005,970		)
	$	1,259,827		$	1,369,726

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

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

In thousands – Unaudited

	Quicksilver Resources Inc. Stockholders’ Equity
	Common Stock		Additional Paid-in Capital		Treasury Stock			Accumulated Other Comprehensive Income			Retained Earnings (Deficit)			Total
Balances at December 31, 2012	$	1,790	$	751,394	$	(49,495	)	$	161,493		$	(1,997,979	)	$	(1,132,797	)
Net loss	—		—		—			—			(59,707		)	(59,707		)
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $6,944	—		—		—			(14,755		)	—			(14,755		)
Foreign currency translation adjustment	—		—		—			301			—			301
Issuance and vesting of stock compensation	39		4,994		(1,007		)	—			—			4,026
Balances at March 31, 2013	$	1,829	$	756,388	$	(50,502	)	$	147,039		$	(2,057,686	)	$	(1,202,932	)
Balances at December 31, 2013	$	1,840	$	770,092	$	(51,422	)	$	109,881		$	(1,836,361	)	$	(1,005,970	)
Net loss	—		—		—			—			(58,833		)	(58,833		)
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $2,426	—		—		—			(7,850		)	—			(7,850		)
Foreign currency translation adjustment	—		—		—			(4,255		)	—			(4,255		)
Issuance and vesting of stock compensation	8		3,806		(2,271		)	—			—			1,543
Balances at March 31, 2014	$	1,848	$	773,898	$	(53,693	)	$	97,776		$	(1,895,194	)	$	(1,075,365	)

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 Three Months Ended March 31,
	2014			2013
Operating activities:
Net loss	$	(58,833	)	$	(59,707	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and accretion	13,955			18,256
Deferred income tax expense	2,426			6,596
Non-cash loss from hedging and derivative activities	32,555			43,920
Stock-based compensation	3,814			5,033
Non-cash interest expense	2,665			1,858
Fortune Creek accretion	4,401			4,845
Other	(407		)	925
Changes in assets and liabilities
Accounts receivable	(13,220		)	6,730
Prepaid expenses and other assets	518			(190		)
Accounts payable	(10,805		)	(17,299		)
Income taxes	8,221			354
Accrued and other liabilities	(5,274		)	(25,715		)
Net cash used in operating activities	(19,984		)	(14,394		)
Investing activities:
Capital expenditures	(38,729		)	(27,442		)
Proceeds from sale of properties and equipment	1,026			608
Purchases of marketable securities	(55,682		)	—
Maturities and sales of marketable securities	124,694			—
Net cash provided by (used in) investing activities	31,309			(26,834		)
Financing activities:
Issuance of debt	—			54,040
Repayments of debt	—			(4,011		)
Debt issuance costs paid	(162		)	—
Distribution of Fortune Creek Partnership funds	(29,472		)	(3,198		)
Purchase of treasury stock	(2,271		)	(1,007		)
Net cash provided by (used in) financing activities	(31,905		)	45,824
Effect of exchange rate changes in cash	731			303
Net change in cash and cash equivalents	(19,849		)	4,899
Cash and cash equivalents at beginning of period	89,103			4,951
Cash and cash equivalents at end of period	$	69,254		$	9,850

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

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QUICKSILVER RESOURCES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unaudited

1. ACCOUNTING POLICIES, DISCLOSURES AND NATURE OF OPERATIONS

The accompanying condensed consolidated interim financial statements have not been audited. In management’s opinion, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to fairly present our financial position as of March 31, 2014 and our results of operations and cash flows for the periods presented. All such adjustments are of a normal recurring nature unless otherwise noted. The results for interim periods are not necessarily indicative of annual results.

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates.

Certain disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2013 Annual Report on Form 10-K.

We project that we will comply with the financial maintenance covenants associated with our Combined Credit Agreements through the end of 2014, however we do not expect to exceed the required levels by a significant margin, and we may have to reduce costs in response to commodity price changes or other factors should they arise. In addition, due to more stringent financial maintenance covenants that take effect in 2015, absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing or significant reductions to our operating costs, we may not comply with our interest coverage requirement under our Combined Credit Agreements and expect that we would need to seek additional covenant relief under the Combined Credit Agreements. We can provide no assurance that we would be successful in obtaining waivers or amendments. We are currently pursuing a transaction involving our Horn River Asset. Any transaction involving our Horn River Asset is likely to result in cash proceeds to us and a reduction in our capital expenditures and liquidity requirements, however we may be unsuccessful in completing such transaction.

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 2013 Annual Report on Form 10-K.

2. DIVESTITURES

In May 2014, we completed the sale of our Niobrara Asset to Southwestern Energy Company for cash proceeds of $93.5 million. We expect that the Southwestern Transaction will not represent a significant disposal of reserves under GAAP, therefore we will reduce the balance of U.S. oil and gas properties by the amount of these proceeds and we will not recognize a gain or a loss.

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

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

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3. DERIVATIVES, MARKETABLE SECURITIES AND FAIR VALUE MEASUREMENTS

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

	Asset Derivatives				Liability Derivatives
	March 31, 2014		December 31, 2013		March 31, 2014		December 31, 2013
	(in thousands)				(in thousands)
Level 2 derivative instruments	$	85,630	$	107,395	$	8,293	$	3,448
Level 3 derivative instruments	8,629		23,485		1,428		—
Total	$	94,259	$	130,880	$	9,721	$	3,448

The fair value of “Level 2” derivative instruments included in these disclosures was estimated using inputs quoted in active markets for the periods covered by the derivatives. The fair value of derivative instruments designated as “Level 3” was estimated using prices quoted in markets where there is insufficient market activity for consideration as “Level 2” instruments. Currently, only our natural gas derivatives with an original tenure of 10 years utilize “Level 3” inputs, primarily due to comparatively less market data available for the later portion of their term compared with our other shorter term derivatives. The fair value of both the “Level 2” and the “Level 3” assets and liabilities are determined using a discounted cash flow model using the terms of the derivative instrument, market prices for the periods covered by the derivatives, and the credit adjusted risk-free interest rates. The “Level 3” unobservable input is the market prices for natural gas for the period from 2018 to 2021, as there is not an active market for that period of time. These unobservable inputs included within the fair value calculation range from $4.01 to $5.14 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 March 31,
	2014			2013
	(In thousands)
Balance at beginning of period	$	23,485		$	(4,931	)
Total gains (losses) for the period:
Unrealized loss on derivatives	(17,883		)	(18		)
Settlements in net derivative gains (losses)	1,599			(4,088		)
Balance at end of period	$	7,201		$	(9,037	)
Total losses included in net derivative losses attributable to the change in unrealized losses related to assets still held at the reporting date	$	(15,576	)	$	(92	)

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Commodity Price Derivatives

As of March 31, 2014, we had natural gas and NGL swaps as follows:

Production Year	Daily Production Volume
	Natural Gas	NGL	Natural Gas Basis Swaps
	MMcfd	MBbld	MMcfd
Remaining 2014 (1)	170	4	40
2015	150	—	—
2016-2021	40	—	—

⁽¹⁾  Our 2014 NGL derivatives end in September. Our natural gas derivatives and AECO to NYMEX natural gas basis swaps are in place for the whole of 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 over the original term of the hedging relationship. Gains from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months will result in production revenue of $23.9 million net of income taxes.

Interest Rate Derivatives

In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges. Upon the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain as a reduction of interest expense over the lives of the respective notes. During the three months endedMarch 31, 2014 and 2013, we recognized $0.5 million and $1.3 million, respectively, of those deferred gains as a reduction of interest expense. Gains from the effective portion of these interest rate swaps expected to reduce interest expense during the following twelve months are $2.1 million.

