UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K/A

Amendment No. 1

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

For the fiscal year ended December 31, 2013

OR

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

For the transition period from to

Commission file number:    001-14837

QUICKSILVER RESOURCES INC.

(Exact name of registrant as specified in its charter)

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

817-665-5000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, $0.01 par value per share	New York Stock Exchange
Preferred Share Purchase Rights, $0.01 par value per share	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨No  þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨No  þ

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  þNo  ¨

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þNo   ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

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.

Large accelerated filer  ¨ Accelerated filer  þ Non-accelerated filer  ¨ 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

As of June 30, 2013, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $209,743,745 based on the closing sale price of $1.68 as reported on the New York Stock Exchange.

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

Class	Outstanding at February 28, 2014
Common Stock, $0.01 par value per share	177,191,991 shares

DOCUMENTS INCORPORATED BY REFERENCE

Document	Parts Into Which Incorporated
Proxy Statement for the Registrant’s May 14, 2014 Annual Meeting of Stockholders	Part III

Explanatory Note

This Amendment No. 1 to the Quicksilver Resources Inc. Annual Report on Form 10-K for the fiscal year ended December 31, 2013, which was originally filed with the Securities and Exchange Commission on March 17, 2014 (the “Original Filing”), is being filed to correct inadvertent clerical errors in Exhibits 31.1, 31.2 and 32.1. No other change to the previously filed certifications is intended to be made by the filing of this Form 10-K/A, and this Form 10-K/A does not amend, update or change any other items or disclosures contained in the Original Filing. This Amendment No. 1 to the Form 10-K continues to speak as of the date of the Original Filing and does not reflect any events that occurred at any subsequent date.

DEFINITIONS

As used in this Annual 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

“Bcf” means billion cubic feet

“Bcfe” means Bcf of natural gas equivalents

“Boe” means Bbl equivalents, calculated as six Mcf of gas equaling one bbl of oil

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

“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

“GHG” means greenhouse gas

“GPT” means gathering, processing and transportation expense

“LIBOR” means London Interbank Offered Rate

“LNG” means liquefied natural gas

“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

“PUD” means proved undeveloped reserve

“RSU” means restricted stock unit

“Tcfe” means trillion cubic feet of natural gas equivalents

“WTI” means West Texas Intermediate

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

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

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

“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

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

“BBEP” means BreitBurn Energy Partners L.P.

“BBEP Unit” means BBEP limited partner unit

“CERCLA” means the Comprehensive Environmental Response, Compensation and Liability Act

“CMLP” means Crestwood Midstream Partners LP

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

“Crestwood” means Crestwood Holdings LLC

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

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

“Eni Production” means production attributable Eni’s working and royalty interests

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

“EPA” means the U.S. Environmental Protection Agency

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

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

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

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

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

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

“IRS” means the U.S. Internal Revenue Service

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

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

“Komie North Project” means the series of contracts with NGTL for the construction of a pipeline and meter station in the Horn River basin

“Lake Arlington Asset” means our natural gas leasehold interests in the Lake Arlington area of the Barnett Shale

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

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

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

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

“OSHA” means Occupational Safety & Health Administration

“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 pending sale of our Niobrara Asset to Southwestern Energy Company

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

“Synergy” means Synergy Offshore LLC

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

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

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

“VIE” means variable interest entity

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

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INDEX TO ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2013

PART I
ITEM 1.	Business	10
ITEM 1A.	Risk Factors	20
ITEM 1B.	Unresolved Staff Comments	32
ITEM 2.	Properties	32
ITEM 3.	Legal Proceedings	32
ITEM 4.	Mine Safety Disclosures	32
PART II
ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	33
ITEM 6.	Selected Financial Data	35
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk	62
ITEM 8.	Financial Statements and Supplementary Data	65
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	120
ITEM 9A.	Controls and Procedures	120
ITEM 9B.	Other Information	124
PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	124
ITEM 11.	Executive Compensation	124
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	124
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	125
ITEM 14.	Principal Accountant Fees and Services	125
PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	126
	Signatures	133

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 Annual 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 and the resulting acceleration of debt thereunder and 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 closing the proposed Southwestern Transaction or 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 Annual Report.

This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict, and are subject to material uncertainties that may affect actual results and may be beyond our control. The forward-looking statements included in this Annual Report are made only as of the date of this Annual 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

ITEM 1. Business

GENERAL

We are an independent oil and gas company engaged in the acquisition, exploration, development and production of onshore oil and natural gas in North America and are based in Fort Worth, Texas. We focus primarily on unconventional reservoirs where hydrocarbons may be found in challenging geological conditions, such as fractured shales and coalbeds. Our producing oil and natural gas properties in the United States are principally located in Texas and in Canada in Alberta and British Columbia. We had total proved reserves of approximately 1.3 Tcfe at December 31, 2013. Our three core development areas include:

• Barnett Shale;

• Horn River; and

• Horseshoe Canyon.

Additionally, we have an oil exploration opportunity in the Delaware basin in western Texas. This exploration project provides opportunity to grow our oil portfolio in the future. We actively study the above basins and other basins in North America, which may result in future oil and natural gas acquisitions.

Our common stock trades under the symbol “KWK” on the New York Stock Exchange.

FORMATION AND DEVELOPMENT OF BUSINESS

We were organized as a Delaware corporation in 1997 and became a public company in 1999. As of February 28, 2014, members of the Darden family and entities controlled by them beneficially owned approximately 30% of our outstanding common stock. Our discussion of liquidity, capital resources and financial position in Item 7 of this Annual Report contains additional information about recent developments in our liquidity and capital structure.

STRATEGIC TRANSACTIONS IN THE LAST FIVE YEARS

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 $0.13 per Mcf until at least 2016. Additionally, as a result of this amendment, KKR is no longer required to fund the capital for construction of a proposed gas treatment facility, but at its option may provide funding for any facility to be constructed by the Partnership, including the proposed gas treatment facility. The amendment provides us with additional time and flexibility in completing a joint venture transaction involving our Horn River Asset and immediate cash flow relief through the reduced gathering fee paid to Fortune Creek.

In March 2014, we executed an agreement with Southwestern Energy Company to sell all of our Niobrara Asset for cash proceeds of $90 million. The transaction is expected to close in May 2014. The decision to sell this acreage was largely rooted in SWEPI’s plans to exit its North American shale plays, including the shared interest in our Niobrara Asset.

In October and November 2013, we executed two separate agreements involving our West Texas Asset, the larger of which is a joint venture with Eni whereby we will jointly evaluate, explore and develop approximately 52,500 gross acres currently held by us in Pecos County, Texas. Under the terms of the agreement, Eni will pay up to $52 million in three phases to earn a 50% interest in our acreage. Upon completion of the three phases, we will participate equally in all future revenue, operating costs and capital expenditures with Eni. We also executed a farm-out agreement with another partner covering 7,500 gross acres also located in Pecos County. As a result of these two transactions, we expect future development of our West Texas Asset to be focused exclusively on Pecos County. These transactions are in line with our 2013 goal to partner with third-parties to develop our West Texas Asset.

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In August 2013, we divested our Southern Alberta Basin Asset in Montana to Synergy with an effective date of January 1, 2013. The purchase price was $46 million, which was subject to customary purchase price adjustments, resulting in a final purchase price of $42 million. This transaction was in line with our goal to divest non-core assets in 2013.

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 million. We view our relationship with TGBR to be a long-term, strategic partnership.

In January 2013, the Canadian NEB recommended against approval of NGTL’s Komie North Project, which included a 75-mile TransCanada pipeline that would connect NGTL’s Alberta system to a meter station planned to be constructed on our acreage in the Horn River basin. We paid NGTL $13 million in the third quarter of 2013 after which the related letter of credit was terminated. We no longer have financial commitments to the project until such time we ask NGTL to reapply for a permit related to the Komie North Project on our behalf.

In December 2012, we formed a partnership with SWEPI to jointly develop our oil and gas interests in the Niobrara formation of the Sand Wash basin in northwest Colorado and to establish an Area of Mutual Interest (“AMI”) covering in excess of 850,000 acres. Each party assigned to the other a 50% working interest in the majority of its combined acreage resulting in each party owning a 50% interest in more than 320,000 acres and having the right to a 50% interest in any acquisition within the AMI. SWEPI paid us an equalization payment for 50% of the acreage contributed by us in excess of the acreage that SWEPI contributed.

In December 2011, we and KKR formed a midstream partnership to construct and operate natural gas midstream services to support producer customers in British Columbia. We contributed our existing 20-mile, 20-inch gathering line and compression facilities and entered into a 10-year contracts of gas deliveries into those facilities to the partnership in exchange for $125 million and a 50% interest in the partnership. In the event that NGTL constructs an extension to our Fortune Creek meter station, the partnership is strategic to the continued development of our Horn River Asset as it is expected to yield reduced costs for treating and transporting gas to sales markets. The partnership’s midstream services could also be attractive to other producers in the Horn River basin and in adjacent basins.

In October 2010, we sold all of our interest in KGS, our Barnett Shale midstream subsidiary, to Crestwood for a payment of $700 million in cash and assumed debt of $58 million. We recognized a gain of $494 million and in February 2012, we received an additional $41 million for consideration of an earn-out on these assets.

In May 2010, we acquired an additional 25% working interest in our Lake Arlington Asset which represented 125 Bcf of proved reserves, for $62 million in cash and 3.6 million BBEP Units. Throughout 2010 and 2011, through this and other transactions, we continued to sell our BBEP Units. We have owned no BBEP Units since 2011.

In January 2010, we completed the sale of certain midstream assets to KGS for $95 million. KGS funded the purchase primarily with proceeds from an equity offering to the public.

In June 2009, we completed the Eni Transaction in which we sold 121 Bcf of proved reserves to Eni for $280 million. As part of the transaction, we and Eni formed a strategic alliance for the acquisition and development of unconventional natural gas resources in an area covering approximately 270,000 acres surrounding our Alliance Asset.

BUSINESS STRATEGY

We have a multi-pronged strategy to increase share value through long-term, cost-effective growth in production and reserves by focusing on unconventional resources plays onshore in North America. This strategy has been established through our proven record and expertise in identifying and developing properties containing fractured shale and coalbed methane. Our strategy includes the following key elements:

Strive to achieve and maintain a capital structure that reflects financial flexibility:  We believe that attaining a more flexible financial structure would better enable us to capitalize on opportunities and to limit our financial risk. As such, in June 2013, we accessed the debt markets for $1.2 billion to refinance our debt at favorable interest rates and extended our weighted average debt maturity by nearly 2.5 years. Throughout 2013, we monetized core and non-core assets to improve liquidity and to reduce debt. We would like to further improve

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liquidity and reduce debt, and we believe that a transaction involving our Horn River Asset will be an important catalyst by providing cash proceeds, reduced capital spending exposure in the future and by improving our ability to access debt and equity capital markets on more favorable terms to enable us to accommodate debt maturities and reduce our overall debt levels.

In order to increase the predictability of the prices we receive for our natural gas and NGL production, we hedge the commodity price of a substantial portion of our expected production with financial derivatives. We regularly review the creditworthiness of our derivative counterparties and our derivative program is spread among numerous financial institutions, all of whom participated in our credit facilities at the time of entering into the derivative. In previous years, we have entered into long-term derivatives to provide predictability over longer periods and to support our financial resilience.

Focus on core areas of repeatable, low-risk development and conduct limited exploration activities:  We believe that development activity in areas where we have acquired a contiguous acreage position and have operational concentration allows us to efficiently deploy our resources, manage our costs and leverage our technical expertise. Additionally, we search for new acreage positions that are not only contiguous from a surface perspective, which is more efficient for drilling, but are also contiguous from a resource perspective, which we believe results in higher returns on investments. At current pricing levels, our Barnett Asset and Horseshoe Canyon Asset represent the lowest risk development within our portfolio.

Focus on organic growth opportunities:  Through our experience in multiple unconventional resources basins, we have established significant expertise and a demonstrated history of identifying, developing and producing fractured shales and coal beds. We completed a number of divestitures in 2013 and chose to weight our 2013 capital program on exploratory endeavors, but expect that in 2014 and beyond we will direct a greater percentage of our capital spending toward our core areas in an attempt to increase production and cash flows from operations. Although a transaction involving our Horn River Asset would result in immediate reductions to our production and reserves, we believe that such a transaction would provide greater ability to develop our retained portion of that asset, which development could provide significant uplift to currently recognized reserves.

We believe our core strength lies in our ability to identify and acquire large resource targets at low cost per acre. Once we secure an acreage position, we then drill resource assessment wells and validation wells to determine the size and commerciality of the project. If a project is validated, we may build additional midstream infrastructure to secure affordable gathering, processing and transportation. Finally, we move the project to full development stage. We have historically monetized some of our mature assets to provide financial flexibility to pursue future projects.

Develop our abundant reserves with strategic partners and link to premium markets:  We believe our extensive acreage in North America is ideal for joint ventures and the value of our assets has the greatest upside through joint development with strategic partners. With this strategy, we expect to be able to grow reserves and production while limiting our capital expenditures. We have developed a strong working relationship with several high quality partners and we have expanded our relationship with Eni in 2013 as we plan to jointly develop our West Texas Asset.

We believe the steady evolution of LNG in North America may provide the opportunity to link our natural gas to international markets, where prices are substantially higher than NYMEX. We believe our Horn River Asset is well situated to source LNG exports in the future and is an attractive option for an end user wishing to purchase natural gas on a gas-weighted benchmark price. In the interim, we believe that existing midstream availability in the Horn River basin is sufficient to accommodate our capital spending and production development over the next three to five years. We believe the Tokyo Gas Transaction involving our Barnett Shale Asset is indicative of our ability to align our assets with the needs of global end users.

BUSINESS STRENGTHS

High-quality asset base with long reserve life:  Our proved reserves totaled approximately 1.3 Tcfe as of December 31, 2013, of which almost 90% is developed. Our Barnett Shale Asset accounts for approximately 80% of our proved reserves and approximately 15% are located in our Horseshoe Canyon Asset and 5% in our Horn River Asset. These areas have a history of proven well performance and have the established and emerging infrastructure necessary to deliver our production to sales markets.

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We believe our reserves are characterized by long lives and predictable well production profiles. Based on our annualized fourth quarter 2013 average production from all of our properties, our implied reserve life (proved reserves divided by annualized fourth quarter 2013 production) was 13.7 years and our implied proved developed reserve life (proved developed reserves divided by annualized fourth quarter 2013 production) was 12.1 years. As of December 31, 2013, over 95% of our proved reserves were attributable to properties we operate.

Multi-year inventory of developmental drilling projects:  As of December 31, 2013, we owned leases covering more than 568,000 net acres in our three core areas. Within our Barnett Shale Asset alone, we have identified drilling locations currently not classified as “proved” that provide us a multi-year inventory of drilling locations based on our trailing three year historical drilling rate. Our drilling success rate has averaged greater than 99% during the past three years. We use 3-D seismic data to enhance our ongoing drilling and development efforts as well as to identify targets in both new and existing fields. Our seismic library covers more than 90% of our acreage in our Barnett Shale Asset.

We have also identified exploratory opportunities that provide exposure to additional oil and natural gas resources. As of December 31, 2013, we have successfully drilled and completed 12 gas wells in our Horn River Asset, and 98% of our licensed acreage has been validated. Total proved reserves in our Horn River Asset are 70 Bcfe. We have drilled two wells in our West Texas Asset and have plans to drill more wells with our partners, including Eni, beginning as early as the first quarter of 2014.