Fair Value Disclosures

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

	Asset Derivatives				Liability Derivatives
	March 31, 2014		December 31, 2013		March 31, 2014		December 31, 2013
	(In thousands)				(In thousands)
Derivatives not designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	50,012	$	60,063	$	6,633	$	2,540
Noncurrent derivative assets	90,132		105,315		39,252		31,958
Current derivative liabilities	—		—		9,540		3,125
Noncurrent derivative liabilities	254		—		435		323
Total derivatives not designated as hedges	$	140,398	$	165,378	$	55,860	$	37,946

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

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Financial instruments not carried at fair value

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

Investments

We hold certain short-term marketable securities related to interest bearing time deposits and commercial paper. These 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. We did not sell or transfer any of our marketable securities during 2014 and do not anticipate selling or transferring these investments before their maturity date. At March 31, 2014, 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	$	3,508	$	—	$	(9	)	$	3,499
Commercial paper	93,933		15		(5		)	93,943
Marketable securities	$	97,441	$	15	$	(14	)	$	97,442

We had no marketable securities at March 31, 2013.

4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	March 31, 2014			December 31, 2013
	(In thousands)
Oil and gas properties
Subject to depletion	$	5,684,433		$	5,687,557
Unevaluated costs	217,481			221,605
Accumulated depletion	(5,239,521		)	(5,268,719		)
Net oil and gas properties	662,393			640,443
Other plant and equipment
Pipelines and processing facilities	341,874			347,093
General properties	71,331			72,125
Accumulated depreciation	(200,480		)	(198,856		)
Net other property and equipment	212,725			220,362
Property, plant and equipment, net of accumulated depletion and depreciation	$	875,118		$	860,805

13

5. LONG-TERM DEBT

Long-term debt consisted of the following:

	March 31, 2014		December 31, 2013
	(in thousands)
Combined Credit Agreements	$	207,746	$	211,200
Second Lien Term Loan, net of unamortized discount	608,221		607,572
Second Lien Notes due 2019, net of unamortized discount	194,631		194,423
Senior notes due 2015, net of unamortized discount	10,478		10,472
Senior notes due 2016, net of unamortized discount	8,056		8,044
Senior notes due 2019, net of unamortized discount	293,405		293,243
Senior notes due 2021, net of unamortized discount	309,530		309,190
Senior subordinated notes due 2016	350,000		350,000
Total debt	1,982,067		1,984,144
Unamortized deferred gain-terminated interest rate swaps	4,311		4,802
Long-term debt	$	1,986,378	$	1,988,946

Combined Credit Agreements

The Combined Credit Agreements’ global borrowing base was $350 million and the global letter of credit capacity was $280 million as of March 31, 2014. At March 31, 2014, we had $99.6 million available under the Combined Credit Agreements.

In April 2014, our redetermined global borrowing base under our Combined Credit Agreements was $325 million. Further, the Combined Credit Agreements were amended changing the definition of EBITDAX. Additionally, we permanently reduced the aggregate maximum credit amounts under the Combined Credit Agreements from $1.75 billion to $650 million.

Senior Notes due 2015 and Senior Notes due 2016

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

Indenture Restrictions

We have an incurrence test under our indentures applicable to debt, restricted payments, mergers and consolidations and designation of unrestricted subsidiaries that requires EBITDA to exceed interest expense by 2.25 times. At March 31, 2014, we did not meet this test and, as a result, we are limited in our ability to, among other things, incur additional debt, except for specific baskets. We do retain, however, the ability to utilize the full borrowing capacity under our Combined Credit Agreements and to refinance existing debt. Not meeting this ratio does not represent an event of default under our debt. We cannot predict when or if we will meet the incurrence test.

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

14

Summary of All Outstanding Debt

The following table summarizes certain significant aspects of our long-term debt outstanding at March 31, 2014.

	Priority on Collateral and Structural Seniority (1)
	Highest priority								Lowest priority
	First Lien		Second Lien		Senior Unsecured				Senior Subordinated
	Combined Credit Agreements		Second Lien Term Loan	Second Lien Notes due 2019	2015 Senior Notes	2016 Senior Notes	2019 Senior Notes	2021 Senior Notes	Senior Subordinated Notes
Principal amount (1) (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 March 31, 2014 (4)	3.99%		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) (9)	- Minimum current ratio of 1.0 - Minimum EBITDA to cash interest expense ratio of 1.10 - Maximum senior secured debt leverage ratio of 2.0		N/A	N/A	N/A	N/A	N/A	N/A	N/A
Significant restrictive covenants (8)(9)	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions - Limitations on derivatives and investments		- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- 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 (9)	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 (9)	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 (9)	Event of default		Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest
Equity clawback (9)	N/A		N/A	N/A	N/A	N/A	N/A	Redeemable until July 1, 2016 at 111.00%, plus accrued interest for up to 35%	N/A
Estimated fair value (10)	$207.7 million		$610.2 million	$195.3 million	$10.7 million	$8.6 million	$294.3 million	$346.5 million	$337.5 million

15

⁽¹⁾  Borrowings under the Amended and Restated U.S. Credit Facility, Second Lien Term Loan and Second Lien Notes due 2019 are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured (on a first priority basis with respect to the Amended and Restated U.S. Credit Facility and on a second priority basis with respect to the Second Lien Term Loan and the Second Lien Notes due 2019) by 100% of the equity interests of each of Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Barnett Shale Operating LLC, Silver Stream Pipeline Company LLC, QPP Parent LLC and QPP Holdings LLC (collectively, the “Domestic Pledged Equity”), 65% of the equity interests of Quicksilver Resources Canada Inc. (“Quicksilver Canada”) and Quicksilver Production Partners Operating Ltd. (with respect to the Amended and Restated U.S. Credit Facility, on a ratable basis with borrowings under the Amended and Restated Canadian Credit Facility) and the majority of Quicksilver's domestic proved oil and gas properties and related assets, (the “Domestic Pledged Property”). Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by the Domestic Pledged Equity, the Domestic Pledged Property, 100% of the equity interests of Quicksilver Canada (65% of which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and any Canadian restricted subsidiaries, under the Amended and Restated Canadian Credit Facility, and 65% of the equity interests of Quicksilver Production Partners Operating Ltd. (which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and the majority of Quicksilver Canada's oil and gas properties and related assets. The other debt presented is based upon structural seniority and priority of payment.

⁽²⁾  The principal amount for the Combined Credit Agreements represents the global borrowing base as of March 31, 2014.

⁽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 Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Second Lien Term Loan and Second Lien Notes due 2019 are required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remain outstanding and (2) 91 days prior to the maturity of the 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%.

16

⁽⁷⁾  The future minimum required interest coverage ratio for the Combined Credit Agreement is as follows:

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

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

⁽⁹⁾  The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions and related definitions contained in the documents governing the various components of our debt.

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

6. INCOME TAXES

Note 13 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains additional information about our income taxes. At March 31, 2014, our U.S. and Canadian valuation allowances are $370.4 million and $62.8 million, respectively, which reduce our net deferred tax assets to a zero value as we continue to believe that it is not more likely than not that we will realize the deferred tax assets primarily related to our cumulative net operating losses. Income tax recognized for the three months ended March 31, 2014 is a result of hedge gains previously deferred in AOCI being realized during the periods and the net tax impact being recognized.

7. COMMITMENTS AND CONTINGENCIES

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 2013 Annual Report on Form 10-K contains a more complete description of our contractual obligations, commitments and contingencies for which there are no other significant updates during the quarter ended March 31, 2014.

8. FORTUNE CREEK

Note 15 to the consolidated financial statements in our 2013 Annual Report on Form 10-K contains additional information on Fortune Creek. In March 2014, we agreed with KKR to an amendment to extend the ending date of the minimum gross capital expenditures requirement to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset and to broaden allowable spending to include acquisitions of producing properties that utilize partnership assets. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by C$0.13 per Mcf until at least 2016.

17

We committed gas production from our Horn River Asset for ten years beginning 2012, as more fully described below. KKR contributed C$125 million cash in exchange for a 50% interest in Fortune Creek. Our Canadian subsidiary has responsibility for the day-to-day operations of Fortune Creek.

The firm gathering agreement with Fortune Creek is guaranteed by us. If our subsidiary does not meet its obligations under the gathering agreement, KKR has the right to liquidate the partnership and consequently we have recorded the funds contributed by KKR as a liability in our consolidated financial statements. We recognize accretion expense to reflect the rate of return earned by KKR via its investment. Fortune Creek has made cash distributions to KKR, which are reported as cash used in financing activities.

9. QUICKSILVER STOCKHOLDERS’ EQUITY

Common Stock, Preferred Stock and Treasury Stock

We are authorized to issue 400 million shares of common stock with a $0.01 par value per share and 10 million shares of preferred stock with a $0.01 par value per share. At March 31, 2014 and December 31, 2013, we had 177.4 million and 177.3 million shares of common stock outstanding, respectively.

Stock Options

No options have been granted during 2014. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the three months ended March 31, 2013:

Weighted avg grant date fair value	$1.81
Weighted avg risk-free interest rate	0.76%
Expected life	5.3 years
Wtd avg volatility	75.0%
Expected dividends	—

The following table summarizes our stock option activity for the three months endedMarch 31, 2014:

	Shares		Wtd Avg Exercise Price		Wtd Avg Remaining Contractual Life	Aggregate Intrinsic Value
					(In years)	(In thousands)
Outstanding at January 1, 2014	6,771,578		$	7.82
Expired	(20,719	)	9.85
Outstanding at March 31, 2014	6,750,859		$	7.81	5.9	$	1,409
Exercisable at March 31, 2014	5,323,678		$	9.19	5.1	$	282

As of March 31, 2014, we estimate that a total of 6.3 million stock options will vest including those options already exercisable. As of March 31, 2014, the unrecognized compensation cost related to outstanding unvested stock options was $1.6 million, which is expected to be recognized in expense through August 2016. Compensation expense related to stock options of $0.5 million and $1.0 million was recognized for the three months endedMarch 31, 2014 and 2013, respectively.

18

Restricted Stock and Stock Units

The following table summarizes our restricted stock and stock unit activity for the three months endedMarch 31, 2014:

	Payable in shares				Payable in cash
	Shares		Wtd Avg Grant Date Fair Value		Shares		Wtd Avg Grant Date Fair Value
Outstanding at January 1, 2014	5,668,090		$	3.90	1,572,341		$	3.69
Granted	662,170		3.01		—		—
Vested	(2,401,580	)	4.93		(498,535	)	4.66
Forfeited	(80,209	)	3.77		(16,893	)	3.49
Outstanding at March 31, 2014	3,848,471		$	3.11	1,056,913		$	3.26

As of March 31, 2014, the unrecognized compensation cost related to outstanding unvested restricted stock was $11.0 million, which is expected to be recognized in expense through March 2017. Grants of restricted stock and RSUs during the three months endedMarch 31, 2014 had an estimated grant date fair value of $2.0 million. The fair value of outstanding RSUs to be settled in cash was $2.8 million at March 31, 2014. For the three months endedMarch 31, 2014 and 2013, compensation expense related to restricted stock and RSUs of $3.7 million and $4.5 million, respectively, was recognized. The total fair value of shares vested during the three months endedMarch 31, 2014 was $9.4 million.

10.EARNINGS PER SHARE

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

	For the Three Months Ended March 31,
	2014			2013
	(In thousands, except per share data)
Net loss attributable to Quicksilver	$	(58,833	)	$	(59,707	)
Basic income allocable to participating securities (1)	$	—		$	—
Loss available to shareholders	$	(58,833	)	$	(59,707	)
Weighted average common shares – basic	173,497			171,826
Effect of dilutive securities (2)
Share-based compensation awards	—			—
Weighted average common shares – diluted	173,497			171,826
Earnings (loss) per common share – basic	$	(0.34	)	$	(0.35	)
Earnings (loss) per common share – diluted	$	(0.34	)	$	(0.35	)

⁽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 March 31, 2014, 6.8 million shares associated with our stock options and 0.3 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations. For the three months ended March 31, 2013, 5.0 million shares associated with our stock options and 0.9 million shares associated with our unvested RSUs were antidilutive and, therefore, excluded from the diluted share calculations.

19

11. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

The following tables present financial information about Quicksilver and our restricted subsidiaries for the three-month period covered by the condensed consolidated financial statements. Under the indentures for our senior notes and senior subordinated notes, Fortune Creek is not considered to be a subsidiary and therefore it is presented separately from the other subsidiaries for these purposes.

Condensed Consolidating Balance Sheets

	March 31, 2014
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non- Guarantor Subsidiaries			Restricted Subsidiary Eliminations			Quicksilver and Restricted Subsidiaries			Unrestricted Non- Guarantor Subsidiaries			Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
ASSETS
Current assets	$	256,321		$	11,510		$	53,154		$	(27,979	)	$	293,006		$	46		$	1,218	$	(24	)	$	294,246
Property and equipment	480,136			15,160			302,224			—			797,520			—			77,598		—			875,118
Investment in subsidiaries (equity method)	(231,131		)	—			(1,345		)	231,131			(1,345		)	(1,345		)	—		2,690			—
Other assets	479,128			—			24,617			(413,282		)	90,463			—			—		—			90,463
Total assets	$	984,454		$	26,670		$	378,650		$	(210,130	)	$	1,179,644		$	(1,299	)	$	78,816	$	2,666		$	1,259,827
LIABILITIES AND EQUITY
Current liabilities	$	116,207		$	12,577		$	25,244		$	(27,979	)	$	126,049		$	25		$	1,778	$	(24	)	$	127,828
Long-term liabilities	1,943,612			19,242			559,958			(413,282		)	2,109,530			—			1,506		96,328			2,207,364
Stockholders' equity	(1,075,365		)	(5,149		)	(206,552		)	231,131			(1,055,935		)	(1,324		)	75,532		(93,638		)	(1,075,365		)
Total liabilities and equity	$	984,454		$	26,670		$	378,650		$	(210,130	)	$	1,179,644		$	(1,299	)	$	78,816	$	2,666		$	1,259,827

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

20

Condensed Consolidating Statements of Income

	For the Three Months Ended March 31, 2014
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non- Guarantor Subsidiaries			Restricted Subsidiary Eliminations		Quicksilver and Restricted Subsidiaries			Unrestricted Non- Guarantor Subsidiaries		Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
Revenue	$	62,910		$	374		$	28,502		$	—	$	91,786		$	—	$	4,942	$	(4,942	)	$	91,786
Operating expenses	75,401			291			30,265			—		105,957			—		1,825		(4,942		)	102,840
Equity in net earnings of subsidiaries	(5,689		)	—			(1,282		)	5,689		(1,282		)	3,119		—		(1,837		)	—
Operating income (loss)	(18,180		)	83			(3,045		)	5,689		(15,453		)	3,119		3,117		(1,837		)	(11,054		)
Fortune Creek accretion	—			—			—			—		—			—		—		(4,401		)	(4,401		)
Interest expense and other	(38,011		)	—			(2,718		)	—		(40,729		)	—		2		—			(40,727		)
Income tax (expense) benefit	(2,642		)	(29		)	20			—		(2,651		)	—		—		—			(2,651		)
Net income (loss)	$	(58,833	)	$	54		$	(5,743	)	$	5,689	$	(58,833	)	$	3,119	$	3,119	$	(6,238	)	$	(58,833	)
Other comprehensive income (loss)	(8,798		)	—			(3,307		)	—		(12,105		)	—		—		—			(12,105		)
Equity in OCI of subsidiaries	(3,307		)	—			—			3,307		—			—		—		—			—
Comprehensive income (loss)	$	(70,938	)	$	54		$	(9,050	)	$	8,996	$	(70,938	)	$	3,119	$	3,119	$	(6,238	)	$	(70,938	)