Extensive technical experience and familiarity with developing and operating Barnett Shale properties and other unconventional resources.  We are a top-six producer in the Barnett Shale producing approximately 340 MMcfed during the fourth quarter of 2013 on a gross basis with over 900 wells drilled since 2007. We have a team of professionals, many of whom have significant engineering, geologic and other expertise, who work in tandem with our valued professional consultants to operate in unconventional resource plays. We have identified a multi-year inventory of producing wells located in the Barnett Shale where we also conduct low-cost workovers to provide attractive returns, including payback periods of one to two months. We intend to utilize these resources to optimize our recovery of reserves and to enhance the value of our assets.

Superior Shareholder Alignment:  The Darden family and entities owned by them maintain greater than a 30% equity interest in Quicksilver. In addition, all employees are also shareholders through the company’s equity-based, long-term incentive programs. We believe this to be a business strength as management, employees and shareholders alike share a vested interest in long-term value creation.

FINANCIAL INFORMATION ABOUT SEGMENTS AND GEOGRAPHICAL AREAS

The consolidated financial statements included in Item 8 of this Annual Report contain information on our segments and geographical areas and are incorporated herein by reference.

PROPERTIES

Substantially all of our properties consist of interests in developed and undeveloped oil and natural gas leases. In addition, we own gathering facilities in our Horn River Asset along with KKR, with whom we formed Fortune Creek.

OIL AND NATURAL GAS OPERATIONS

Our oil and natural gas operations are focused onshore in North America, in basins containing unconventional reservoirs with predictable, long-lived production. Our current production and development operations are concentrated in our three core areas: the Barnett Shale, Horn River and Horseshoe Canyon. At December 31, 2013, we had total proved reserves of approximately 1.3 Tcfe, of which 82% is natural gas and 18% is NGLs. For 2013, we had total production of 108 Bcfe or 295.8 MMcfed. In 2013, we sold 337 Bcfe of Barnett Shale reserves to TGBR and approximately 2,100 MBbl of reserves from our Southern Alberta Basin Asset to Synergy, which represented a sale of our entire interest.

We believe the development of our leasehold interest in our core areas, in concert with our exploration activities in our West Texas Asset may afford us the opportunity over the next several years to grow reserves and production. We may also pursue acquisitions of additional interests where economically feasible, particularly in

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our core operating areas, which would allow for further capitalization on our proven expertise in unconventional resource plays. Details of our 2014 capital program and our projected production levels can be found in Item 7 of this Annual Report. Our future capital program and ability to complete acquisitions will require continued liquidity which may be dependent on continued access to capital through debt and equity transactions.

Barnett Shale

At December 31, 2013, we held approximately 85,000 net acres in the Barnett Shale after selling 25% of these assets to TGBR in April 2013. Proved reserves were 1.1 Tcfe. Our acreage is divided between the dry gas areas in Tarrant and Denton counties in the northern part of the Fort Worth Basin, and the high-Btu natural gas areas in Hood and Somervell counties in the southern part of the basin. NGLs are extracted through midstream facilities that we constructed and are now owned by CMLP. In the current pricing environment, where NGLs trade at a premium to methane, we are able to enhance our revenue per Mcf of natural gas production by extracting and separately selling NGLs. In 2013, sales of NGLs represented 25% of our Barnett Shale Asset production and 17% of consolidated production revenue.

We limited the level of drilling activity in 2013 due to weak natural gas and NGL prices and limitations in the amount of capital available for deployment. As commodity prices improved in the latter half of 2013, we deployed a drilling rig in our Alliance leasehold to convert near-term expiring leases. As operator, we drilled 6 (3.1 net) wells but completion of these wells was deferred into 2014. We also drilled 1 (0.8 net) and completed 3 (2.3 net) wells in our Lake Arlington leasehold during 2013. At December 31, 2013, we have a total of 975 (596.7 net) producing wells in our Barnett Shale Asset.

We expect to employ a single drilling rig program in the Barnett Shale throughout 2014.

West Texas

Our focus in West Texas is approximately 60,000 gross acres in Pecos County, which is being jointly developed with Eni and another party. We believe this acreage is prospective for the Bone Springs and Wolfcamp formations. We do not expect to conduct drilling operations in our leases outside of Pecos County in the near future. We are currently evaluating our strategic options for this acreage as part of our streamlined focus in West Texas.

In 2013, we completed two joint venture transactions to promote the development of our most prospective leasehold in West Texas and to streamline our focus. The above section, “Strategic Transactions in the Last Five Years” contains a more detailed description.

We did not have a material amount of proved reserves from our West Texas Asset at December 31, 2013.

Horn River

We hold approximately 130,000 net acres in our Horn River Asset. We drilled an eight-well pad in 2012 and those eight wells have been our highest producing wells to date. Proved reserves in our Horn River Asset at December 31, 2013 were 69.7 Bcfe. Our Horn River Asset contains the most prolific wells in our portfolio, however continued capital deployment will require substantial amounts of liquidity. In full development, individual wells on a multi-well pad could cost up to $20 million or more. Thus, in order to best capitalize on the potential of this resource, attracting the right partner is critical to us. We expect to significantly limit our capital spending in our Horn River Asset until our strategic transaction pursuit is completed.

In May 2013, we purchased a former paper mill site located in Campbell River, British Columbia with the intent to begin feasibility studies for development of the site as an LNG export facility. The 1,200 acre site is classified as a brownfield redevelopment site and zoned as heavy industrial land with deep-water access. We believe the site is an attractive option for redevelopment as a liquefaction facility and ultimately expect to apply for an export license.

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 plan to announce more information about this project and our development plans as appropriate.

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Horseshoe Canyon

We hold approximately 353,000 net acres in our Horseshoe Canyon Asset. As of December 31, 2013, our Horseshoe Canyon Asset proved reserves were 196.4 Bcfe, of which substantially all was natural gas. We expect to commence a substantial drilling and completion program in this area in 2014.

OIL AND NATURAL GAS RESERVES

Our proved reserve estimates and related disclosures for 2013, 2012 and 2011 are presented in compliance with SEC rules and regulations. The information, with respect to our proved reserves and related disclosures, has been prepared by Schlumberger PetroTechnical Services (“Schlumberger”) and LaRoche Petroleum Consultants, Ltd. (“LaRoche”), our independent reserve engineers for U.S. and Canada, respectively.

The process of estimating our proved reserves is complex. In order to prepare these estimates, we have developed, maintained and monitored internal processes and controls for estimating and recording proved reserves in compliance with the rules and regulations of the SEC. Compliance with SEC reserve guidelines is the primary responsibility of our reservoir engineering team. We require that proved reserve estimates be made by qualified third party reserve estimators, as defined by the Society of Petroleum Engineers’ standards. Our reservoir engineering team, which is responsible for our proved reserve estimates, participates in continuing education to maintain a current understanding of SEC reserve reporting requirements.

Our reservoir engineering team, led by David Haugen, Vice President - Engineering, is responsible for the preparation and maintenance of our engineering data and review of our proved reserve estimates with Schlumberger and LaRoche. Mr. Haugen has over 20 years of experience in the oil and gas industry. Mr. Haugen is licensed as a Professional Engineer, registered with the Association of Professional Engineers, Geologists and Geophysicists of Alberta and is a member of the Society of Petroleum Engineers. Mr. Haugen earned a Bachelor of Science degree in Petroleum Engineering from the University of Alberta in Alberta, Canada. The reservoir engineering team reports directly to him on all reserves issues and is thus independent from management for our operating areas. Throughout the year, the reservoir engineering team analyzes the performance of producing properties for each operating area, identifies proved reserve additions and revisions and prepares internal proved reserve estimates. In addition, the team is responsible for maintaining all reserve engineering data. Integrity of reserve engineering data is enhanced by restricting full access to only the members of our reservoir engineering team. Limited other personnel have read-only access with no ability to modify reserve engineering data.

The technical person at Schlumberger responsible for overseeing the preparation of our estimates of proved reserves is Charles M. Boyer II, PG, CPG. Mr. Boyer is licensed in the Commonwealth of Pennsylvania and has over 30 years of geologic and engineering experience in the oil and gas industry. Mr. Boyer earned a Bachelor of Science degree in geological sciences from The Pennsylvania State University in University Park and completed graduate studies in mining and petroleum engineering at the University of Pittsburgh and The Pennsylvania State University. The technical person at LaRoche primarily responsible for overseeing the preparation of our estimates of proved reserves is Stephen W. Daniel. Mr. Daniel is a Professional Engineer licensed in the State of Texas who has over 40 years of engineering experience in the oil and gas industry. Mr. Daniel earned a Bachelor of Science degree in Petroleum Engineering from University of Texas and has prepared reserves estimates for his employers throughout his career. He has prepared and overseen preparation of reports for public filings for LaRoche for the past 17 years. The technical persons at Schlumberger and LaRoche responsible for preparing our estimates of U.S. and Canadian proved reserves meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Prior to finalizing their proved reserve estimates, each of Schlumberger’s and LaRoche’s results are reviewed in detail by internal reservoir engineering teams, Mr. Haugen and the other members of our executive management team.

The Audit Committee of our Board has met with our executive management team, Mr. Haugen, Schlumberger and LaRoche to discuss the process and results of proved reserve estimation. The analytical review of proved reserve estimates includes comparisons of ending proved undeveloped estimates to our average ending ultimate recoverable proved reserves for each of our operating areas. Additional reviews of drilling results and proved undeveloped estimates have been conducted with our executive management team and the Audit Committee of our Board.

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Pursuant to the rules and regulations of the SEC, proved reserves are the estimated quantities of natural gas, NGLs and oil which, through analysis of geological and engineering data, demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” connotes a high degree of confidence that the quantities of natural gas, NGLs and oil actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the technologies used in the estimation process must have been demonstrated to yield results with consistency and repeatability. Proved developed reserves are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are expected to be recovered from new wells on undrilled acreage. Proved reserves for undrilled wells are estimated only where it can be demonstrated that there is continuity of production from the existing productive formation. To achieve reasonable certainty of our proved reserve estimates, our reservoir engineering team assumes continued use of technologies with demonstrated success of yielding expected results, including the use of drilling results, well performance, well logs, seismic data, geologic maps, well stimulation techniques, well test data, and reservoir simulation modeling.

The proved reserve data we disclose are estimates and are subject to inherent uncertainties. The determination of our proved reserves is based on estimates that are highly complex and interpretive. Reserve engineering is a subjective process that depends upon the quality of available data and on engineering and geological interpretation and judgment. Although we believe our proved reserve estimates are reasonable, reserve estimates are imprecise and are expected to change as additional information becomes available. Additional information regarding risks associated with estimating our proved reserves may be found in Item 1A of this Annual Report.

The following table summarizes our proved reserves.

	Proved Developed Reserves			Proved Undeveloped Reserves			Total Proved Reserves
	For the Years Ended December 31,			For the Years Ended December 31,			For the Years Ended December 31,
	2013	2012	2011	2013	2012	2011	2013	2012	2011
Natural gas (MMcf)
U.S.	702,147	725,361	1,244,187	122,303	122,687	584,717	824,450	848,048	1,828,904
Canada	260,159	266,783	299,371	5,896	—	31,260	266,056	266,783	330,631
Total	962,306	992,144	1,543,558	128,199	122,687	615,977	1,090,506	1,114,831	2,159,535
NGL (MBbl)
U.S.	34,603	47,284	60,902	5,131	8,890	41,243	39,734	56,174	102,145
Canada	9	10	11	—	—	—	9	10	11
Total	34,612	47,294	60,913	5,131	8,890	41,243	39,743	56,184	102,156
Oil (MBbl)
U.S.	139	2,416	2,545	60	113	490	199	2,529	3,035
Canada	—	—	—	—	—	—	—	—	—
Total	139	2,416	2,545	60	113	490	199	2,529	3,035
Total (MMcfe)
U.S.	910,601	1,023,562	1,624,866	153,445	176,703	835,118	1,064,046	1,200,265	2,459,984
Canada	260,215	266,845	299,437	5,896	—	31,260	266,112	266,845	330,697
Total	1,170,816	1,290,407	1,924,303	159,341	176,703	866,378	1,330,158	1,467,110	2,790,681

	Years Ended December 31,
	2013		2012		2011
Representative prices for reserve estimation purposes:
Natural gas – Henry Hub, per MMBtu	$	3.67	$	2.76	$	4.12
Natural gas – AECO, per MMBtu	2.90		2.35		3.65
Oil – WTI Cushing, per Bbl	97.18		94.71		95.71
Standardized measure of discounted future net  cash flows (1) (in millions)	$	823.0	$	715.1	$	1,734.9

⁽¹⁾  Determined based on year-end unescalated costs in accordance with the guidelines of the SEC, discounted at 10% per annum, net of tax.

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The reference price used for our NGLs was based on WTI Cushing, adjusted for local differentials, gravity and BTU.

PROVED UNDEVELOPED RESERVES

Our 2013 drilling and completion activities related to our proved undeveloped locations as of December 31, 2012 were as follows:

	For the Year Ended December 31, 2013
	Drilled		Completed		Producing
	Gross	Net	Gross	Net	Gross	Net
Barnett Shale	5.0	1.1	—	—	—	—

Costs incurred in 2013 relating to the drilling and completion activities related to our proved undeveloped locations as of December 31, 2012 were $2.0 million.

Our gross capital costs for a Barnett Shale Asset well from preparation of the multi-well drilling pad through the initiation of production have an estimated median of $3.2 million depending on factors such as the area, the depth and lateral length of each well, number of stages of fracture stimulation and its distance to central facilities. On each multi-well drilling pad, we drill all the wells prior to initiation of completion activities. As a result, we maintain an inventory of drilled wells awaiting completion.

In our Horseshoe Canyon Asset, the gross capital costs for a typical well from pre-drilling preparation through the initiation of production, generally range from $0.3 million to $0.4 million depending upon the number of coal seams, depth and distance to a gathering system.

The following table summarizes our proved undeveloped reserves activity during the year ended December 31, 2013 (in MMcfe):

Beginning proved undeveloped reserves	176,705
Extensions and discoveries	56,903
Transfers to proved developed	(21,441	)
Revisions of previous estimates	(52,826	)
Ending proved undeveloped reserves	159,341

As of December 31, 2013, we had total proved undeveloped reserves of 153.4 Bcfe in our Barnett Shale Asset on 55 well locations, all of which are scheduled for development before the end of 2018. Our proved undeveloped reserves of 5.9 Bcfe on 32 well locations in our Horseshoe Canyon Asset are all planned for development in 2014.

We estimate that our proved undeveloped well locations will be developed on the following timeline:

	Barnett Shale	Horseshoe Canyon
2014	20	32
2015	13	—
2016	11	—
2017	9	—
2018	2	—
Total	55	32

During 2014, we expect to spend $48.4 million to drill, complete and tie-in wells on proved locations. Estimated future development costs on proved locations as of December 31, 2013 are projected to be $26.7 million for 2015, $23.6 million for 2016, $20.0 million for 2017, and $3.9 million for 2018.

At December 31, 2013, our inventory of proved undeveloped drilling locations included four wells that have been recognized as proved reserves for five years or longer as these four wells are in our 2014 drilling schedule.

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DEVELOPMENT AND EXPLORATION ACTIVITIES AT YEAR END

At December 31, 2013, we had one drilling rig operating in our Barnett Shale Asset and no completion work was in progress. In the U.S. we had 26 (18.7 net) wells awaiting completion or tie-in to sales lines as these wells were drilled to preserve acreage.