	For the Three Months Ended March 31, 2013
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries		Restricted Non- Guarantor Subsidiaries			Restricted Subsidiary Eliminations		Quicksilver and Restricted Subsidiaries			Unrestricted Non- Guarantor Subsidiaries		Fortune Creek		Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
Revenue	$	88,900		$	214	$	29,589		$	—	$	118,703		$	—	$	5,325	$	(5,325	)	$	118,703
Operating expenses	97,024			30		28,459			—		125,513			—		2,389		(5,325		)	122,577
Equity in net earnings of subsidiaries	(4,191		)	—		(1,908		)	4,191		(1,908		)	2,937		—		(1,029		)	—
Operating income (loss)	(12,315		)	184		(778		)	4,191		(8,718		)	2,937		2,936		(1,029		)	(3,874		)
Fortune Creek accretion	—			—		—			—		—			—		—		(4,845		)	(4,845		)
Interest expense and other	(41,168		)	—		(2,925		)	—		(44,093		)	—		1		—			(44,092		)
Income tax (expense) benefit	(6,224		)	—		(672		)	—		(6,896		)	—		—		—			(6,896		)
Net income (loss)	$	(59,707	)	$	184	$	(4,375	)	$	4,191	$	(59,707	)	$	2,937	$	2,937	$	(5,874	)	$	(59,707	)
Other comprehensive income (loss)	(11,003		)	—		(3,451		)	—		(14,454		)	—		—		—			(14,454		)
Equity in OCI of subsidiaries	(3,451		)	—		—			3,451		—			—		—		—			—
Comprehensive income (loss)	$	(74,161	)	$	184	$	(7,826	)	$	7,642	$	(74,161	)	$	2,937	$	2,937	$	(5,874	)	$	(74,161	)

21

Condensed Consolidating Statements of Cash Flows

	For the Three Months Ended March 31, 2014
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Restricted Subsidiary Eliminations			Quicksilver and Restricted Subsidiaries			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek			Consolidated Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
Net cash flow provided by (used in) operating activities	$	(29,198	)	$	14		$	9,075		$	—		$	(20,109	)	$	—		$	125		$	—		$	(19,984	)
Purchases of property, plant and equipment	(28,772		)	(14		)	(9,934		)	—			(38,720		)	—			(9		)	—			(38,729		)
Investment in subsidiary	(7,385		)	—			(26,395		)	7,385			(26,395		)	(26,395		)	—			52,790			—
Proceeds from sale of properties and equipment	910			—			116			—			1,026			—			—			—			1,026
Purchases of marketable securities	(55,682		)	—			—			—			(55,682		)	—			—			—			(55,682		)
Maturities and sales of marketable securities	124,694			—			—			—			124,694			—			—			—			124,694
Net cash flow provided by (used in) investing activities	33,765			(14		)	(36,213		)	7,385			4,923			(26,395		)	(9		)	52,790			31,309
Debt issuance costs paid	(162		)	—			—			—			(162		)	—			—			—			(162		)
Intercompany note	(22,559		)	—			22,559			—			—			—			—			—			—
Intercompany financing	—			—			7,385			(7,385		)	—			—			—			—			—
Contribution received	—			—			—			—			—			26,395			26,395			(52,790		)	—
Distribution of Fortune Creek Partnership funds	—			—			—			—			—			—			(29,472		)	—			(29,472		)
Purchase of treasury stock	(2,271		)	—			—			—			(2,271		)	—			—			—			(2,271		)
Net cash flow provided by (used in) financing activities	(24,992		)	—			29,944			(7,385		)	(2,433		)	26,395			(3,077		)	(52,790		)	(31,905		)
Effect of exchange rates on cash	—			—			(2,357		)	—			(2,357		)	(1		)	3,089			—			731
Net increase (decrease) in cash and equivalents	(20,425		)	—			449			—			(19,976		)	(1		)	128			—			(19,849		)
Cash and equivalents at beginning of period	83,893			—			4,135			—			88,028			22			1,053			—			89,103
Cash and equivalents at end of period	$	63,468		$	—		$	4,584		$	—		$	68,052		$	21		$	1,181		$	—		$	69,254

	For the Three Months Ended March 31, 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	$	(27,331	)	$	4		$	10,648		$	(16,679	)	$	—	$	2,285		$	(14,394	)
Purchases of property, plant and equipment	(18,824		)	(4		)	(8,110		)	(26,938		)	—		(504		)	(27,442		)
Proceeds from sale of properties and equipment	591			—			17			608			—		—			608
Net cash flow used in investing activities	(18,233		)	(4		)	(8,093		)	(26,330		)	—		(504		)	(26,834		)
Issuance of debt	51,000			—			3,040			54,040			—		—			54,040
Repayments of debt	—			—			(4,011		)	(4,011		)	—		—			(4,011		)
Distribution of Fortune Creek Partnership funds	—			—			—			—			—		(3,198		)	(3,198		)
Purchase of treasury stock	(1,007		)	—			—			(1,007		)	—		—			(1,007		)
Net cash flow provided by (used in) financing activities	49,993			—			(971		)	49,022			—		(3,198		)	45,824
Effect of exchange rates on cash	—			—			(1,584		)	(1,584		)	—		1,887			303
Net increase (decrease) in cash and equivalents	4,429			—			—			4,429			—		470			4,899
Cash and equivalents at beginning of period	4,618			—			—			4,618			—		333			4,951
Cash and equivalents at end of period	$	9,047		$	—		$	—		$	9,047		$	—	$	803		$	9,850

22

12. SEGMENT INFORMATION

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

	Exploration & Production													Quicksilver Consolidated
	U.S.		Canada			Midstream		Corporate			Elimination
For the Three Months Ended March 31:	(In thousands)
2014
Revenue	$	62,903	$	27,962		$	5,863	$	—		$	(4,942	)	$	91,786
DD&A	7,379		4,827			1,243		506			—			13,955
Operating income (loss)	2,181		(611		)	3,201		(15,825		)	—			(11,054		)
Property and equipment costs incurred	33,216		8,954			11		91			—			42,272
2013
Revenue	$	81,553	$	36,260		$	6,215	$	—		$	(5,325	)	$	118,703
DD&A	13,128		3,190			1,340		598			—			18,256
Operating income (loss)	6,922		2,841			3,124		(16,761		)	—			(3,874		)
Property and equipment costs incurred	20,553		3,064			80		640			—			24,337
Property, plant and equipment-net
March 31, 2014	$	476,579	$	300,837		$	92,758	$	4,944		$	—		$	875,118
December 31, 2013	451,840		306,423			97,118		5,424			—			860,805
Total assets
March 31, 2014	770,747		378,650			105,486		4,944			—			$	1,259,827
December 31, 2013	895,388		359,951			108,963		5,424			—			1,369,726

13. SUPPLEMENTAL CASH FLOW INFORMATION

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

	For the Three Months Ended March 31,
	2014			2013
	(In thousands)
Interest, net of capitalized interest	$	49,103		$	69,633
Income taxes	(7,951		)	35

Other significant non-cash transactions are as follows:

	For the Three Months Ended March 31,
	2014		2013
	(In thousands)
Working capital related to capital expenditures	$	13,128	$	8,964

23

14. TRANSACTIONS AND OTHER MATTERS WITH RELATED PARTIES

As of March 31, 2014, members of the Darden family and entities controlled by them beneficially owned approximately 30% of our outstanding common stock. Glenn Darden and Anne Darden Self are officers and directors, and Thomas Darden is a director, of Quicksilver.

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

Payments received from Mercury, a company owned by members of the Darden family, for sublease rentals, employee insurance coverage and administrative services were less than $0.1 million for the first three months of 2014 and 2013.

Thomas Darden retired as an employee on December 31, 2013. During the first three months of 2014, consulting fee payments of $135,000, office allowance payments of $37,500 and COBRA payments of $39,000 were made to Mr. Darden. Additionally, in accordance with the agreement related to such retirement signed in May 2013 and following the execution and non-revocation of a release agreement satisfactory to us, we paid Mr. Darden a cash bonus of $286,650 and an equity bonus in the form of 72,662 fully vested shares having a grant date fair value equal to $191,100 in March 2014.

24

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

The following Management’s Discussion and Analysis (“MD&A”) is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Quarterly Report as well as our 2013 Annual Report on Form 10-K. We conduct our operations in two segments: (1) our more dominant exploration and production segment and (2) our significantly smaller midstream segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis.