No drilling rigs were operating in our Horn River Asset at December 31, 2013. There are currently 6 (6.0 net) wells drilled and awaiting completion that have no proved reserves assigned. These wells were drilled to preserve acreage and will not be completed until the gathering infrastructure is extended into these areas based upon the results of future drilling in the area. Additionally, 83 (67.9 net) wells in our Horseshoe Canyon Asset were awaiting completion or tie-in to sales lines at December 31, 2013.

DRILLING ACTIVITY

During the periods indicated, we drilled the following exploratory and development wells:

	Years Ended December 31,
	2013		2012		2011
	Gross	Net	Gross	Net	Gross	Net
Development:
U.S.
Productive (1)	14	5.4	22	20.5	61	49.6
Non-productive	—	—	—	—	—	—
Canada
Productive (2)	3	0.4	2	2.0	18	14.9
Non-productive	—	—	—	—	—	—
Total	17	5.8	24	22.5	79	64.5
Exploratory:
U.S.
Productive	—	—	8	5.7	8	6.0
Non-productive	—	—	—	—	—	—
Canada
Productive	—	—	2	2.0	4	4.0
Non-productive	—	—	—	—	—	—
Total	—	—	10	7.7	12	10.0
Total:
Productive	17	5.8	34	30.2	91	74.5
Non-productive	—	—	—	—	—	—
Total	17	5.8	34	30.2	91	74.5

⁽¹⁾  U.S. development drilling includes non-operated drilling of 6 wells (1.1 net), 2 wells (0.0 net) and 4 wells (0.0 net) for 2013, 2012 and 2011, respectively.

⁽²⁾  Canadian development drilling includes non-operated drilling of 3 wells (0.4 net) and 2 wells (1.0 net) for 2013 and 2011, respectively.

VOLUME, SALES PRICES AND OIL AND GAS PRODUCTION EXPENSE

The discussion of volume produced from, revenue generated by and cost associated with operating our properties included in Management’s Discussion and Analysis in Item 7 of this Annual Report is incorporated herein by reference.

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DELIVERY COMMITMENTS AND PURCHASERS OF NATURAL GAS, NGLs AND OIL

We have contracts with third parties that require we provide minimum daily natural gas or NGL volume for gathering, fractionation and transportation, as determined on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. We will utilize production volumes from our wells plus royalty volumes we control and other third-party volumes towards meeting our commitments below. We will fund any shortfall with cash which could be between $16 million and $18 million in 2014 depending on our production levels and our ability to fulfill our commitment through third-party production. In Canada, we have incurred unused firm capacity expenses of $7.4 million, $6.7 million and $4.6 million for 2013, 2012 and 2011, respectively.

Our prospective obligations under existing agreements are summarized below:

	Total	2014	2015	2016	2017	2018	Thereafter
				(In MMcfe)
Gathering
Horn River	800,253	77,491	73,545	73,746	73,545	120,001	381,925
Processing, Treating and Fractionation
Barnett Shale	295,812	29,565	29,565	29,646	29,565	29,565	147,906
Horn River	175,907	37,045	37,045	37,146	37,045	23,476	4,150
Transportation
Barnett Shale	382,627	90,440	89,757	76,088	71,296	37,896	17,150
Horseshoe Canyon	4,612	3,861	738	13	—	—	—
Horn River	67,917	19,862	19,862	19,917	8,276	—	—

Our Horn River transportation commitment decreased from our commitment at December 31, 2012 due to the Canadian Governor in Council's failure to approve NGTL's construction of the Komie North Project and the resulting termination by NGTL of the Project and Expenditure Authorization.

We have dedicated substantially all natural gas production from our Barnett Shale Asset for gathering and compression to CMLP through 2020. The rates charged by CMLP are fixed for each system but vary by system and range from $0.72 to $0.87 per Mcf of gathered volume, subject to annual inflationary increases. Processing fees are fixed at $0.71 per Mcf, and are also subject to annual inflationary increases. We are not obligated to guarantee CMLP any minimum volume (accordingly the above table of commitments does not include amounts which flow to CMLP).

We sell natural gas, NGLs and oil to a variety of customers, including utilities, major oil and natural gas companies or their affiliates, industrial companies, large trading and energy marketing companies and other users of petroleum products. Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. Accordingly, the loss of any single purchaser would not materially affect our revenue. During 2013, Targa Liquids Marketing and Trade, the largest purchaser of our production, accounted for 18% of our cash collected for natural gas, NGL and oil sales.

As further discussed in Note 15 to the financial statements included in Item 8 of this Annual Report, we also have requirements to expend capital in the drilling and completion, or in limited acquisition, of resources in our Horn River Asset pursuant to our Fortune Creek partnership.

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ACQUISITION, EXPLORATION AND DEVELOPMENT CAPITAL EXPENDITURES

The following table summarizes our acquisition, exploration and development costs incurred:

	U.S.		Canada		Consolidated
	(In thousands)
2013
Proved acreage	$	—	$	—	$	—
Unproved acreage	15,843		6,305		22,148
Development costs	49,299		17,422		66,721
Exploration costs	—		—		—
Total	$	65,142	$	23,727	$	88,869
2012
Proved acreage	$	—	$	—	$	—
Unproved acreage	23,711		5,612		29,323
Development costs	131,926		178,808		310,734
Exploration costs	35,244		8,304		43,548
Total	$	190,881	$	192,724	$	383,605
2011
Proved acreage	$	—	$	—	$	—
Unproved acreage	145,099		—		145,099
Development costs	304,373		90,361		394,734
Exploration costs	37,673		41,338		79,011
Total	$	487,145	$	131,699	$	618,844

PRODUCTIVE OIL AND GAS WELLS

The following table summarizes productive wells:

	As of December 31, 2013
	Natural Gas		Oil
	Gross	Net	Gross	Net
U.S.	980	600.7	9	5.1
Canada	2,921	1,442.2	3	—
Total	3,901	2,042.9	12	5.1

OIL AND GAS ACREAGE

Our principal oil and gas properties consist of non-producing and producing oil and gas leases and mineral acreage, including reserves of natural gas and oil in place. Developed acres are defined as acreage allocated to wells that are producing or capable of producing. Undeveloped acres are acres on which wells are not to a point that would permit the production of commercial reserves or acreage which has not yet been allocated to any wells, regardless of whether such acreage contains proved reserves. Gross acres are the total number of acres in which we have a working interest. Net acres are the sum of our fractional interests owned in the gross acres.

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The following table indicates our interest in developed and undeveloped acreage:

	As of December 31, 2013
	Developed Acreage		Undeveloped Acreage
	Gross	Net	Gross	Net
Barnett Shale	94,888	60,345	40,424	24,228
West Texas (1)	2,200	2,001	195,828	145,407
Niobrara	8,396	3,107	456,890	162,990
Other U.S.	10,018	5,452	85,065	71,178
U.S.	115,502	70,905	778,207	403,803
Horseshoe Canyon	459,233	293,504	68,984	59,966
Horn River Basin	15,616	13,729	124,804	115,369
Canada	474,849	307,233	193,788	175,335
Total	590,351	378,138	971,995	579,138

⁽¹⁾  Includes 137,836 gross (95,684 net) total acres located outside Pecos County.

The following table summarizes information regarding the total number of net undeveloped acres as of December 31, 2013:

		2014 Expirations		2015 Expirations		2016 Expirations
	Net Undeveloped Acres	Net Acres	Net Acres with Options to Extend	Net Acres	Net Acres with Options to Extend	Net Acres	Net Acres with Options to Extend
Barnett Shale	24,228	3,958	5	3,965	389	3,781	7
West Texas	145,407	58,132	36,180	49,364	4,516	27,757	—
Niobrara	162,990	44,134	28,925	39,022	5,649	29,579	6,827
Other U.S.	71,178	14,396	—	3,152	—	11,485	—
Canada	175,335	6,903	—	3,282	—	23,732	—
Total	579,138	127,523	65,110	98,785	10,554	96,334	6,834

All of the acreage scheduled to expire can be held through drilling and producing operations. We believe that we have the ability to retain substantially all of the expiring acreage that we believe will provide economic returns either through drilling activities or through the exercise of extension options.

COMPETITION

We compete for acquisitions of prospective oil and natural gas properties and oil and gas reserves. We also compete for drilling rigs and equipment used to drill for and produce oil and gas. Our competitive position is dependent upon our ability to recruit and retain geological, engineering and management expertise. We believe that the location of our leasehold acreage, our exploration and production expertise and the experience and knowledge of our management team enable us to compete effectively in our core operating areas. However, we face competition from a substantial number of other companies, many of which have larger technical staffs and greater financial and operational resources than we do and from companies in other, but potentially related, industries.

GOVERNMENTAL REGULATION

Our operations are affected from time to time in varying degrees by political developments and U.S. and Canadian federal, state, provincial and local laws and regulations. In particular, our production and related operations are, or have been, subject to taxes and other laws and regulations relating to the industry. Failure to comply with such laws and regulations can result in substantial penalties and delayed operations. The regulatory burden on the industry increases our cost of doing business and affects our profitability. We do not anticipate any significant challenges in complying with laws and regulations applicable to our operations.

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SAFETY REGULATION

We are subject to a number of federal, state, provincial and local laws and regulations, whose purpose is to protect the health and safety of workers, both generally and within our industry. Regulations overseen by OSHA, the EPA, Human Resources and Skills Development Canada, Environment Canada and other agencies require, among other matters, that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We are also subject to safety regulations which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.

ENVIRONMENTAL MATTERS

We are subject to stringent and complex federal, state, provincial and local environmental laws, regulations and permits, including those relating to the generation, storage, handling, use, disposal, gathering, transmission and remediation of natural gas, NGLs, oil and hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife, habitat, water and wetlands protection; the storage, use, treatment and disposal of water, including processed water; and the placement, operation and reclamation of wells. In particular, many of these requirements are intended to help preserve water resources and regulate those aspects of our operations that could potentially impact surface water or groundwater. If we violate these requirements, or fail to obtain and maintain the necessary permits, we could be subject to sanctions, including the imposition of fines and penalties, as well as potential orders enjoining future operations or delays or other impediments in obtaining or renewing permits. Pursuant to such laws, regulations and permits, we may be subject to operational restrictions and have made and expect to continue to make capital and other compliance expenditures.

We could be liable for any environmental contamination at our or our predecessors' currently or formerly owned, leased or operated properties or third-party waste disposal sites. Certain environmental laws, including CERCLA, more commonly known as Superfund, impose joint and several strict liability for releases of hazardous substances at such properties or sites, without regard to fault or the legality of the original conduct. In addition to potentially significant investigation and remediation costs, environmental contamination can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.

Environmental laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. For example, various federal, state, provincial and local initiatives have been implemented or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. In particular, the EPA has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of wastewater from certain gas production operations. In addition, certain states and Canadian provinces in which we operate, including Colorado, Texas, British Columbia and Alberta, have adopted, or are considering adopting, regulations that have imposed, or could impose, more stringent permitting, transparency, disposal and well construction requirements. States and Canadian provinces in which we operate, including Texas, Colorado and British Columbia require public disclosure of chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations also may regulate, restrict or prohibit the performance of well drilling in general and hydraulic fracturing in particular, and may require baseline water well sampling. Baseline water quality sampling and studies prior to and following certain drilling operations are required in Colorado, British Columbia and Alberta. Such laws and regulations may result in increased scrutiny or third-party claims, or otherwise result in operational delays, liabilities and increased costs.

Regulators are also becoming increasingly focused on air emissions from our industry, including volatile organic compound and methane emissions and water quality concerns. This increased scrutiny has led to heightened enforcement of existing regulations as well as the imposition of new air emission measures. The EPA has implemented requirements for sulfur dioxide, volatile organic compound and hazardous air pollutant air emissions from oil and gas operations, including standards for wells that are hydraulically fractured. In addition, from time to time, initiatives are proposed that could further regulate certain exploration and production by-products as hazardous wastes and subject them to more stringent requirements. Any current or future air

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emission, hazardous waste or other environmental requirements applicable to our operations could curtail our operations or otherwise result in operational delays, liabilities and increased costs.

Greenhouse gas (“GHG”) emission regulation is also becoming more stringent. We are currently required to implement a GHG recordkeeping and reporting program due to issuance of the EPA's subpart W regulation, which requires significant effort to quantify sources at all of our production sites and requires us to report our GHG emissions from operations. Our operations in British Columbia are subject to similar GHG reporting requirements. In addition, regulatory authorities are considering, or have developed, energy or emission measures to reduce GHG emissions. For example, the EPA has begun regulating GHG emissions from stationary sources pursuant to the Prevention of Significant Deterioration and Title V provisions of the federal Clean Air Act, as a result of which we might be required to obtain permits to construct, modify or operate facilities on account of, and implement emission control measures for, our GHG emissions. In British Columbia, we are subject to a carbon tax on our purchase or use of virtually all carbon-based fuels (including natural gas), which is payable at the time such fuel is purchased or otherwise used. Any limitation, or further regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could restrict our operations and subject us to significant costs, including those relating to emission credits, pollution control equipment, monitoring and reporting. Although there is still significant uncertainty surrounding the scope, timing and effect of GHG regulation, any such regulation could have a material adverse impact on our business, financial condition, reputation and operating performance.

In addition, to the extent climate change results in more severe weather, our operations may be disrupted. For example, storms in the Gulf of Mexico could damage downstream pipeline infrastructure causing a decrease in takeaway capacity and potentially requiring us to curtail production. In addition, warmer temperatures might shorten the time during the winter months when we can access certain remote production areas resulting in decreased exploration and production activity.

AVAILABILITY OF REPORTS AND CORPORATE GOVERNANCE DOCUMENTS

Our website is located at www.qrinc.com, and our investor relations website is located at investors.qrinc.com. The following filings are available through our investor relations website as soon as we electronically file or furnish such material to the SEC:

•Annual Reports on Form 10-K;

•Quarterly Reports on Form 10-Q;

•Current Reports on Form 8-K and

• amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934.

All such postings and filings are available on our investor relations website free of charge. The SEC's web site, www.sec.gov, contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

We use our investor relations website as a routine channel for distribution of important information, including news releases, analyst presentations, and financial information, as a means of disclosing material non-public information and for complying with our disclosure obligations under Regulation FD. Additionally, we provide notifications of news or announcements as part of our investor relations website. Investors and others can receive notifications of new information posted on our investor relations website in real time by signing up for email alerts and RSS feeds. Accordingly, investors should monitor this portion of our website in addition to following press releases, SEC filings and public conference calls and webcasts. Further, charters for the committees of our Board and our Corporate Governance Guidelines and Code of Business Conduct and Ethics can be found on our website under the heading “Corporate Governance.” Our website and the information contained therein or connected thereto shall not be deemed to be incorporated into this Annual Report on Form 10-K or in any other report or document we file with the SEC, and any references to our websites are intended to be inactive textual references only.

EMPLOYEES

As of February 28, 2014, we had 338 employees, none of whom are covered by collective bargaining agreements.

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EXECUTIVE OFFICERS OF THE REGISTRANT

The following information is provided with respect to our executive officers as of February 28, 2014.

Name	Age	Position(s)
Glenn Darden	58	Director, President and Chief Executive Officer
Anne Darden Self	56	Director, Vice President - Human Resources
John C. Regan	44	Senior Vice President - Chief Financial Officer and Chief Accounting Officer
Stan Page	56	Senior Vice President - U.S. Operations
John D. Rushford	54	Senior Vice President and Chief Operating Officer of Quicksilver Resources Canada Inc.