Our MD&A includes the following sections:

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

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

• Results of Operations – an analysis of our consolidated results of operations for the three-month periods presented in our financial statements

• Liquidity, Capital Resources and Financial Position – an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments

2014 HIGHLIGHTS

Joint Venture Update

In March 2014, we executed an agreement with Southwestern Energy Company to sell all of our Niobrara Asset for cash proceeds of $93.5 million. The transaction closed on May 1, 2014. The decision to sell this acreage was largely rooted in SWEPI’s plans to exit its North American shale plays, including the shared interest in our Niobrara Asset.

Recognizing the need to enter into a partnership to develop our Horn River Asset, with the assistance of our advisors, we began the process to identify one or more potential partners. We have identified potential partners and we are working toward completing a transaction with them. We believe that completing a transaction will substantially defray our need to make significant capital investments on the Horn River Asset. We cannot provide any assurance that we will be successful in consummating any such prospective transactions.

Significant Contract Revisions

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

2014 CAPITAL PROGRAM

We incurred costs related to our capital program of $42.3 million for the first three months of 2014. We continue to anticipate full-year 2014 spending to be $136 million.

25

RESULTS OF OPERATIONS

Three Months EndedMarch 31, 2014 and 2013

The following discussion compares the results of operations for the three months ended March 31, 2014 and 2013, or the 2014 period and 2013 period, respectively. “Other U.S.” refers to the combined amounts for our Niobrara Asset, West Texas Asset and Southern Alberta Basin Asset. The 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. Combining these items mirrors our view of the derivatives' usefulness, provides more comparability and is consistent with how management views and evaluates operating results.

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

	Natural Gas					NGL					Oil				Total
	2014			2013		2014			2013		2014		2013		2014			2013
	(In millions)
Barnett Shale	$	48.3		$	51.8	$	18.2		$	23.7	$	1.4	$	2.3	$	67.9		$	77.8
Other U.S.	—			0.1		—			0.1		0.5		3.1		0.5			3.3
Hedging	7.1			15.3		—			—		—		—		7.1			15.3
U.S.	55.4			67.2		18.2			23.8		1.9		5.4		75.5			96.4
Horseshoe Canyon	19.1			15.2		—			—		—		—		19.1			15.2
Horn River	18.7			17.8		—			—		—		—		18.7			17.8
Hedging	2.4			3.2		—			—		—		—		2.4			3.2
Canada	40.2			36.2		—			—		—		—		40.2			36.2
Consolidated production revenue	$	95.6		$	103.4	$	18.2		$	23.8	$	1.9	$	5.4	$	115.7		$	132.6
U.S. realized cash derivative gains (losses)	$	(7.8	)	$	5.5	$	(1.9	)	$	—	$	—	$	—	$	(9.7	)	$	5.5
Canada realized cash derivative gains (losses)	(0.7		)	4.1		—			—		—		—		(0.7		)	4.1
Consolidated realized cash derivative gains (losses)	(8.5		)	9.6		(1.9		)	—		—		—		(10.4		)	9.6
Consolidated production revenue and realized cash derivative gains (1)	$	87.1		$	113.0	$	16.3		$	23.8	$	1.9	$	5.4	$	105.3		$	142.2

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

26

Average Daily Production Volume:

	Natural Gas		NGL		Oil		Equivalent Total
	2014	2013	2014	2013	2014	2013	2014	2013
	(MMcfd)		(Bbld)		(Bbld)		(MMcfed)
Barnett Shale	112.6	175.9	6,303	9,644	165	281	151.4	235.5
Other U.S.	—	0.1	—	24	57	407	0.3	2.7
U.S.	112.6	176.0	6,303	9,668	222	688	151.7	238.2
Horseshoe Canyon	48.1	51.3	5	6	—	—	48.1	51.3
Horn River	46.1	68.0	—	—	—	—	46.1	68.0
Canada	94.2	119.3	5	6	—	—	94.2	119.3
Consolidated	206.8	295.3	6,308	9,674	222	688	245.9	357.5

Average Realized Price:

	Natural Gas					NGL					Oil				Equivalent Total
	2014			2013		2014			2013		2014		2013		2014			2013
	(per Mcf)					(per Bbl)					(per Bbl)				(per Mcfe)
Barnett Shale	$	4.76		$	3.27	$	32.16		$	27.35	$	93.75	$	90.12	$	4.99		$	3.67
Other U.S.	3.78			4.24		—			52.49		89.31		85.92		13.32			13.50
Hedging	0.70			0.96		—			—		—		—		0.52			0.71
U.S.	$	5.47		$	4.23	$	32.16		$	27.42	$	92.61	$	87.63	$	5.53		$	4.50
Horseshoe Canyon	$	4.40		$	3.29	$	52.23		$	66.68	$	—	$	—	$	4.41		$	3.29
Horn River	4.50			2.91		—			—		—		—		4.50			2.91
Hedging	0.29			0.30		—			—		—		—		0.29			0.30
Canada	$	4.74		$	3.37	$	52.23		$	66.68	$	—	$	—	$	4.74		$	3.38
Consolidated production revenue	$	5.14		$	3.89	$	32.18		$	27.44	$	92.61	$	87.63	$	5.23		$	4.12
U.S. realized cash derivative gains (losses)	$	(0.77	)	$	0.35	$	(3.29	)	$	—	$	—	$	—	$	(0.71	)	$	0.26
Canada realized cash derivative gains	(0.09		)	0.38		—			—		—		—		(0.09		)	0.38
Consolidated realized cash derivative gains (losses)	$	(0.46	)	$	0.36	$	(3.28	)	$	—	$	—	$	—	$	(0.47	)	$	0.30
Consolidated production revenue and realized cash derivative gains	$	4.68		$	4.25	$	28.90		$	27.44	$	92.61	$	87.63	$	4.76		$	4.42

27

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

	Natural Gas			NGL			Oil			Total
	(In thousands)
Consolidated production revenue and realized cash derivative gains for the 2013 period	$	112,896		$	23,891		$	5,423		$	142,210
Volume variances	(25,417		)	(8,310		)	(3,668		)	(37,395		)
Hedge revenue variances	(8,963		)	—			—			(8,963		)
Realized cash derivative variance (1)	(18,117		)	(1,865		)	—			(19,982		)
Price variances	26,632			2,688			100			29,420
Consolidated production revenue and realized cash derivative gains for the 2014 period	$	87,031		$	16,404		$	1,855		$	105,290

⁽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 increased for the 2014 period from the 2013 period due to an increase in our realized price partially offset by lower volumes primarily attributable to the Tokyo Gas Transaction and natural declines in the Barnett Shale Asset and natural declines in our Horn River Asset. Our hedge and realized cash derivative decreased for the 2014 period compared to the 2013 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 revenues derived from our derivatives. Consolidated production revenue and realized cash derivative gains from NGL revenue for the 2014 period decreased from the 2013 period due to lower volumes produced primarily attributable to the Tokyo Gas Transaction, declining well production and the 2014 period including an NGL derivative loss that the 2013 period did not, partially offset by an increase in realized prices. Our oil revenue decreased for the 2014 period from the 2013 period due to lower volumes resulting from the Synergy Transaction.