Officers are elected by our Board of Directors and hold office at the pleasure of the Board until their successors are elected and qualified. Glenn Darden, Anne Darden Self and Thomas F. Darden are siblings. The following biographies describe the business experience of our executive officers:

GLENN DARDEN has served on our Board of Directors since December 1997 and became our Chief Executive Officer in December 1999. He served as our Vice President until he was elected President and Chief Operating Officer in March 1999. Prior to that time, he served with Mercury for 18 years, the last five as Executive Vice President. Mr. Darden previously worked as a geologist for Mitchell Energy Company LP (subsequently merged with Devon Energy). He served as a director of Crestwood Gas Services GP LLC, the general partner of Crestwood Gas Services LP (formerly known as Quicksilver Gas Services LP), from March 2007 to October 2010.

ANNE DARDEN SELF has served on our Board of Directors since August 1999, and became our Vice President - Human Resources in July 2000. She is also currently President of Mercury, where she has worked since 1992. From 1988 to 1991, she was employed by Banc PLUS Savings Association in Houston, Texas, initially as Marketing Director and for three years thereafter as Vice President of Human Resources. She worked from 1987 to 1988 as an Account Executive for NW Ayer Advertising Agency. Prior to 1987, she spent several years in real estate management.

JOHN C. REGAN became our Senior Vice President - Chief Financial Officer and Chief Accounting Officer in April 2012, after serving as our Vice President and Chief Accounting Officer since September 2007. Mr. Regan is a Certified Public Accountant with more than 20 years of combined public accounting, corporate finance and financial reporting experience. Mr. Regan joined us from Flowserve Corporation where he held various management positions of increasing responsibility from 2002 to 2007, including Vice President of Finance for the Flow Control Division and Director of Financial Reporting. He was also a senior manager specializing in the energy industry in the audit practice of PricewaterhouseCoopers LLP, where he was employed from 1994 to 2002.

STAN PAGE became our Senior Vice President - U.S. Operations in June 2010, after serving as our Vice President - U.S. Operations since October 2007. Mr. Page joined us from BP America (formerly known as Amoco Production Company) where he held various management positions of increasing responsibility from 1979 to 2007, including Operations Center Manager for East Texas Operations from 2005 to 2007.

JOHN D. RUSHFORD became Senior Vice President and Chief Operating Officer of Quicksilver Resources Canada Inc. in August 2010. He is a Professional Engineer with more than 30 years of oil and gas experience in project development and business unit management. Mr. Rushford joined us from Cenovus Energy Inc. where he served as the Vice President of Business Services supporting Cenovus' business unit operations from 2005 to 2010. Prior to Cenovus he had more than 15 years of increasingly senior management positions at PanCanadian Petroleum Ltd. and EnCana Corp., including Vice President of the Chinook Business Unit that commercialized coalbed methane in Canada and as Vice President of the Fort Nelson Business Unit.

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ITEM 1A. Risk Factors

You should carefully consider the following risk factors together with all of the other information included in this Annual Report, including the financial statements and related notes, when deciding to invest in us. You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report could have a material adverse effect on our business, financial position, results of operations and cash flows.

The provisions of our debt agreements and the risks associated with our debt could adversely affect our business, financial condition and results of operations, and could cause our securityholders to experience a partial or total loss of their investment in us.

Subject to the limits and conditions contained in our various debt agreements, we may incur additional debt. Our ability to incur additional debt and to comply with the terms of our debt agreements is affected by a variety of factors, including commodity prices and their effects on the value of our proved reserves, financial condition, results of operations and cash flows. In addition, we expect our ability to borrow under our Combined Credit Agreements will depend on our borrowing base, which is redetermined twice each year based on our reserve reports and such other information deemed appropriate by the administrative agent in a manner consistent with its normal oil and gas lending criteria as it exists at the time of the redetermination. The semi-annual scheduled redetermination of the Combined Credit Agreements occurs each spring and autumn. In addition, we or the administrative agent can each elect to cause a special borrowing base redetermination for any reason one time between each scheduled redetermination. We are only in the preliminary stages of the spring 2014 redetermination process and cannot yet determine what, if any, adjustment occurs to the borrowing base. While we believe that the remaining availability under our Combined Credit Agreements together with cash and short-term securities on hand, recurring operating cash flow and asset sale proceeds will be adequate to meet our liquidity needs for the remainder of 2014, the borrowing base could be reduced during the spring or autumn redetermination, or otherwise, and that amount may cause our liquidity to be insufficient. If we incur additional debt or fail to maintain or increase the quantity and value of our proved reserves, the risks that we expect to face as a result of our indebtedness could intensify.

Our ability to comply with the covenants and other provisions of our debt agreements may be affected by events beyond our control, and we may be unable to comply with all aspects of our debt agreements in the future. While we believe that we will be able to comply with our financial maintenance 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 production estimates and cost savings or operational efficiencies, our failure to execute certain asset purchases, 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 financial maintenance 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 addition, our Combined Credit Agreements, Second Lien Term Loan and Second Lien Notes due 2019 include springing maturities which could cause this debt to come due 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 our capital program to satisfy these maturities. Further, we may retain a portion of the cash received from our asset sales but our indentures require us to reinvest or repay senior debt with net cash proceeds from asset sales within one year. If certain capital spending and senior debt repayment thresholds are not met, we could be required to make an offer to repay our notes, which amount could be material. Our debt agreements, among other things, require the maintenance of and compliance with financial and other covenants and provisions that are more fully described in Note 11 to our consolidated financial statements found in Item 8 of this Annual Report.

We have demands on our cash resources, including recurring operating expenses, funding of our capital expenditures and contractual commitments and the interest expense we expect to have on our outstanding debt. Our level of debt, the value of our oil and gas properties and other assets, the demands on our cash resources, and

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the provisions of our outstanding debt could have materially adverse effects on our business and on the value of our securities. For example, the provisions of our outstanding debt could:

• make it more difficult for us to satisfy our obligations with respect to our debt;

• require us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing the amount of our cash flow available for working capital, capital expenditures, acquisitions and other general corporate purposes;

• require us to make principal payments if the quantity and value of our proved reserves are insufficient to support our level of borrowings;

• limit our flexibility in planning for, or reacting to, changes in the oil and gas industry;

• place us at a competitive disadvantage compared to our competitors who may have lower debt service obligations and greater financing flexibility than we do;

• limit our financial flexibility, including our ability to borrow additional funds;

• increase our interest expense on our variable rate borrowings if interest rates increase;

• limit our ability to make capital expenditures to develop our properties;

• increase our vulnerability to exchange risk associated with Canadian dollar denominated indebtedness; and

• increase our vulnerability to general adverse economic and industry conditions.

In addition, failure to comply with the provisions of our debt agreements could result in an event of default which could enable the applicable creditors to declare the outstanding principal and accrued interest to be immediately due and payable. Moreover, any of our debt agreements that contain a cross-default or cross-acceleration provision could also be subject to acceleration. If we were unable to repay the accelerated amounts, the creditors could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, we may have insufficient assets to repay such debt in full, and the holders of our securities could experience a partial or total loss of their investment and our business, financial condition and results of operations could be adversely affected.

Our ability to pay principal and interest on our debt, to otherwise comply with the provisions of our outstanding debt may be affected by economic and capital markets conditions and other factors that may be beyond our control. If we are unable to service our debt, fund our other liquidity needs or comply with provisions of our debt, we will be forced to adopt alternative strategies that may include:

• reducing or delaying capital expenditures;

• seeking additional debt financing or equity capital;

• selling assets;

• restructuring or refinancing debt; or

• reorganizing our capital structure.

We may be unable to implement any of these strategies on satisfactory terms, or at all, and our inability to do so could cause our securityholders to experience a partial or total loss of their investment in us.

Our Horn River Asset has the potential for development of significant resources, but is expensive to develop and requires us to attract one or more strategic partners to fully realize its value.

The successful development of our Horn River Asset will require significant capital resources and currently exceeds our ability to finance such development. We need to attract and successfully execute one or more transactions involving our Horn River Asset to fully fund the development of these potential resources. If we are unable to successfully execute a transaction involving our Horn River Asset, we may be unable to develop our Horn River Asset to its full resource potential.

Commodity prices fluctuate widely, and low prices could adversely affect our ability to borrow under and comply with our debt agreements and have a material adverse impact on our business, financial condition and results of operations.

Our revenue, profitability, and future growth depend in part on prevailing commodity prices. These prices also affect the amount of cash flow available to service our debt, fund our capital program and our other liquidity needs, as well as our ability to borrow, raise additional capital and comply with the terms of our various debt agreements, including our financial maintenance covenants. Among other things, the amount we can borrow under our Combined Credit Agreements is subject to periodic redetermination based in part on expected future prices. Lower prices may also reduce the amount of natural gas, NGLs and oil that we can economically produce.

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Prices for our production fluctuate widely, particularly as evidenced by price movements between 2008 and 2013. Among the factors that can cause these fluctuations are:

• domestic and foreign demand for oil, natural gas and NGLs;

• the level and locations of domestic and foreign oil and natural gas supplies;

• the quality, price and availability of alternative fuels;

• the quantity of natural gas in storage;

• weather conditions;

• domestic and foreign governmental regulations, including environmental regulations;

• impact of trade organizations, such as the Organization of Petroleum Exporting Countries, or OPEC;

• political conditions in oil and natural gas producing regions;

• localized supply and demand fundamentals and transportation availability;

• technological advances affecting energy consumption;

• speculation by investors in oil and natural gas; and

• worldwide economic conditions.

Due to the volatility of commodity prices and the inability to control the factors that influence them, we cannot predict future pricing levels. A decrease in commodity prices without an offsetting significant increase in production or cash received from our derivatives program could have a material adverse impact on our business activities, financial condition and results of operations.

A decrease in the prices we receive for our production, unsuccessful exploration and development efforts or a substantial increase in our costs, could have a material adverse effect on our results of operations.

We employ the full cost method of accounting for our oil and gas properties which, among other things, imposes limits to the capitalized cost of our assets. The capitalized cost pool cannot exceed the present value of the estimated cash flows from the underlying oil and gas reserves discounted at 10%. We could recognize future impairments if the commodity prices utilized in determining proved reserves value cause the value of our proved reserves to decrease. Increased operating and capitalized costs without incremental increases in proved reserve value could also trigger impairment based upon decreased value of our proved reserves. The impairment of our oil and gas properties will cause us to reduce their carrying value and recognize non-cash expense, which could have a material adverse effect on our results of operations.

Our proved reserve and production estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in these estimates or underlying assumptions may materially affect the quantities and present value of our proved reserves and our forecasted production.

The process of estimating proved reserves and production is complex. In order to prepare these estimates, we and our independent reserve engineers must project future production rates and the timing and amount of future development expenditures and such projections may be inaccurate. We and the engineers must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. In addition to interpreting available technical data, we and the engineers must also analyze other various assumptions and the estimated production. Actual future production, commodity prices, revenue, taxes, development expenditures, operating expenses and our estimated quantities of recoverable proved reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of proved reserves and the estimated production presented in our filings with the SEC. In addition, we may adjust estimates of production and estimates of proved reserves to reflect production history, results of exploration and development, prevailing commodity prices and other factors that may be beyond our control.

We have proved reserves that are undeveloped. Recovery of proved undeveloped reserves requires additional capital expenditures and successful drilling and completion operations. Our proved reserve estimates assume that we will make significant capital expenditures to develop our proved undeveloped and non-producing reserves. Although we have prepared estimates of our proved reserves using SEC specifications, actual prices and costs may vary from these estimates, the development of our reserves may not occur as scheduled or actual results of that development may not be as estimated prior to drilling.

The present value of future net cash flows disclosed in Item 8 of this Annual Report is not necessarily the fair value of our proved reserves. In accordance with SEC requirements, the discounted future net cash flows from proved reserves for 2013 are based upon prices determined on an unweighted average of the preceding 12-month first-day-of-the-month prices adjusted for local differentials and operating and development costs as of period end.

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Actual future prices and costs may be materially higher or lower than the prices and costs used in our estimates, which are calculated in accordance with SEC requirements. Any changes in consumption by natural gas, NGL and oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the costs from the development and production of our oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is specified by the SEC for calculating discounted future net cash flows, may not reflect current conditions. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general would affect the appropriateness of the 10% discount factor in arriving at the actual fair value of our proved reserves.

All of our producing properties and operations are located in a small number of geographic areas, making us vulnerable to risks associated with operating in limited geographic areas.

Our production is concentrated in three core areas. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or gas produced from the wells in these areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our business, financial condition and results of operations.

Our Canadian operations present unique risks and uncertainties, different from or in addition to those we face in our U.S. operations.

In addition to the various risks associated with our U.S. operations, risks associated with our operations in Canada, where we have substantial operations, include, among other things, risks related to increases in taxes and governmental royalties, aboriginal claims, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and compliance with U.S. and Canadian laws and regulations, such as the U.S. Foreign Corrupt Practices Act. For example, in addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates and other matters. The royalty regime is a significant factor in the profitability of oil and gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced. Laws and policies of the U.S. affecting foreign trade and taxation may also adversely affect our Canadian operations.

In addition, the level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing our activity levels. Also, certain of our oil and gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Therefore, seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity.

Aboriginal peoples in Canada hold certain constitutionally protected rights pursuant to historic occupation of lands, historic customs and treaties with governments. Such rights may include, among other things, rights to access lands and hunting and fishing rights. The extent and nature of aboriginal rights vary from place to place in Canada, depending on historic and contemporary circumstances. All of our Horn River Asset acreage is located within the Treaty 8 settlement negotiated between the Federal Crown and First Nations and is subject to aboriginal rights associated with traditional use of the lands that could potentially impact our ability to develop and produce our mineral rights. We are not aware that any claims have been made against us in respect of our properties and assets in connection with aboriginal rights; however, if a claim arose and was successful, such claim may have a

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material adverse effect on our business, financial condition and results of operations. In addition, prior to making decisions that may adversely affect existing or claimed aboriginal rights, governments in Canada have a duty to consult with aboriginal people potentially affected, and in some instances, a duty to accommodate concerns raised through such consultation. Regulatory authorizations for our operations may be affected by the time required for the completion of aboriginal consultation, and operational restrictions imposed by governmental authorities pursuant to such consultation may materially affect our business, financial condition and results of operations.

If we are unable to obtain needed capital or financing on satisfactory terms or maintain adequate liquidity, our ability to replace our proved reserves or to maintain current production levels and generate revenue will be limited.

Historically, we have used our cash flow from operations, borrowings under our credit facilities and proceeds from issuances of debt and asset dispositions to fund our capital program, working capital needs and acquisitions. Our capital program will require additional financing above the level of cash generated by our operations to fund our growth. If our cash flow from operations remains depressed or decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain current production may be limited, resulting in decreased production and proved reserves over time. If our cash flow from operations is insufficient to satisfy our financing needs, we cannot be certain that additional financing will be available to us on acceptable terms or at all. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our ability to successfully execute joint venture and other strategic transactions as well as our financial condition or general economic conditions at the time of any such financing or offering. At December 31, 2013 we did not meet the interest coverage ratio related to our indentures, which restricts our ability to incur additional debt, although we can refinance our existing debt. We may need lender permission to access the capital markets and we may be unsuccessful in obtaining that permission. Even if we are successful in obtaining the necessary funds, the terms of such financings could have a material adverse effect on our business, results of operations and financial condition. If additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis. Drilling activity may be directed by our partners in certain areas and may result in us forfeiting acreage if we do not have sufficient capital resources to fund our portion of expenses.