Our production revenue for the 2014 period and 2013 period was higher by $9.5 million and $18.5 million, respectively, because of our hedging activities.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas

	For the Three Months Ended March 31,
	2014		2013
	(In thousands)
Sales of purchased natural gas
Purchases from Eni	$	16,397	$	15,900
Purchases from others	825		658
Total	17,222		16,558
Costs of purchased natural gas sold
Purchases from Eni	16,375		15,896
Purchases from others	817		622
Total	17,192		16,518
Net sales and purchases of natural gas	$	30	$	40

28

Net Derivative Losses

The following table summarizes our net derivative gains and losses:

	For the Three Months Ended March 31,
	2014			2013
	(In thousands)
Unrealized mark-to-market changes in fair value of natural gas derivative gains (losses) (1)	$	(32,418	)	$	(40,965	)
Realized cash settlements of natural gas derivative gains (losses)	(8,521		)	9,596
Unrealized mark-to-market changes in fair value of NGL derivative gains (1)	771			—
Realized cash settlements of NGL derivative losses	(1,865		)	—
Derivative gains (losses), net	(42,033		)	(31,369		)

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

Other Revenue

	For the Three Months Ended March 31,
	2014		2013
	(In thousands)
Midstream revenue from third parties
Canada	$	540	$	675
Texas	381		225
Total	$	921	$	900

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Operating Expense

Lease Operating

	For the Three Months Ended March 31,
	2014				2013
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale
Expense	$	10,099	$	0.74	$	13,435	$	0.63
Equity compensation expense	135		0.01		272		0.01
	$	10,234	$	0.75	$	13,707	$	0.64
Other U.S.
Expense	$	440	$	14.12	$	1,403	$	5.72
Equity compensation expense	31		0.99		68		0.28
	$	471	$	15.11	$	1,471	$	6.00
Total U.S.
Expense	$	10,539	$	0.77	$	14,838	$	0.69
Equity compensation expense	166		0.01		340		0.02
	$	10,705	$	0.78	$	15,178	$	0.71
Horseshoe Canyon
Expense	$	6,400	$	1.48	$	8,211	$	1.78
Equity compensation expense	616		0.14		65		0.01
	$	7,016	$	1.62	$	8,276	$	1.79
Horn River
Expense	$	1,036	$	0.25	$	1,441	$	0.24
Equity compensation expense	—		—		—		—
	$	1,036	$	0.25	$	1,441	$	0.24
Total Canada
Expense	$	7,436	$	0.88	$	9,652	$	0.90
Equity compensation expense	616		0.07		65		0.01
	$	8,052	$	0.95	$	9,717	$	0.91
Total Company
Expense	$	17,975	$	0.81	$	24,490	$	0.76
Equity compensation expense	782		0.04		405		0.01
	$	18,757	$	0.85	$	24,895	$	0.77

Lease operating expense for the 2014 period in the Barnett Shale decreased in total primarily due to the Tokyo Gas Transaction. On a unit basis, the Barnett Shale increased primarily due to fixed lease operating charges being distributed over lower volume due to natural declines compared to the 2013 period. Other U.S. decreased in total for the 2014 period primarily due to the Synergy Transaction and on a unit basis the 2014 period increased as fixed lease operating charges were distributed over lower volume compared to the 2013 period. In Canada, the decrease in lease operating expense in total for the 2014 period compared to the 2013 period is primarily due to decreased headcount and lower direct lifting charges.

30

Gathering, Processing and Transportation

	For the Three Months Ended March 31,
	2014				2013
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Barnett Shale	$	21,259	$	1.56	$	30,799	$	1.45
Other U.S.	—		0.01		3		0.01
Total U.S.	21,259		1.56		30,802		1.44
Horseshoe Canyon	879		0.20		823		0.18
Horn River	10,645		2.57		8,199		1.34
Total Canada	11,524		1.36		9,022		0.84
Total	$	32,783	$	1.48	$	39,824	$	1.24

U.S. GPT on a gross basis decreased primarily due to lower volumes in our Barnett Shale Asset attributable to the Tokyo Gas Transaction. On a unit basis, the 2014 period was higher primarily due to increased rates in the 2014 period compared to the 2013 period and increased transportation charges from unused demand charges and higher NGL reservation fees. Our Horn River Asset GPT increased in total and on a unit basis for the 2014 period as compared to the 2013 period as a result of increased gathering rates as the 2013 period included discounted rates prior to the contractual increase in volumes. Our Horn River Asset GPT includes payments made for unused firm capacity of $3.1 million and $1.1 million for the 2014 period and the 2013 period, respectively.

Production and Ad Valorem Taxes

	For the Three Months Ended March 31,
	2014				2013
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Production taxes
Barnett Shale	$	955	$	0.07	$	940	$	0.04
Other U.S.	6		0.20		232		0.01
Total U.S.	961		0.07		1,172		0.05
Horseshoe Canyon	61		0.01		65		0.01
Horn River	9		—		—		—
Total Canada	70		0.01		65		0.01
Total production taxes	1,031		0.05		1,237		0.04
Ad valorem taxes
Barnett Shale	$	2,133	$	0.16	$	3,353	$	0.16
Other U.S.	90		2.90		147		0.59
Total U.S.	2,223		0.16		3,500		0.16
Horseshoe Canyon	741		0.17		698		0.15
Horn River	189		0.05		49		0.01
Total Canada	930		0.11		747		0.07
Total ad valorem taxes	3,153		0.14		4,247		0.13
Total	$	4,184	$	0.19	$	5,484	$	0.17

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Depletion, Depreciation and Accretion

	For the Three Months Ended March 31,
	2014				2013
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Depletion
U.S.	$	6,887	$	0.50	$	11,108	$	0.52
Canada	1,795		0.21		1,205		0.11
Total depletion	8,682		0.39		12,313		0.38
Depreciation of other fixed assets
U.S.	$	1,651	0.12		$	2,115	0.10
Canada	2,239		0.26		2,459		0.23
Total depreciation	3,890		0.18		4,574		0.14
Accretion	1,383		0.06		1,369		0.04
Total	$	13,955	$	0.63	$	18,256	$	0.57

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

General and Administrative

	For the Three Months Ended March 31,
	2014				2013
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe
Expense	$	8,399	$	0.38	$	10,333	$	0.32
Audit and accounting fees	1,115		0.05		1,266		0.04
Strategic transaction costs	2,775		0.12		—		—
Equity compensation	3,031		0.14		4,564		0.14
Total	$	15,320	$	0.69	$	16,163	$	0.50

The decrease in general and administrative expense is primarily due to reduced headcount during the 2014 period, which also decreased equity compensation.

Fortune Creek Accretion

KKR’s contribution is shown as Partnership liability in the condensed consolidated balance sheet, and we recognize accretion expense to reflect the rate of return earned by KKR via its investment.

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Interest Expense

	For the Three Months Ended March 31,
	2014			2013
	(In thousands)
Interest costs on debt outstanding	$	39,375		$	43,973
Add:
Fees paid on letters of credit outstanding	65			50
Non-cash interest (1)	2,665			1,858
Total interest costs incurred	42,105			45,881
Less:
Interest capitalized	(1,309		)	(1,939		)
Interest expense	$	40,796		$	43,942

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

Interest costs incurred for the 2014 period were lower when compared to the 2013 period primarily because of the refinancing of our debt securities in June 2013.

Income Taxes

The effective tax rates for the three months ended March 31, 2014 and 2013 are as follows:

	For the Three Months Ended March 31,
	2014			2013
	(in thousands)
Income tax (benefit) expense - U.S.	$	2,671		$	6,224
Effective tax rate - U.S.	(5.3		)%	(12.7		)%
Income tax (benefit) expense - Canada	$	(20	)	$	672
Effective tax rate - Canada	0.3		%	(18.1		)%
Income tax (benefit) expense - total	$	2,651		$	6,896
Effective tax rate - total	(4.7		)%	(13.1		)%

Income tax expense for the 2014 period included an increase in the U.S. valuation allowance of $19.5 million. Income tax recognized for the 2014 and 2013 periods is a result of hedge gains previously deferred in AOCI being realized during the quarter and the net tax impact being recognized.

Quicksilver Resources Inc. and its Restricted Subsidiaries

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

The combined results of operations for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated results of operations, which are discussed above under “Results of Operations,” except for Fortune Creek accretion expense. The combined financial position of Quicksilver and our restricted subsidiaries and our consolidated financial position are materially the same except for balances related to Fortune Creek which were included in the consolidated financial position as of March 31, 2014. The combined operating cash flows, financing cash flows and investing cash flows for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated operating cash flows, financing cash flows and investing cash flows, which are discussed below in “Cash Flow Activity,” except for cash flows associated with the operations and development of Fortune Creek.

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LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

Cash Flow Activity

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

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

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

For the remainder of 2014 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 March 31, 2014.

Production Year	Daily Production Volume
	Natural Gas	NGL	Natural Gas Basis Swaps
	MMcfd	MBbld	MMcfd
2014 (1)	170	4	40
2015	150	—	—
2016-2021	40	—	—

⁽¹⁾  Our 2014 NGL derivatives end in September. Our natural gas derivatives and AECO to NYMEX natural gas basis swaps are in place for the whole of 2014.

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

	For the Three Months Ended March 31,
	2014			2013
	(In thousands)
Net cash used in operating activities	$	(19,984	)	$	(14,394	)
Net cash provided by (used in) investing activities	31,309			(26,834		)
Net cash provided by (used in) financing activities	(31,905		)	45,824

Operating Cash Flows

Net cash used in operating activities for the 2014 period increased from the 2013 period due to lower production volumes, partially offset by positive changes in working capital, including the receipt of $7.9 million in income tax refunds.

Net cash used in operating activities for the 2014 period includes hedge cash settlements of $1.8 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 2014 period and 2013 period were as follows:

	United States		Canada		Consolidated
	(In thousands)
For the Three Months Ended March 31, 2014
Exploration and development	$	33,216	$	8,954	$	42,170
Midstream	11		—		11
Administrative	14		77		91
Total	$	33,241	$	9,031	$	42,272
For the Three Months Ended March 31, 2013
Exploration and development	$	20,553	$	3,064	$	23,617
Midstream	6		74		80
Administrative	393		247		640
Total	$	20,952	$	3,385	$	24,337

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

Several of our marketable securities matured during the 2014 quarter and were held as cash.

Financing Cash Flows

Distributions of Fortune Creek partnership funds of $29.5 million and $3.2 million were paid in the 2014 period and the 2013 period, respectively, to our partner based on our partner's preferential distribution rights.

Liquidity and Borrowing Capacity

At March 31, 2014, the Combined Credit Agreements’ global borrowing base was $350 million and the global letter of credit capacity was $280 million. At March 31, 2014, there was $99.6 million available under the Combined Credit Agreements. 2014 Highlights contains additional information regarding the Colorado sale.

In April 2014, our redetermined global borrowing base under our Combined Credit Agreements was $325 million. Further, the Combined Credit Agreements were amended changing the definition of EBITDAX. Additionally, we permanently reduced the aggregate maximum credit amounts under the Combined Credit Agreements from $1.75 billion to $650 million.

Our ability to remain in compliance with the financial maintenance 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 through the end of 2014, we do not expect to exceed the required levels by a significant margin, particularly the interest coverage ratio under our Combined Credit Agreements. Accordingly, even a modest decline in prices for natural gas and NGLs, our failure to achieve anticipated cost savings or operational efficiencies, our failure to execute certain asset purchases and/or repay certain debt 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 precluding further borrowings under our credit facilities and by accelerating the maturity of our debt.

In order to be able to incur debt, make restricted payments, designate unrestricted subsidiaries or effect mergers or consolidations, we must meet an incurrence test under the indentures applicable to our debt, which test requires EBITDA to exceed interest expense by 2.25 times. At March 31, 2014 and throughout the three months ended March 31, 2014, we did not meet this test and, as a result, we are limited in our ability to, among other things, incur additional debt, except for specific baskets. We do retain, however, the ability to utilize the full borrowing capacity under our Combined Credit Agreements and the ability to refinance existing debt. Not meeting this ratio does not represent an event of default under our debt. We are unable to predict when or if our EBITDA will exceed interest expense by 2.25 times.

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In addition, our Combined Credit Agreements, Second Lien Term Loan and Second Lien Notes due 2019 include springing maturities which could cause them to become due and payable prior to their stated maturity, which amount is material. Further, as a result of these springing maturities, our current liabilities could exceed current assets and we would be required to redirect cash flow from operations, cash on hand and proceeds from future asset sales away from operations, interest expense and capital spending to satisfy these maturities. If we have to sell assets or seek additional debt financing or equity capital, we may be unable to complete any such transactions on satisfactory terms, or at all. In April 2014, we deferred the earliest springing maturity to the last half of 2015 with the redemption of our Senior Notes due 2015 and 2016.

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

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

Our ability to borrow under our Combined Credit Agreements depends on our global borrowing base, which is regularly redetermined twice each year. A reduction to the global borrowing base during the spring or autumn redetermination, or upon a special redetermination requested by our administrative agent in the Combined Credit Agreements, could adversely impact our ability to meet our future obligations.

In March 2014, we agreed with KKR to an amendment to extend the ending date of the minimum gross capital expenditures requirement, of which C$120 million remains, to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset and to broaden allowable spending to include acquisitions of producing properties that utilize partnership assets. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by C$0.13 per Mcf until at least 2016.

Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or equity securities or other possible capital markets transactions, the proceeds of which could be used to refinance current indebtedness, reduce debt or for other corporate purposes. We will also consider from time to time additional acquisitions of, and investments in, assets or businesses that complement our existing asset portfolio. Acquisition transactions, if any, are expected to be financed through cash flow from operations, borrowings under the Combined Credit Agreements, proceeds from asset sales, the issuance of debt or other securities or a combination of those sources. Because we have not met our incurrence test, we are unable to fund acquisitions with debt other than under our Combined Credit Agreements. Our ability to access the debt and equity capital markets on economic terms is affected by general economic conditions, the domestic and global financial markets, our credit ratings assigned by independent credit rating agencies, our operational and financial performance, the value and performance of our equity and debt securities, prevailing commodity prices, and other macroeconomic factors outside of our control. In addition, we believe that access to the equity capital markets on economic terms will be limited if we are unable to execute a transaction involving our Horn River Asset, due in large part to our high debt levels relative to cash flow.

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Financial Position

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

• Cash, cash equivalents and marketable securities decreased $88.8 million as we used cash on hand to fund operations, capital expenditures and make a contribution to Fortune Creek, which was distributed to KKR based on their preferential rights.

• Our net property, plant and equipment balance increased $14.3 million from December 31, 2013 to March 31, 2014. The increase was primarily due to incurred capital costs of $42.3 million in 2014, partially offset by incurred depletion and depreciation of $12.6 million and $14.7 million related to U.S.-Canadian exchange rate changes.

• The $8.0 million decrease in accounts payable was due primarily to a decrease in trade payables of $8.6 million from December 31, 2013 as activity has decreased from year end.

Contractual Obligations and Commercial Commitments

There have been no significant changes to our contractual obligations and commitments as reported in our 2013 Annual Report on Form 10-K.

Critical Accounting Estimates

Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated interim financial statements and related footnotes contained within this report. The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions to determine certain of the assets, liabilities, revenue and expense. Our more critical accounting estimates used in the preparation of the consolidated financial statements were discussed in our 2013 Annual Report on Form 10-K. These critical estimates, for which no significant changes occurred during the three months ended March 31, 2014, include estimates and assumptions for:

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

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

OFF-BALANCE SHEET ARRANGEMENTS

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

RECENTLY ISSUED ACCOUNTING STANDARDS

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 2013 Annual Report on Form 10-K.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

37

We enter into financial derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future production and to increase the predictability of our revenue. Utilization of our financial hedging program will most often result in realized prices from the sale of our natural gas and NGLs that vary from market prices. As a result of settlements of derivative contracts, our revenue from natural gas and NGL production was greater by $9.5 million and $18.5 million for the 2014 period and 2013 period, respectively, and a loss was recognized in net derivative losses of $10.4 million for the 2014 period and a gain of $9.6 million for the 2013 period. Unrealized losses of $31.6 million and $41.0 million were recognized for the 2014 period and 2013 period, respectively.