Our business involves many hazards and operational risks.

Our operations are subject to many risks inherent in the oil and gas industry, including operating hazards such as well blowouts, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, injuries to personnel, formations with abnormal pressures, treatment plant “downtime,” pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could cause us to experience substantial losses. The occurrence of a significant accident or other event could curtail our operations and have a material adverse effect on our business, financial condition and results of operations.

Liabilities and expenses not covered by our insurance could have a material adverse effect on our business, financial condition and results of operations.

As a result of operating hazards, regulatory risks and other uninsured risks, we could incur substantial liabilities to third parties or governmental entities. We maintain insurance against some, but not all, of such risks and losses in accordance with customary industry practice. We are not insured against all incidents, claims or damages that might occur, and pollution and environmental risks generally are not fully insurable. Any significant accident or event that is not insured at levels that may become payable could materially adversely affect our business, financial condition and results of operations. In addition, we may be unable to economically obtain or maintain the insurance that we desire, or may elect not to obtain or renew insurance if we believe that the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for all or some certain of our insurance policies could escalate further. In some instances, certain insurance could become unavailable or available only at reduced coverage levels. Any type of catastrophic event that is not covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

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The failure to replace our proved reserves could adversely affect our business, financial condition, results of operations, production and cash flows.

Oil and gas proved reserves are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions or divestitures. Our proved reserves will generally decline as commodity prices decrease and as proved reserves are produced, except to the extent that we conduct successful exploration or development activities or acquire additional proved reserves. In order to maintain or increase proved reserves and production, we must continue our development drilling or undertake other replacement activities. Our planned exploration and development projects or any acquisition activities that we may undertake might not result in meaningful additional proved reserves, and we might not have continuing success drilling productive wells. Even in the event that our exploration and development projects do result in meaningful additional commercially viable proved reserves, midstream infrastructure for these proved reserves may not exist or may not be constructed, either of which could adversely impact our ability to benefit from those proved reserves. If our exploration and development efforts are unsuccessful, our leases covering acreage that is not already held by production could expire. If they do expire and if we are unable to renew the leases on acceptable terms, we will lose the right to conduct drilling activities and the resulting economic benefits associated therewith. If we are unable to develop or acquire additional proved reserves to replace our current and future production at economically acceptable terms, our business, financial condition and results of operations would be materially adversely affected. Further, our limited liquidity has caused us to limit the development of and exploration for additional reserves, and future development and exploration will require continued liquidity. If we divest any of our producing assets, our production and cash flows will be reduced. Drilling may occur at a rate directed by our partners in certain areas and may not be sufficient to grow production or proved reserves.

We rely upon the operations of gas gathering, treating, processing, liquids fractionation and transportation facilities we do not own or operate.

We deliver our production to market through gathering, treating, fractionation and transportation systems that we do not own or operate. The marketability of our production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. A portion of our production could be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, terrorist activities and other security threats, maintenance of third-party facilities or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities or interstate pipelines to transport our production. Disruption of our production could negatively impact our ability to market, fractionate and deliver our production. Since we do not own or operate these assets, their continuing operation is not within our control. If any of these pipelines and other facilities becomes unavailable or capacity constrained, or if further planned development of such assets is delayed or abandoned, it could have a material adverse effect on our business, financial condition and results of operations.

Competition in our industry is intense, and we are smaller and have a more limited operating history than many of our competitors.

We compete with major and independent oil and gas companies for property acquisitions and for the equipment and labor required to develop and operate our properties. Many of our competitors have substantially greater financial and other resources than we do, and they may be better able to absorb the burden of drilling and infrastructure costs, implementation of new technologies and any changes in federal, state, provincial and local laws and regulations than we can, which would adversely affect our competitive position. In addition, there is substantial competition for investment capital in the oil and gas industry. These competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than we can. Our ability to explore for oil and gas prospects and to acquire additional properties in the future will depend upon our ability to conduct operations, to evaluate and select suitable properties and to complete transactions in this highly competitive environment. Furthermore, the oil and gas industry competes with other industries in supplying the energy and fuel needs of industrial, commercial and other consumers. Our inability to compete effectively with other oil and gas companies could have a material adverse impact on our business activities, financial condition and results of operations.

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Our economic hedging policy may not effectively mitigate the impact of commodity price volatility on our cash flows, and our economic hedging activities could result in losses or limit our ability to benefit from price increases.

To reduce our exposure to commodity price fluctuations, we have entered and intend to continue to enter into commodity derivatives covering our future production, which may limit the benefit we would receive from increases in commodity prices. These arrangements also expose us to risk of financial losses in some circumstances, including the following:

• our production could be materially less than expected; or

• the counterparties to the contracts could fail to perform their contractual obligations.

If our actual production and sales for any period are less than the production covered by commodity derivatives (including reduced production due to operational delays) or if we are unable to perform our exploration and development activities as planned, we might be required to satisfy a portion of our obligations under those commodity derivatives without the benefit of the cash flow from the sale of that production, which may materially impact our liquidity. Additionally, if market prices for our production exceed collar ceilings or swap prices, we would be required to make monthly cash payments, which could materially adversely affect our liquidity.

The price for natural gas set by our derivatives has been significantly higher than the prevailing price for natural gas over the past two years. We currently maintain a portfolio of commodity derivatives covering approximately 70% of our estimated production over the next two years. However, the commodity derivatives covering a significant portion of our production expire in 2015 or earlier, and we may not be able to enter into additional commodity derivatives covering our production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than our competitors who engage in hedging arrangements. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

We mark our derivatives to market with the unrealized changes in their fair value recorded in earnings. This election, particularly on our multi-year derivatives, may create volatility to our reported earnings levels compared with our earnings had we elected to apply hedge accounting.

Difficulties or delays in obtaining oil field equipment and increases in drilling and other service costs could adversely affect our ability to pursue our drilling program.

As commodity prices increase and exploration and development activity increases in established and emerging basins, demand and costs for drilling equipment, crews and associated supplies, equipment and services can increase significantly. We cannot be certain that in a higher commodity price environment we would be able to obtain necessary drilling equipment and supplies in a timely manner, on satisfactory terms or at all, and we could experience difficulty in obtaining, or there may be material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services. In addition, drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, including urban drilling, and possible title issues. As a result of increased activity levels, we have seen increases and supply limitations for the services we procure. Any such shortages or delays and price increases could adversely affect our ability to execute our drilling program.

Our activities are regulated by complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to various U.S. and Canadian federal, state, provincial and local government laws and regulations that could change in response to economic or political conditions. Matters that are typically regulated include:

• discharge permits for drilling and completion operations;

• water obtained for drilling and completion purposes;

• drilling permits and bonds;

• reports concerning operations;

• spacing of wells;

• operations and personnel safety;

• water and waste disposal, including disposal wells;

• wildlife habitat restrictions;

• air emissions limits and permitting;

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• hydraulic fracturing chemical disclosures;

• unitization and pooling of properties; and

• taxation.

From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity to conserve supplies of natural gas and oil. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, laws, regulations and tax requirements frequently are changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We cannot assure you that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, will not materially adversely affect our business, results of operations and financial condition.

We benefit from federal income tax provisions with respect to natural gas and oil exploration and development, and those provisions may be limited or repealed by future legislation.

The Obama administration's 2014 budget proposes to eliminate certain U.S. federal income tax benefits currently available to oil and gas exploration and production companies. These proposals include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the manufacturing deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. These changes are similar to proposals in prior years that were not enacted into law. It is unclear whether such changes will be enacted or how soon they would be effective if enacted. Enactment of these proposals or other similar changes in U.S. federal income tax law could eliminate or defer certain tax credits or deductions that are currently available with respect to our activities, and any such change could negatively affect our financial condition and results of operations. See also “-Our activities are regulated by complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.”

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

We are subject to stringent and complex U.S. and Canadian federal, state, provincial and local environmental laws, regulations and permits relating to, among other things, the generation, storage, handling, use, disposal, gathering, transmission and remediation of natural gas, NGLs, oil and hazardous materials; the emission and discharge of such materials to the ground, air and water; aging equipment; wildlife, habitat, water and wetlands protection; threatened and endangered species protection; the storage, use, treatment and disposal of water, including process water; the placement, operation and reclamation of wells; and the health and safety of our employees. These requirements may impose operational restrictions and remediation obligations, including requirements to close pits. In particular, many of these requirements are intended to help preserve water and wildlife resources and regulate those aspects of our operations that could potentially impact surface water, groundwater or wildlife. Failure to comply with these laws, regulations and permits may result in our being subject to litigation, fines or other sanctions, including the revocation of permits and suspension of operations, and could otherwise delay or impede the issuance or renewal of permits. We expect to continue to incur significant capital and other compliance costs related to such requirements.

We could be subject to joint and several strict liability for any environmental contamination at our and our predecessors' currently or formerly owned, leased or operated properties or third-party waste disposal sites. In addition to potentially significant investigation and remediation costs, such matters can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.

These laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. For example, governmental regulators are becoming increasingly focused on air emissions from our industry, including volatile organic compound and methane emissions. This increased scrutiny has led to heightened enforcement of existing regulations as well as the imposition of new air emission measures. With respect to GHG emissions, we are currently required to report annual GHG emissions from certain of our operations, and additional GHG emission related requirements have been implemented or are in various stages of development. Any current or future GHG or other air emission requirements could curtail our operations or otherwise result in operational delays, liabilities and increased compliance costs. In addition, to the

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extent climate change results in more severe weather, our or our customers' operations may be disrupted, which could curtail our exploration and production activity, increase operating costs and reduce product demand.

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

Our hydraulic fracturing operations are subject to laws and regulations that could expose us to increased costs and additional operating restrictions and delays, and adversely affect production.

We rely and expect to continue to rely upon hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. Various federal, state, provincial and local initiatives have been implemented or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing. In particular, the EPA has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of wastewater from certain gas production operations. In April 2012, the EPA issued new air standards that require measures to reduce volatile organic compound emissions at new hydraulically fractured natural gas wells and existing wells that are re-fractured. Certain municipalities and states and Canadian provinces in which we operate, including Texas, Colorado, British Columbia and Alberta, have adopted, or are considering adopting, regulations that have imposed, or could impose, more stringent permitting, transparency, disposal and well construction requirements on hydraulic fracturing operations. For example, several jurisdictions in which we operate require public disclosure of chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations also may regulate, restrict or prohibit the performance of well drilling in general and hydraulic fracturing in particular. Baseline water sampling and studies are a regulatory requirement in Colorado, British Columbia and Alberta. Such laws and regulations may result in increased scrutiny or third-party claims, or otherwise result in operational delays, liabilities and increased costs.

Hydraulic fracturing can require significant quantities of water. In recent years, Texas and northeastern British Columbia have experienced drought conditions. Any diminished access to water for use in hydraulic fracturing in these or other locations in which we operate, whether due to usage restrictions or drought or other weather conditions, could curtail our operations or otherwise result in operational delays or increased costs. Any current or future federal, state, provincial or local hydraulic fracturing requirements applicable to our operations, or diminished access to water for use in hydraulic fracturing, could have a material adverse effect on our business, results of operations and financial condition.

Parties with whom we do business may become unable or unwilling to timely perform their obligations to us.

We enter into contracts and transactions with various third parties, including contractors, suppliers, customers, lenders, joint venture and other partners, and counterparties to hedging arrangements, under which such third parties incur performance or payment obligations to us. Any delay or failure on the part of one or more of such third parties to perform their obligations to us could, depending upon the nature and magnitude of such failure or failures, have a material adverse effect on our business, financial condition and results of operations.

The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state, provincial and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations.

Wells that we decide to drill may not meet our pre-drilling expectations, may not yield oil or natural gas in commercially viable quantities and are susceptible to uncertainties that could materially alter the occurrence, timing or success of drilling.

Our ability to execute our drilling program, including the development of our proved undeveloped reserves, is subject to a number of uncertainties, including the availability of capital, regulatory approvals, commodity prices, costs and drilling results. In addition, the cost and timing of drilling, completing, and operating any well are often uncertain, and new wells may not be productive. We cannot assure you that the analogies we draw from available data from other wells will be applicable to our identified drilling locations. Even if sufficient amounts of

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oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. Because of these uncertainties, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce commercially viable quantities of oil or natural gas from these or any other potential drilling locations. The failure to drill our identified drilling locations on a timely basis or the failure of our wells to yield oil or natural gas in commercially viable quantities could cause a decline in our proved reserves and adversely affect our ability to maintain leases, borrowing capacity, financial condition, results of operations and cash flows.

Many of our properties are in areas that may be impacted by offset wells and our wells may be adversely affected by actions other operators may take when operating wells that they own.

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling additional wells, that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expense and could adversely affect the production and proved reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.

Our Horn River Asset is in the early stages of development.

Our Horn River Asset is at an early stage of development. As such, there is limited information on reservoir quality which may affect the development schedule and well spacing requirements to fully recover the natural gas reserves. Additionally, the infrastructure is still in development, and while sufficient capacity exists today, future infrastructure development is necessary and could lead to delays or unexpected costs associated with getting our production to market.

A significant increase in the differential between the NYMEX price or other benchmark prices and the prices we receive for our production could adversely affect our financial condition.

The prices that we receive for our production often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX, that are used for calculating the fair value of our commodity derivatives. Although there has been a demonstrated and consistent basis spread between NYMEX and where we sell our production (such as at Henry Hub, Houston Ship Channel and AECO), any increase in these differentials, if significant, could adversely affect our financial condition. Furthermore, any long-term dislocation of such differentials could materially affect our results of operations and ability to achieve expected results.

Derivatives regulations adopted under the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, could have an adverse effect on our ability to use derivatives to reduce the effect of commodity price risk, interest rate and other risks associated with our business.

We use commodity derivatives to manage our commodity price risk. In 2010, the U.S. Congress adopted comprehensive financial reform legislation that, among other things, establishes comprehensive federal oversight and regulation of over-the-counter derivatives, termed “swaps” and “security-based swaps” by the Dodd-Frank Act, and many of the entities that participate in the swaps markets. The Dodd-Frank Act required the SEC and the Commodity Futures Trading Commission (the “CFTC”), along with certain other regulators, to promulgate final rules and regulations to implement many of its swap regulatory provisions. The SEC was given regulatory authority over security-based swaps. The CFTC was given regulatory authority over swaps, which includes commodity swaps. While the SEC's rules governing security-based swaps have largely not been finalized, the CFTC has implemented the majority of its rules. As a result, the final form and timing of the implementation of the new swap regulatory regime affecting commodity derivatives is largely in effect, subject to the rules discussed below.

In particular, the Dodd-Frank Act provides the CFTC with authority to adopt position limits for swaps. In 2011, the CFTC adopted a swap position limits rule, however, that rule was vacated by the U.S. District Court for the District of Columbia under a lawsuit brought by the financial services industry organizations. In November

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2013, the CFTC re-proposed position limits rules that, if finalized as proposed, would impose limits on positions in certain physical commodity swaps. While the timing of implementation of final rules on position limits, their applicability to, and impact on, us remains uncertain, there can be no assurance that, when in place, position limit rules will not have a material adverse impact on us by affecting the prices of or market for commodities relevant to our operations and/or by reducing the availability to us of commodity derivatives.