The following table details our open derivative positions at March 31, 2014:

Product	Type	Segment	Remaining Contract Period	Volume	Price Per Mcf or Bbl
Gas	Swap	U.S.	Apr 2014 - Dec 2014	10 MMcfd	3.91
Gas	Swap	U.S.	Apr 2014 - Dec 2014	10 MMcfd	3.89
Gas	Swap	U.S.	Apr 2014 - Dec 2015	5 MMcfd	6.23
Gas	Swap	U.S.	Apr 2014 - Dec 2015	5 MMcfd	6.20
Gas	Swap	U.S.	Apr 2014 - Dec 2015	20 MMcfd	6.00
Gas	Swap	U.S.	Apr 2014 - Dec 2015	10 MMcfd	6.00
Gas	Swap	U.S.	Apr 2014 - Dec 2015	5 MMcfd	5.68
Gas	Swap	U.S.	Apr 2014 - Dec 2015	7.5 MMcfd	5.48
Gas	Swap	U.S.	Apr 2014 - Dec 2015	7.5 MMcfd	5.50
Gas	Swap	U.S.	Apr 2014 - Dec 2015	5 MMcfd	4.15
Gas	Swap	U.S.	Apr 2014 - Dec 2015	5 MMcfd	4.13
Gas	Swap	U.S.	Apr 2014 - Dec 2015	5 MMcfd	4.26
Gas	Swap	U.S.	Apr 2014 - Dec 2015	5 MMcfd	4.25
Gas	Swap	U.S.	Apr 2014 - Dec 2021	10 MMcfd	4.54
Gas	Swap	U.S.	Apr 2014 - Dec 2021	5 MMcfd	4.38
Gas	Swap	U.S.	Apr 2014 - Dec 2021	10 MMcfd	4.37
Gas	Swap	U.S.	Apr 2014 - Dec 2021	5 MMcfd	4.35
NGL	Swap	U.S.	Apr 2014 - Sept 2014	1 MBbld	30.43
NGL	Swap	U.S.	Apr 2014 - Sept 2014	2 MBbld	30.55
NGL	Swap	U.S.	Apr 2014 - Sept 2014	1 MBbld	30.55
Gas	Swap	Canada	Apr 2014 - Dec 2015	10 MMcfd	6.42
Gas	Swap	Canada	Apr 2014 - Dec 2015	10 MMcfd	6.45
Gas	Swap	Canada	Apr 2014 - Dec 2015	10 MMcfd	4.04
Gas	Swap	Canada	Apr 2014 - Dec 2021	10 MMcfd	4.625
Gas Basis1	Swap	Canada	Apr 2014 - Dec 2014	5 MMcfd	(0.475)
Gas Basis1	Swap	Canada	Apr 2014 - Dec 2014	5 MMcfd	(0.475)
Gas Basis1	Swap	Canada	Apr 2014 - Dec 2014	10 MMcfd	(0.475)
Gas Basis1	Swap	Canada	Apr 2014 - Dec 2014	10 MMcfd	(0.47)
Gas Basis1	Swap	Canada	Apr 2014 - Dec 2014	10 MMcfd	(0.45)

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

These open derivative positions had a net fair value of $84.5 million as of March 31, 2014.

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

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Interest Rate Risk

Changes in interest rates affect the interest rate we pay on borrowings under the Combined Credit Agreements, Second Lien Term Loan and Second Lien Notes due 2019. Our senior unsecured notes and senior subordinated notes have fixed interest rates and thus do not expose us to risk from fluctuations in market interest rates. Changes in interest rates do affect the fair value of our fixed rate debt.

In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We deferred gains of $30.8 million as a fair value adjustment to our debt, which we began to recognize over the life of the associated debt instruments. During the 2014 period and the 2013 period, we recognized $0.5 million and $1.3 million, respectively, of those deferred gains as a reduction of interest expense.

Should we be required to borrow under our Combined Credit Agreements and based on interest rates as of March 31, 2014, each $50 million in borrowings would result in additional annual interest payments of $2.0 million. If the current borrowing availability under our Combined Credit Agreements were to be fully utilized by year-end 2014 at interest rates as of March 31, 2014, we estimate that annual interest payments would increase by $4.0 million. If interest rates change by 1% on our March 31, 2014 variable debt balances of $207.7 million, our annual pre-tax income would decrease or increase by $2.1 million.

Our Second Lien Term Loan and Second Lien Notes due 2019 feature a LIBOR floor. Consequently, a 1% increase in the interest rates on our outstanding variable rate debt as of March 31, 2014, would not impact our applicable interest rate on this debt, as the floor would not be exceeded. A 1% decrease in the interest rate would not impact our applicable interest rate on this debt, as we have not exceeded the floor at March 31, 2014.

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

Foreign Currency Risk

Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. Non-functional currency transactions for the 2014 period and the 2013 period resulted in a loss of $0.3 million and a loss 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 Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2014, our disclosure controls and procedures were not effective, due to the outstanding remediation of the income tax material weakness and the significant transaction material weakness, both identified at December 31, 2013, to provide reasonable assurance that material information required to be disclosed by us (including our consolidated subsidiaries) in reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

As disclosed in our 2013 Annual Report on Form 10-K, two material weaknesses were identified related to the design and operating effectiveness of our controls. We identified a material weakness related to the accounting for significant, non-recurring transactions, particularly related to the accuracy of the inputs provided to accounting

39

to incorporate into the analysis of such transactions. This weakness caused several out of period adjustments principally between quarters in 2013 to be recognized in our financial statements though none of the adjustments were considered individually material.

We also had a material weakness related to the operating effectiveness of controls over the reconciliation of deferred income taxes, particularly related to the tax basis in property, plant and equipment. In response to this material weakness, management is working to complete a detailed reconciliation of the property, plant and equipment account balances.

While the remediation process is not yet complete, we have concluded that the financial statements in this Quarterly Report on Form 10-Q present fairly, in all material respects, our consolidated financial condition, results of operations and cash flows in conformity with generally accepted accounting principles in the U.S.

There has been no other change in our internal control over financial reporting during the quarter ended March 31, 2014, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1.   Legal Proceedings

There have been no material changes in the legal proceedings described in Part I, Item 3 included in our 2013 Annual Report on Form 10-K.

ITEM 1A.   Risk Factors

There have been no material changes in the risk factors described in Part I, Item 1A included in our 2013 Annual Report on Form 10-K.

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

Issuer Purchases of Equity Securities

The following table summarizes our repurchases of Quicksilver common stock during the quarter ended March 31, 2014.

Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan (2)	Maximum Number of Shares that May Yet Be Purchased Under the Plan (2)
January 2014	605,354	$	3.31	—	—
February 2014	4,787	$	3.11	—	—
March 2014	96,054	$	2.64	—	—
Total	706,195	$	3.22	—	—

⁽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	Letters to J. David Rushford dated July 15, 2013					†
10.2	Mutual Release Agreement, dated January 21, 2014, between Quicksilver Resources Inc. and Thomas F. Darden					†
10.3 *	First Amending Agreement, dated March 13, 2014, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc., Makarios Midstream Inc., Fortune Creek Gathering and Processing Partnership and 0927530 B.C. Unlimited Liability Company					†
10.4	Quicksilver Resources Inc. Exempt Employee Discretionary Bonus Plan					†
10.5	Omnibus Amendment No. 7 to Combined Credit Agreements, dated as of April 25, 2014, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein					†
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					†
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					†
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					†
101.INS	XBRL Instance Document					‡
101.SCH	XBRL Taxonomy Extension Schema Linkbase Document					‡
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					‡
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document					‡
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					‡
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document					‡

* Certain portions of this exhibit have been omitted and filed separately under an application for confidential treatment.

42

SIGNATURES

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

Dated:	May 9, 2014	Quicksilver Resources Inc.
		By:	/s/ John C. Regan
			John C. Regan
			Senior Vice President-Chief Financial Officer (Duly Authorized Officer, Principal Financial and Accounting Officer)

43

EXHIBIT INDEX

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
10.1	Letters to J. David Rushford dated July 15, 2013					†
10.2	Mutual Release Agreement, dated January 21, 2014, between Quicksilver Resources Inc. and Thomas F. Darden					†
10.3 *	First Amending Agreement, dated March 13, 2014, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc., Makarios Midstream Inc., Fortune Creek Gathering and Processing Partnership and 0927530 B.C. Unlimited Liability Company					†
10.4	Quicksilver Resources Inc. Exempt Employee Discretionary Bonus Plan					†
10.5	Omnibus Amendment No. 7 to Combined Credit Agreements, dated as of April 25, 2014, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein					†
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					†
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002					†
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					†
101.INS	XBRL Instance Document					‡
101.SCH	XBRL Taxonomy Extension Schema Linkbase Document					‡
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					‡
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document					‡
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					‡
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document					‡

* Certain portions of this exhibit have been omitted and filed separately under an application for confidential treatment.

44