The Dodd-Frank Act, through CFTC swap rules, has imposed a number of other new requirements on swap transactions and subjected swap dealers and major swap participants and their counterparties to significant new regulatory requirements, including mandatory clearing and trade execution of certain standardized interest rate and credit default swaps. This has resulted in increased costs and regulatory oversight for us and our swap counterparties. The full impact of this new regulatory regime on the availability, pricing and terms and conditions of commodity derivatives, remains uncertain, but there can be no assurance that it will not have, or continue to have, certain materially adverse effects on our ability to hedge our exposure to commodity prices.

In addition, under the Dodd-Frank Act, swap dealers and major swap participants will be required to collect initial and variation margin from certain end-users of swaps. The rules implementing these requirements have not been finalized and therefore the timing of their implementation and their applicability to us remains uncertain. Depending on the final rules and definitions ultimately adopted, we may be required to post collateral for some or all of our derivative transactions, which could cause liquidity issues for us by reducing our ability to use our cash or other assets for capital expenditures or other corporate purposes and reduce our ability to execute strategic hedges to reduce commodity price uncertainty and protect cash flows.

If we reduce our use of derivatives as a result of the Dodd-Frank Act, the regulations promulgated under it and the changes to the nature of the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. In addition, the Dodd-Frank Act was intended, in part, to reduce the volatility of commodity prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to natural gas, NGLs and oil. Our revenue could, therefore, be adversely affected if commodity prices were to decrease.

We have lost key personnel and the loss of additional key personnel could adversely affect our operations.

Our operations are dependent on a relatively small group of key management personnel, including our executive officers. There is a risk that the services of all our key personnel may not be available to us in the future and that the existing staff can continue to discharge the required tasks for conducting our business. Because competition for experienced personnel in our industry can be intense, we may be unable to find acceptable replacements with comparable skills and experience and their loss could adversely affect our ability to operate our business.

A small number of existing stockholders exercise significant control over our company, which could limit other stockholders' ability to influence the outcome of stockholder votes.

As of February 28, 2014, members of the Darden family, together with entities controlled by them, beneficially owned approximately 30% of our outstanding common stock. As a result, they are generally able to significantly affect the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our charter or bylaws and the approval of mergers and other significant corporate transactions.

Our amended and restated certificate of incorporation, restated bylaws and stockholder rights plan contain provisions that could discourage an acquisition or change of control without our board of directors' approval.

Our amended and restated certificate of incorporation and restated bylaws contain provisions that could discourage an acquisition or change of control without our board of directors' approval. In this regard:

• our board of directors is authorized to issue preferred stock without stockholder approval;

• our board of directors is classified; and

• advance notice is required for director nominations by stockholders and actions to be taken at annual meetings at the request of stockholders.

In addition, we have amended and extended a stockholder rights plan, which could also impede a merger, consolidation, takeover or other business combination involving us, even if that change of control might be beneficial to stockholders, thus increasing the likelihood that incumbent directors will retain their positions. In

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certain circumstances, the fact that corporate devices are in place that will inhibit or discourage takeover attempts could reduce the market value of our common stock.

If we do not complete the Southwestern Transaction or another sale of our Niobrara Asset, or at all, it would adversely affect our liquidity.

Our ability to complete the Southwestern Transaction is subject to various customary closing conditions, some of which are beyond our control. If the transaction does not close or the purchase agreement is terminated, we may be unable to find another purchaser of our Niobrara Asset on terms acceptable to us, or at all. If we are unable to complete the Southwestern Transaction, or a similar transaction, by the expected closing date of May 2014, or at all, it could trigger significant expenditures to renew or retain our acreage position during 2014. For this and other reasons, if we are unable to dispose of our Niobrara Asset as currently anticipated, we may be required to adjust our activities elsewhere to reflect this higher capital need.

There are inherent limitations in all internal control over financial reporting systems, and misstatements due to error or fraud may occur and not be detected. We have identified material weaknesses in our internal controls that, if not properly corrected, could result in material misstatements in our financial statements.

We have identified material weaknesses in our system of internal control over financial reporting as of December 31, 2013. A material weakness is a deficiency, or combination of deficiencies in internal controls over financial reporting that results in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

We did not maintain operating effectiveness of our controls over deferred income taxes. Consistent with the material weakness identified at December 31, 2012, we continue to have difficulty in the preparation of a timely reconciliation of certain temporary differences, particularly related to the tax basis in property, plant and equipment, from our provision to our tax returns and our tax subledger. We have increased our staffing resources in 2014 and expect to complete a reconciliation of these temporary differences during 2014; however, we may encounter additional difficulties as these reconciliations are completed.

Additionally, we did not maintain operating effectiveness of our controls over accounting for significant, non-recurring transactions, particularly related to the accuracy of inputs within the respective calculations. 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 have redesigned our controls and expect, when executed, these improvements will remediate this material weakness in 2014.

A significant deficiency as of December 31, 2013 relates to the operating effectiveness of our controls for payroll. In response, management enhanced its controls in this area and believes that these enhancements, will remediate the matter going forward.

If we are not able to remedy the control deficiencies in a timely manner, we may be unable to provide holders of our securities with the required financial information in a timely and reliable manner, either of which could subject us to litigation and regulatory enforcement actions.

While we have taken actions designed to address compliance with the requirements of the Sarbanes-Oxley Act of 2002, as amended, and the rules and regulations thereunder, there are inherent limitations in our ability to comply with these requirements. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal control over financial reporting and disclosure controls and procedures will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions or the degree of compliance

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with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties

A detailed description of our significant properties and associated 2013 developments can be found in Item 1 of this Annual Report, which is incorporated herein by reference.

ITEM 3. Legal Proceedings

We are a defendant in lawsuits from time to time in the normal course of business. We are not party to any legal proceedings that, based on facts currently available, management believes will, individually or in the aggregate, have a material adverse effect on our business, operating results, financial condition or cash flows.

ITEM 4. Mine Safety Disclosures

Not applicable.

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PART II

ITEM 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities

Market Information

Our common stock is traded on the New York Stock Exchange under the symbol “KWK.”

The following table sets forth the quarterly high and low in-trading sales prices of our common stock for the periods indicated below.

	HIGH		LOW
2013
Fourth Quarter	$	3.17	$	1.94
Third Quarter	1.99		1.44
Second Quarter	3.17		1.53
First Quarter	3.27		1.62
2012
Fourth Quarter	$	4.96	$	2.62
Third Quarter	5.97		3.28
Second Quarter	5.65		2.93
First Quarter	7.18		4.14

As of February 28, 2014, there were approximately 530 common stockholders of record. Because many of our shares of common stock are held by brokers and other institutions on behalf of stockholders, we are unable to estimate the total number of stockholders represented by these record holders.

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

Performance Graph

The following performance graph compares the cumulative total stockholder return on Quicksilver common stock (KWK) with the Standard & Poor’s 500 Stock Index (the “S&P 500 Index”) and the Standard & Poor’s 400 Oil and Gas Index (the “S&P 400 Oil & Gas Index”) for the period from December 31, 2008 to December 31, 2013, assuming an initial investment of $100 and the reinvestment of all dividends, if any.

Comparison of Cumulative Five Year Total Return

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Issuer Purchases of Equity Securities

The following table summarizes our repurchases of Quicksilver common stock during the quarter ended December 31, 2013.

Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan (2)	Maximum Number of Shares that May Yet Be Purchased Under the Plan (2)
October 2013	—	$	—	—	—
November 2013	4,931	$	2.92	—	—
December 2013	148,058	$	2.97	—	—
Total	152,989	$	2.97	—	—

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

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

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ITEM 6. Selected Financial Data

The following table sets forth, as of the dates and for the periods indicated, our selected financial information and is derived from our audited consolidated financial statements for such periods. The information should be read in conjunction with “Management's Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes thereto contained in this Annual Report. The following information is not necessarily indicative of our future results:

	Years Ended December 31,
	2013 (1)			2012 (2)			2011 (3)		2010 (4)		2009 (5)
	(In thousands, except for per share data)
Operating Results Information
Total revenue	$	561,562		$	709,038		$	943,623	$	928,331	$	832,735
Operating income (loss)	464,644			(2,465,761		)	122,604		804,134		(613,873		)
Income (loss) before income taxes	176,168			(2,648,176		)	147,909		713,828		(836,856		)
Net income (loss)	161,618			(2,352,606		)	90,046		455,290		(545,239		)
Net income (loss) attributable to Quicksilver	161,618			(2,352,606		)	90,046		445,566		(557,473		)
Diluted earnings (loss) per common share	$	0.92		$	(13.83	)	$	0.52	$	2.50	$	(3.30	)
Dividends paid per share	—			—			—		—		—
Financial Condition Information
Property, plant and equipment - net	$	860,805		$	1,029,058		$	3,460,519	$	3,063,245	$	2,542,845
Midstream assets held for sale - net	—			—			—		27,178		548,508
Total assets	1,369,726			1,381,788			3,995,462		3,507,734		3,612,882
Long-term debt	1,988,946			2,063,206			1,903,431		1,746,716		2,427,523
All other long-term obligations	251,953			283,588			495,939		248,762		121,877
Total equity	(1,005,970		)	(1,132,797		)	1,261,919		1,069,905		696,822
Cash Flow Information
Cash provided by (used in) operating activities	$	(51,700	)	$	227,727		$	253,053	$	397,720	$	612,240
Capital expenditures	101,288			485,479			690,607		695,114		693,838

⁽¹⁾  Operating income for 2013 includes a gain of $339.3 million from the Tokyo Gas Transaction. Operating income also includes a charge of $12.8 million in connection with the termination of the PEA with NGTL.

⁽²⁾  Operating loss for 2012 includes charges for impairment of $2.6 billion for U.S. and Canadian oil and gas properties and certain midstream assets in Colorado. Net loss includes a tax valuation allowance of $595.3 million.

⁽³⁾  Operating income for 2011 includes gains of $217.9 million from the sale of BBEP Units. Operating income also includes charges for impairment of $58.0 million and $49.1 million for our midstream assets in Texas, and Canadian oil and gas properties, respectively.

⁽⁴⁾  Operating income for 2010 includes gains of $494.0 million and $57.6 million from the sales of KGS and BBEP Units, respectively. Operating income also includes charges for impairment of $28.6 million and $19.4 million for our HCDS and Canadian oil and gas properties, respectively.

⁽⁵⁾  Operating loss for 2009 includes charges of $786.9 million and $192.7 million for impairments associated with our U.S. and Canadian oil and gas properties, respectively. Net loss also includes $75.4 million of income attributable to our proportionate ownership of BBEP and a charge of $102.1 million for impairment of that investment.

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ITEM 7. 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 Annual Report. 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:

• Overview – a general description of our business; the value drivers of our business; and key indicators

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

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

• Financial Risk Management – information about debt financing and financial risk management

• Results of Operations – an analysis of our consolidated results of operations for the three years 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

• Critical Accounting Estimates – a discussion of critical accounting estimates that represent choices between acceptable alternatives and/or require management judgments and assumptions.

OVERVIEW

We are an independent oil and gas company engaged in the acquisition, exploration, development, and production of onshore oil and natural gas based in Fort Worth, Texas. We focus primarily on unconventional reservoirs where hydrocarbons may be found in challenging geological conditions such as fractured shales and coalbeds. We generate revenue, income and cash flows by producing and selling natural gas, NGLs and oil. We conduct acquisition, exploration, development, and production activities to replace the reserves that we produce. Item 1 of this Annual Report contains additional information about our business and properties, including the capital and partners needed to develop them.

At December 31, 2013, 82% and 18% of our proved reserves were natural gas and NGLs, respectively. Consistent with one of our business strategies, we continue to develop our unconventional resources by applying our expertise to our development projects in our Barnett Shale Asset, Horseshoe Canyon Asset and Horn River Asset, which had 80%, 15% and 5%, respectively, of our proved reserves at December 31, 2013. Our acreage in our Horn River Asset provides us the most immediate and most significant additional opportunity for further application of our unconventional resources expertise.

A key focus for 2014 is completing a transaction involving our Horn River Asset that will be an important catalyst to our accessing the capital markets to improve our capital structure, although we may be unable to complete a transaction in 2014. In addition, we also expect to focus on three other long-term value drivers:

•reserve growth;

•production growth; and

•maximizing our operating margin.

Our reserve growth depends on our ability to fund a drilling program. It also relies on our ability to apply our technical and operational expertise to explore and develop unconventional reservoirs. We strive to increase reserves and production through aggressive management of our operations and through relatively low-risk developmental drilling. All of our development and exploratory programs are aimed at providing us with opportunities to develop unconventional reservoirs.

We believe the acreage we hold in our core operating areas is well suited for additional development. We perform workover and infrastructure projects to reduce ongoing operating costs and enhance current and future

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production rates. We regularly review the properties we operate to determine if steps can be taken to efficiently increase reserves and production.

In evaluating the results of our efforts, we consider the capital efficiency of our drilling program and also measure the following key indicators, whose recent results are shown below:

	Years Ended December 31,
	2013 (2)			2012 (3)			2011
Organic reserve growth (1)	22		%	(42		)%	1		%
Production volume (Bcfe)	108.0			131.8			150.6
Cash flow from operating activities (in millions)	$	(51.7	)	$	227.7		$	253.1
Diluted earnings (loss) per share	$	0.92		$	(13.83	)	$	0.52

⁽¹⁾  This ratio is calculated by subtracting beginning of the year proved reserves from adjusted end of the year proved reserves and dividing by beginning of the year proved reserves. Adjusted end of the year reserves are calculated by adding back divested reserves and production and deducting acquired reserves from end of the year reserves.

⁽²⁾  Organic reserve adds in 2013 were 329 Bcfe, representing 22% growth from 2012 due to the following factors: 1) an improved SEC benchmark natural gas price and lower lease operating expenses offset negative revisions related to increased well spacing in our Alliance field, resulting in a net increase of 268 Bcfe in our proved developed producing and proved undeveloped reserves; and 2) the 2013 capital program in our Barnett Shale Asset and Horseshoe Canyon Asset targeted non-PUD locations, resulting in addition to proved developed reserves of 61 Bcfe. Though the benchmark natural gas price improved in 2013 compared to 2012, our capital budget projection over the next five years is constrained by our operating cash flow and our liquidity, and thus, we were unable to materially increase the number of overall PUD locations in 2013 compared to 2012. However, we were able to recognize 32 PUD locations in our Horseshoe Canyon Asset in 2013 compared to no locations recognized in 2012; Barnett PUD locations total 55 in 2013, which is a decrease of 5 compared to 2012. Our proved developed to total proved ratio in 2013 is 88%, which is flat with 2012.

⁽³⁾  During 2012, we recognized substantial negative reserve revisions due to lower average SEC commodity prices compared to prior periods. As such, we recognized a 1.2 Tcfe negative revision for all of 2012, which represents a 44% decline compared to 2011 year-end reserves. Organic reserve adds in 2012 were approximately 49 Bcfe, which represents less than 2% growth from 2011. The modest level of reserve additions results from two main factors: 1) approximately 85% of the 22 gross wells drilled in the Barnett Shale in 2012 were PUD locations at year-end 2011. Therefore, no new reserves were recognized for these PUD locations after bringing them on line; and 2) we did not recognize significant additional PUD locations at year-end 2012 due the influence of commodity prices on the five-year development profile. Customarily, we would recognize additional PUD locations to offset drilled locations during the year provided the new PUDs meet the SEC's standards, including the five-year limitation.

The organic reserve growth ratio is a supplemental measure that we use to assess how successfully we are implementing our business strategy of pursuing organic growth. We believe that total reserve growth is a multi-year key value driver of which organic reserve growth is a component. Reserve estimation has inherent limitations which are detailed in our Risk Factors in Item 1A and include assumptions regarding future production rates, timing and amount of future development expenditures, results of geological, geophysical, production and engineering data and economic factors. Any inaccuracies in these assumptions could materially affect the estimated quantities of proved reserves. Item 8 “Supplemental Oil and Gas Information” contains additional information about our reserves.

2013 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 $90 million. The transaction is expected to close in May 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.

37

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 million. We recognized a gain of $339 million before consideration of income taxes as a result of this transaction.

In August 2013, we divested our Southern Alberta Basin Asset to Synergy with an effective date of January 1, 2013. The purchase price was $46 million, which after purchase price adjustments resulted in a final purchase price of $42 million. Under the full cost method of accounting, our U.S. exploration and production assets are considered a single asset. The Synergy Transaction did not represent a significant disposal of reserves, therefore our U.S. oil and gas properties were reduced by these proceeds and we did not recognize a gain.

In October and November 2013, we executed two separate agreements involving our West Texas Asset, the larger of which is a joint venture with Eni whereby we will jointly evaluate, explore and develop approximately 52,500 gross acres currently held by us in Pecos County, Texas. Under the terms of the agreement, Eni will pay up to $52 million in three phases to earn a 50% interest in our acreage. Upon completion of the three phases, we will participate equally in all future revenue, operating costs and capital expenditures with Eni. We also executed a farm-out agreement with another partner covering 7,500 gross acres also located in Pecos County.

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 $0.13 per Mcf until at least 2016. Additionally, as a result of this amendment, KKR is no longer required to fund the capital for construction of a proposed gas treatment facility, but at its option may provide funding for any facility to be constructed by the Partnership, including the proposed gas treatment facility. The amendment provides us with additional time and flexibility in completing a joint venture transaction involving our Horn River Asset and immediate cash flow relief through the reduced gathering fee paid to Fortune Creek.

In the second quarter of 2013, we refinanced a portion of our debt to extend maturities and reduce the weighted average interest costs on outstanding debt. We also amended our Combined Credit Agreements primarily to loosen the financial covenants through the second quarter of 2016 and to permit the incurrence of up to $825 million of second lien debt. Specific refinancing activities and changes to the Combined Credit Agreements are outlined in Note 11 to our consolidated financial statements found in Item 8 of this Annual Report.

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

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2014 CAPITAL PROGRAM

We expect our 2014 capital program to be spent in the following areas:

	(In millions)
Barnett Shale	$	77
West Texas	9
Other U.S.	5
Total U.S.	91
Horseshoe Canyon	22
Total Canada	22
Corporate (1)	23
Total Company	$	136

⁽¹⁾ Includes capitalized interest expense and capitalized internal costs.

We expect our 2014 production volume to be between 245 and 255 MMcfe per day.

FINANCIAL RISK MANAGEMENT

We have established internal control policies and procedures for managing risk within our organization. The possibility of decreasing prices received for our production is one of the many 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 these derivatives but, in doing so, have also limited our ability to benefit from favorable price movements. Our commodity price strategy enhances our ability to execute our development and exploration programs, meet debt service requirements and pursue acquisition opportunities even in periods of price volatility or depression. Item 7A of this Annual Report contains details of our commodity price and interest rate risk management.

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RESULTS OF OPERATIONS

“Other U.S.” refers to the combined amounts for our operations in our Niobrara Asset, West Texas Asset and Southern Alberta Basin Asset.

Revenue

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

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

	Natural Gas						NGL								Oil						Total
	2013		2012		2011		2013			2012		2011			2013		2012		2011		2013		2012		2011
	(In millions)
Barnett Shale	$	180.4	$	200.9	$	376.5	$	80.5		$	137.5	$	216.6		$	6.6	$	10.9	$	11.8	$	267.5	$	349.3	$	604.9
Other U.S.	0.1		0.6		1.1		0.3			0.5		0.6			9.0		13.7		12.3		9.4		14.8		14.0
Hedging	55.1		151.3		100.2		—			23.5		(46.1		)	—		—		—		55.1		174.8		54.1
U.S.	235.6		352.8		477.8		80.8			161.5		171.1			15.6		24.6		24.1		332.0		538.9		673.0
Horseshoe Canyon	56.6		48.2		79.2		0.2			0.1		0.1			—		—		—		56.8		48.3		79.3
Horn River	61.6		23.9		17.4		—			—		—			—		—		—		61.6		23.9		17.4
Hedging	13.1		19.8		30.8		—			—		—			—		—		—		13.1		19.8		30.8
Canada	131.3		91.9		127.4		0.2			0.1		0.1			—		—		—		131.5		92.0		127.5
Consolidated production revenue	$	366.9	$	444.7	$	605.2	$	81.0		$	161.6	$	171.2		$	15.6	$	24.6	$	24.1	$	463.5	$	630.9	$	800.5
U.S. realized cash derivative gains (losses)	$	11.7	$	23.0	$	—	$	(1.4	)	$	—	$	—		$	—	$	—	$	—	$	10.3	$	23.0	$	—
Canada realized cash derivative gains	10.9		19.8		—		—			—		—			—		—		—		10.9		19.8		—
Consolidated realized cash derivative gains (losses)	22.6		42.8		—		(1.4		)	—		—			—		—		—		21.2		42.8		—
Consolidated production revenue and realized cash derivative gains (1)	$	389.5	$	487.5	$	605.2	$	79.6		$	161.6	$	171.2		$	15.6	$	24.6	$	24.1	$	484.7	$	673.7	$	800.5

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

Average Daily Production Volume by Operating Area:

	Natural Gas			NGL			Oil			Equivalent Total
	2013	2012	2011	2013	2012	2011	2013	2012	2011	2013	2012	2011
	(MMcfd)			(Bbld)			(Bbld)			(MMcfed)
Barnett Shale	139.8	206.2	261.8	7,727	11,090	12,117	194	333	352	187.3	274.8	336.6
Other U.S.	0.1	0.6	0.8	15	26	24	281	451	396	1.9	3.5	3.3
U.S.	139.9	206.8	262.6	7,742	11,116	12,141	475	784	748	189.2	278.3	339.9
Horseshoe Canyon	49.7	54.6	58.4	5	5	6	—	—	—	49.7	54.6	58.5
Horn River	56.9	27.1	14.1	—	—	—	—	—	—	56.9	27.1	14.1
Canada	106.6	81.7	72.5	5	5	6	—	—	—	106.6	81.7	72.6
Consolidated	246.5	288.5	335.1	7,747	11,121	12,147	475	784	748	295.8	360.0	412.5

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Average Realized Price by Operating Area:

	Natural Gas						NGL								Oil						Equivalent Total
	2013		2012		2011		2013			2012		2011			2013		2012		2011		2013		2012		2011
	(per Mcf)						(per Bbl)								(per Bbl)						(per Mcfe)
Barnett Shale	$	3.54	$	2.66	$	3.94	$	28.53		$	33.87	$	48.98		$	92.48	$	89.85	$	91.83	$	3.92	$	3.47	$	4.92
Other U.S.	4.68		2.59		4.06		51.00			50.83		72.92			87.50		83.13		84.87		13.06		11.57		11.65
Hedging	1.08		2.00		1.05		—			5.77		(10.41		)	—		—		—		0.80		1.72		0.44
U.S.	$	4.62	$	4.66	$	4.99	$	28.57		$	39.67	$	38.61		$	89.53	$	85.98	$	88.15	$	4.81	$	5.29	$	5.42
Horseshoe Canyon	$	3.12	$	2.41	$	3.71	$	66.15		$	61.12	$	64.64		$	—	$	—	$	—	$	3.12	$	2.41	$	3.72
Horn River	2.96		2.40		3.39		—			—		—			—		—		—		2.97		2.41		3.39
Hedging	0.34		0.66		1.16		—			—		—			—		—		—		0.34		0.66		1.16
Canada	$	3.37	$	3.07	$	4.81	$	66.15		$	67.91	$	64.64		$	—	$	—	$	—	$	3.38	$	3.07	$	4.82
Consolidated production revenue	$	4.08	$	4.21	$	4.95	$	28.60		$	39.69	$	38.63		$	89.53	$	85.98	$	88.15	$	4.29	$	4.79	$	5.32
U.S. realized cash derivative gains (losses)	$	0.23	$	0.30	$	—	$	(0.48	)	$	—	$	—		$	—	$	—	$	—	$	0.15	$	0.23	$	—
Canada realized cash derivative gains	0.28		0.66		—		—			—		—			—		—		—		0.28		0.66		—
Consolidated realized cash derivative gains (losses)	0.25		0.41		—		(0.48		)	—		—			—		—		—		0.20		0.32		—
Consolidated production revenue and realized cash derivative gains	$	4.33	$	4.62	$	4.95	$	28.12		$	39.69	$	38.63		$	89.53	$	85.98	$	88.15	$	4.49	$	5.11	$	5.32

The following table summarizes the changes in our natural gas, NGL and oil production revenue and realized cash derivative gains (losses):

	Natural Gas			NGL			Oil			Total
	(In thousands)
Consolidated production revenue for the 2011 period	$	605,205		$	171,265		$	24,073		$	800,543
Volume variances	(64,614		)	(17,820		)	1,235			(81,199		)
Hedge revenue variances	40,171			69,602			—			109,773
Realized cash derivative variance (1)	42,798			—			—			42,798
Price variances	(136,048		)	(61,505		)	(617		)	(198,170		)
Consolidated production revenue and realized cash derivative gains for the 2012 period	$	487,512		$	161,542		$	24,691		$	673,745
Volume variances	(40,504		)	(42,146		)	(9,782		)	(92,432		)
Hedge revenue variances	(102,934		)	(23,454		)	—			(126,388		)
Realized cash derivative variance (1)	(20,208		)	(1,362		)	—			(21,570		)
Price variances	65,804			(15,052		)	612			51,364
Consolidated production revenue and realized cash derivative gains for the 2013 period	$	389,670		$	79,528		$	15,521		$	484,719

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

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Our natural gas revenue without the effects of derivatives decreased for 2013 from 2012 due to lower volumes produced partially offset by an increase in our realized price. Our hedge revenue and realized cash derivative gains (losses) decreased for 2013 compared to 2012 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 from derivative instruments. Consolidated production revenue and realized cash derivative gains from NGL revenue for 2013 decreased from 2012 due to lower volumes produced, decreased realized prices and a decrease in derivative hedge revenue and realized cash. Our oil revenue decreased for 2013 compared to 2012 primarily due to the Synergy Transaction. The decrease in natural gas and NGL volumes is primarily due to the Tokyo Gas Transaction and to a lesser extent the natural decline of aging wells and is partially offset by an increase in volumes in our Horn River Asset as we increased production as wells were completed in the second half of 2012.

Natural gas and NGL revenue for 2012 decreased from 2011 as a result of a decrease in both realized prices without hedging gains and production. The decrease in natural gas volume from our Barnett Shale Asset was primarily due to production declines resulting from the aging of existing wells and a reduction of our capital program related to our Barnett Shale Asset. On a lesser basis, natural gas production volumes were also impacted by temporary shut-ins in support of new development activity.

Our production revenue for 2013 and 2012 was higher by $68.2 million and $194.6 million, respectively, because of our hedging activities.

We expect our 2014 production volumes to decline in our Horn River Asset offset by an increase in our Barnett Shale Asset. These volumetric declines and increases will impact our unit costs.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas

	Years Ended December 31,
	2013		2012		2011
			(In thousands)
Sales of purchased natural gas:
Purchases from Eni	$	62,103	$	58,881	$	71,921
Purchases from others	2,810		3,524		14,724
Total	64,913		62,405		86,645
Costs of purchased natural gas sold:
Purchases from Eni	62,126		58,915		71,746
Purchases from others	2,714		3,126		13,652
Total	64,840		62,041		85,398
Net sales and purchases of natural gas	$	73	$	364	$	1,247

We purchase Eni’s interest in natural gas production in our Alliance Asset and then sell the natural gas to others. The decrease from 2012 compared to 2011 is due to decreased production primarily as a result of fewer new wells brought online in 2012 and lower realized prices.

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Derivative Gains (Losses), net

The following table summarizes our net derivative gains and losses:

	Years Ended December 31,
	2013			2012			2011
				(In thousands)
Unrealized mark-to-market changes in fair value of natural gas derivative gains (losses) (1)	$	10,299		$	(17,880	)	$	45,852
Realized cash settlements of natural gas derivative gains	22,590			42,798			—
Non-cash loss in fair value from restructured natural gas derivatives	—			(14,755		)	—
Unrealized mark-to-market changes in fair value of NGL derivative losses (1)	(1,599		)	—			—
Realized cash settlements of NGL derivative losses	(1,362		)	—			—
Gain from hedge ineffectiveness	—			1,281			5,928
Derivative gains, net	29,928			11,444			51,780

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

In 2012 we began to account for the fair value changes of certain natural gas derivatives in the income statement as reflected in the above table. In 2012 we terminated a number of our ten-year derivative instruments in exchange for derivative instruments with shorter durations at above market terms. The decrease in the fair value between the terminated ten-year instrument and the new shorter term instrument was recognized as a non-cash loss in fair value from restructured derivatives. Unrealized mark-to-market gains for 2011 is due to our recognition of $48.9 million for unrealized gains on commodity derivatives that were not designated as hedges at inception. These instruments were subsequently designated as hedges in August 2011 with unrealized gains and losses from that date forward recognized as a component of AOCI. These unrealized gains were partially offset by a decrease in fair value of the related hedge assets due to credit risk of our counterparties as of December 31, 2011.

Other Revenue

	Years Ended December 31,
	2013		2012		2011
			(In thousands)
Midstream revenue from third parties:
Canada	$	2,388	$	2,523	$	3,139
Texas	842		1,687		1,018
Total midstream revenue	3,230		4,210		4,157
Other	—		32		498
Total	$	3,230	$	4,242	$	4,655

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Operating Expense

Lease Operating Expense

	Years Ended December 31,
	2013				2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe				Per Mcfe
Barnett Shale
Expense	$	43,270	$	0.63	$	53,509	$	0.53	$	62,158	$	0.50
Equity compensation expense	842		0.01		997		0.01		904		0.01
	$	44,112	$	0.64	$	54,506	$	0.54	$	63,062	$	0.51
Other U.S.
Expense	$	4,889	$	7.22	$	8,317	$	6.49	$	6,327	$	5.24
Equity compensation expense	323		0.48		166		0.13		224		0.19
	$	5,212	$	7.70	$	8,483	$	6.62	$	6,551	$	5.43
Total U.S.
Expense	$	48,159	$	0.70	$	61,826	$	0.61	$	68,485	$	0.55
Equity compensation expense	1,165		0.02		1,163		0.01		1,128		0.01
	$	49,324	$	0.72	$	62,989	$	0.62	$	69,613	$	0.56
Horseshoe Canyon
Expense	$	28,504	$	1.57	$	29,107	$	1.46	$	29,853	$	1.40
Equity compensation expense	290		0.02		375		0.02		461		0.02
	$	28,794	$	1.59	$	29,482	$	1.48	$	30,314	$	1.42
Horn River
Expense	$	4,147	$	0.20	$	2,862	$	0.29	$	2,947	$	0.57
Equity compensation expense	—		—		—		—		—		—
	$	4,147	$	0.20	$	2,862	$	0.29	$	2,947	$	0.57
Total Canada
Expense	$	32,651	$	0.84	$	31,969	$	1.07	$	32,800	$	1.24
Equity compensation expense	290		0.01		375		0.01		461		0.02
	$	32,941	$	0.85	$	32,344	$	1.08	$	33,261	$	1.26
Total Company
Expense	$	80,810	$	0.75	$	93,795	$	0.71	$	101,285	$	0.67
Equity compensation expense	1,455		0.01		1,538		0.01		1,589		0.01
	$	82,265	$	0.76	$	95,333	$	0.72	$	102,874	$	0.68

Lease operating expense for 2013 in the Barnett Shale decreased in total primarily due to the Tokyo Gas Transaction, partially offset by a non-cash inventory impairment in 2013 of $2.4 million. On a unit basis, the Barnett Shale lease operating expense increased primarily due to fixed lease operating charges being distributed over lower net volumes due to well decline curves compared to 2012. In Canada, the increase in lease operating expense in the Horn River compared to 2012 is primarily due to increased volumes, which also lowered the per unit cost as fixed lease operating costs were distributed over these increased volumes. The increase on a unit basis in Horseshoe Canyon is primarily due to field office personnel expenses.

Lease operating expense for 2012 on a gross basis in the U.S. decreased compared to 2011 primarily due to the Barnett Shale Asset experiencing lower gas lift costs, workover expenses and saltwater disposal costs compared to 2011 through continued cost containment initiatives. On a unit basis the Barnett Shale Asset lease operating expense increased due to production decreases during the year. Other U.S. lease operating costs were impacted on a gross and unit basis by increased production and costs for our Niobrara Asset. In Canada, lease

44

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

Gathering, Processing and Transportation Expense

	Years Ended December 31,
	2013				2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe				Per Mcfe
Barnett Shale	$	104,462	$	1.53	$	141,269	$	1.40	$	172,128	$	1.40
Other U.S.	9		0.01		13		0.01		70		0.05
Total U.S.	$	104,471	$	1.51	$	141,282	$	1.39	$	172,198	$	1.39
Horseshoe Canyon	3,274		0.18		3,547		0.18		4,157		0.19
Horn River	40,824		1.96		21,487		2.16		14,205		2.77
Total Canada	44,098		1.13		25,034		0.84		18,362		0.69
Total	$	148,569	$	1.38	$	166,316	$	1.26	$	190,560	$	1.27

U.S. GPT decreased in total for 2013 compared to 2012 primarily due to lower production volume in our Barnett Shale Asset, with the Tokyo Gas Transaction contributing to this decline, partially offset by an increase of $2.5 million following a customary audit of expenses paid by a joint venture partner. On a unit basis, 2013 U.S. GPT was higher primarily following the customary audit, higher unused capacity from our natural gas transportation in 2013 compared to 2012 and higher transportation fuel charges in 2013 as the price of natural gas increased. Canadian GPT increased in total for 2013 primarily as a result of increased volumes in our Horn River Asset during 2013 compared to 2012. On a unit basis, the decrease in our Horn River Asset is primarily due to fixed costs under our firm agreements with third parties being allocated over the increased volumes. Canadian GPT includes unused firm capacity of $7.4 million, $6.7 million and $4.6 million for 2013, 2012 and 2011, respectively.

U.S. GPT decreased in total for 2012 compared to 2011 primarily due to lower production volume from the Barnett Shale Asset. Canadian GPT increased both in total dollars and on unit basis primarily as a result of fixed costs under our firm agreements with third parties in our Horn River Asset.

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Production and Ad Valorem Taxes

	Years Ended December 31,
	2013					2012				2011
	(In thousands, except per unit amounts)
				Per				Per				Per
Production taxes				Mcfe				Mcfe				Mcfe
Barnett Shale	$	3,620		$	0.05	$	4,982	$	0.05	$	7,886	$	0.06
Other U.S.	655			0.97		857		0.67		1,097		0.91
Total U.S.	4,275			0.06		5,839		0.06		8,983		0.07
Horseshoe Canyon	(5		)	—		167		0.01		231		0.01
Horn River	—			—		—		—		—		—
Total Canada	(5		)	—		167		0.01		231		0.01
Total production taxes	4,270			0.04		6,006		0.05		9,214		0.06
Ad valorem taxes
Barnett Shale	$	8,786		$	0.13	$	15,963	$	0.16	$	16,875	$	0.14
Other U.S.	569			0.84		470		0.37		220		0.18
Total U.S.	9,355			0.14		16,433		0.16		17,095		0.14
Horseshoe Canyon	2,813			0.15		2,696		0.13		2,850		0.13
Horn River	628			0.03		260		0.03		67		0.01
Total Canada	3,441			0.09		2,956		0.10		2,917		0.11
Total ad valorem taxes	12,796			0.12		19,389		0.15		20,012		0.13
Total	$	17,066		$	0.16	$	25,395	$	0.19	$	29,226	$	0.19

Production taxes in the U.S. decreased in 2013 compared to 2012 and in 2012 compared to 2011 primarily as a result of decreased volumes year over year. The decrease on a unit basis from 2011 to 2012 is a result of decreased prices.

Ad valorem taxes decreased in our Barnett Shale Asset in 2013 primarily due to the Tokyo Gas Transaction and to a lesser extent a decrease in assessed value as wells mature.

Depletion, Depreciation and Accretion

	Years Ended December 31,
	2013				2012				2011
	(In thousands, except per unit amounts)
			Per				Per				Per
Depletion			Mcfe				Mcfe				Mcfe
U.S.	$	34,995	$	0.51	$	116,005	$	1.14	$	164,493	$	1.33
Canada	5,362		0.14		24,897		0.83		38,228		1.44
Total depletion	40,357		0.37		140,902		1.07		202,721		1.35
Depreciation of other fixed assets:
U.S.	$	7,549	$	0.11	$	8,913	$	0.09	$	12,931	$	0.10
Canada	9,597		0.25		9,687		0.32		7,415		0.28
Total depreciation	17,146		0.16		18,600		0.14		20,346		0.14
Accretion	5,109		0.05		4,122		0.03		2,696		0.02
Total	$	62,612	$	0.58	$	163,624	$	1.24	$	225,763	$	1.50

U.S. depletion for 2013, when compared to 2012, reflects a decrease in production and a decrease in the current year depletion rate due to impairments recognized in 2012. Canadian depletion decreased for 2013, when

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compared to 2012, due to a decrease in the current year depletion rate as a result of impairment recognized in 2012 partially offset by an increase in production. We expect that our U.S. and Canadian depletion rates for 2014 will be approximately $0.50 and $0.22 per Mcfe, respectively.

U.S. depletion expense for 2012 decreased from 2011 as production decreased in addition to a decreased depletion rate. Canadian depletion expense decreased due to a depletion rate decrease partially offset by increased production. Both our U.S. and Canadian 2012 depletion rates were impacted by impairment charges recognized during 2012.

Depreciation in the U.S. decreased in 2013 compared to 2012 as a portion of our compressors were sold as part of the Tokyo Gas Transaction.

The decrease in 2012 U.S. depreciation expense as compared to 2011 is the result of midstream impairments from 2011. The Canadian depreciation expense increased in 2012 compared to 2011 as a result of additions of other fixed assets in support of our increased activity in the Horn River Asset.

Impairment Expense

As required under GAAP, we perform quarterly ceiling tests to assess impairment of our oil and gas properties. We also assess our fixed assets reported outside the full-cost pool when circumstances indicate impairment may have occurred. Information detailing the calculation of any impairment is more fully described in our “Critical Accounting Estimates” found below and in Note 8 to the consolidated financial statements in Item 8 of this Annual Report.

In 2013, we recognized a non-cash impairment of $1.8 million for impairment of surface land in our Barnett Shale Asset and $0.1 million related to midstream assets in our West Texas Asset.

In 2012, we recognized non-cash charges of $2.2 billion and $465.9 million for our U.S. and Canadian oil and gas properties, respectively, as a result of our quarterly ceiling tests. The natural gas and natural gas liquids pricing used in our quarterly ceiling tests declined throughout the year resulting in impairment charges being recognized in each quarter. Additionally, effective December 31, 2012, we no longer accounted for derivatives as hedges and therefore our year-end ceiling test did not include this benefit. In performing our quarterly ceiling tests, we utilize the average first of month prices for the preceding 12 months.

We recognized impairment expense in 2012 on other property and equipment of $7.9 million, including $7.3 million on pipelines and processing facilities located in Colorado and Texas as a result of reduced utilization and lower reserves. We also impaired general properties $0.6 million related to reduced utilization of a compressed natural gas station in Texas.

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

In 2011, we recognized a $44.7 million impairment for certain midstream assets in Texas that we retained after the sale of KGS. The primary factors for the impairment were our inability to attract third-party customers to utilize the pipe and a decrease in reserves from our assets that utilize the laterals. During 2011, we discontinued our efforts to actively market the HCDS assets and recognized additional impairment of HCDS. We conducted an impairment analysis of the HCDS and recorded $13.3 million during 2011 to reduce the carrying value to estimated fair value.

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General and Administrative Expense

	Years Ended December 31,
	2013				2012				2011
	(In thousands, except per unit amounts)
			Per Mcfe				Per Mcfe				Per Mcfe
Expense	$	29,876	$	0.28	$	40,306	$	0.31	$	45,616	$	0.30
Audit and accounting fees	2,301		0.02		6,179		0.05		1,216		0.01
Strategic transactions	6,885		0.06		8,503		0.06		4,978		0.03
Litigation settlement	—		—		—		—		8,500		0.06
Equity compensation	16,244		0.15		20,709		0.16		19,272		0.13
Total	$	55,306	$	0.51	$	75,697	$	0.58	$	79,582	$	0.53

General and administrative expense for 2013 decreased compared to 2012 primarily due to reduced headcount during 2013, which also decreased equity compensation and salary expense.

General and administrative expense for 2012 was $3.9 million lower than 2011 due to a decrease in litigation settlement expense and strategic transaction costs during the year. These decreases were partially offset by an increase in our audit fees incurred related to our 2011 audit and an increase in our equity compensation during the year due to accelerated stock compensation expense in connection with a previously announced executive retirement. In 2012, we recognized expense of $7.2 million related to previously deferred filing fees for our Barnett Shale Asset master limited partnership since the transaction had been dormant since June 2012.

General and administrative costs for 2011 included $8.5 million for litigation settlement and $5.0 million for legal, accounting and professional fees incurred in connection with the evaluation of possible strategic transactions.

Related Party Transactions

We have related party transactions which are outlined in Note 22 to our consolidated financial statements found in Item 8 of this Annual Report

Tokyo Gas Transaction Gain

In April 2013, we recognized a $339.3 million gain upon closing of the Tokyo Gas Transaction. Further information regarding the transaction can be found in Note 3 to our consolidated financial statements included in Item 8 of this Annual Report.

Crestwood Earn-Out

In February 2012, we collected $41 million of earn-out payments from Crestwood.

Income from Earnings of BBEP

We recorded our portion of BBEP’s earnings during the quarter in which its financial statements became publicly available. As a result, our 2011 annual results of operations included BBEP’s earnings for the 12 months ended September 30, 2011. As of December 31, 2011, we no longer owned any BBEP Units.

We recognized an $8.4 million loss for equity earnings from our investment in BBEP based upon its reported earnings for the 12-month period ended September 30, 2011. During the time we owned BBEP Units, BBEP experienced significant volatility in its net earnings primarily due to changes in the value of its derivative instruments for which it did not employ hedge accounting.

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Other Income (Expense)

In 2013, we recognized an expense of $12.8 million in connection with the termination of the PEA with NGTL. Further information regarding the transaction can be found in Note 14 to our consolidated financial statements included in Item 8 of this Annual Report. Additionally, we incurred a $3.3 million non-cash expense to settle litigation in 2013 and the Canadian foreign currency exchange rate change resulted in a loss of $2.4 million.

We recognized gains of $217.9 million in 2011 from the sale of 15.7 million BBEP Units.

Fortune Creek Accretion

In December 2011, we and KKR formed a midstream partnership to construct and operate natural gas midstream assets to support producer customers in British Columbia. In connection with the partnership formation, KKR contributed $125 million cash in exchange for a 50% interest in Fortune Creek. KKR’s contribution is shown as Partnership liability in the condensed consolidated balance sheet, and we recognize accretion expense to reflect the rate of return earned by KKR via its investment. By virtue of the March 2014 amendment with KKR, the additional contribution that we made to Fortune Creek will cause a reduction in estimated future accretion expense for 2014 of approximately $3 million to $4 million from 2013.

Interest Expense

	Years Ended December 31,
	2013			2012			2011
				(In thousands)
Interest costs on debt outstanding	$	165,381		$	172,502		$	172,696
Add:
Fees paid on letters of credit outstanding	239			118			1,674
Cash premium on early debt extinguishment	67,010			—			2,560
Non-cash interest (1)	26,920			9,854			16,510
Total interest cost incurred	259,550			182,474			193,440
Less:
Interest capitalized	(7,703		)	(18,423		)	(7,416		)
Interest expense	$	251,847		$	164,051		$	186,024

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

Interest costs incurred for 2013 were higher when compared to 2012 primarily because of the refinancing of our debt securities in June 2013, which is more fully discussed in Note 11 to our consolidated financial statements included in Item 8 of this Annual Report, and lower capitalized interest costs.

Interest costs on debt outstanding for 2012 were flat compared to 2011. 2012 non-cash interest decreased as a result of lower deferred financing costs compared to 2011. Interest capitalized in 2012 increased compared to 2011 as unevaluated property balances increased primarily in our Niobrara Asset and West Texas Asset. As of December 31, 2012, we moved our Niobrara Asset to the full cost pool and no longer capitalize interest on these costs.

In 2011, we repurchased notes as summarized below:

Instrument	Repurchase Price		Face Value		Premium on Repurchase
	(In thousands)
Senior notes due 2015	$	38,134	$	37,000	$	1,134
Senior notes due 2016	10,646		9,380		1,266
Senior notes due 2019	2,160		2,000		160
	$	50,940	$	48,380	$	2,560

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Income Taxes

The U.S effective tax rates for the three years ended December 31, 2013 are as follows:

	Years Ended December 31,
	2013			2012			2011
				(In thousands)
Income (loss) before income taxes	$	184,034		$	(2,142,730	)	$	146,090
Income tax expense (benefit)	$	12,076		$	(227,934	)	$	53,599
Effective tax rate	6.56		%	10.60		%	36.70		%

In 2013, our U.S. income tax expense includes a decrease in the valuation allowance of $183.0 million.

The Canadian effective tax rates for the three years ended December 31, 2013 are as follows:

	Years Ended December 31,
	2013			2012			2011
				(In thousands)
Income (loss) before income taxes	$	(7,866	)	$	(505,446	)	$	1,819
Income tax expense (benefit)	$	2,474		$	(67,636	)	$	4,264
Effective tax rate	(31.45		)%	13.40		%	215.80		%

In 2013, our Canadian income tax expense includes an increase in the valuation allowance of $1.6 million.

The consolidated effective tax rates for the three years ended December 31, 2013 are as follows:

	Years Ended December 31,
	2013			2012			2011
				(In thousands)
Income (loss) before income taxes	$	176,168		$	(2,648,176	)	$	147,909
Income tax expense (benefit)	$	14,550		$	(295,570	)	$	57,863
Effective tax rate	8.26		%	11.20		%	39.10		%

In 2012, we recognized a full valuation allowance against our net deferred tax assets in the U.S. and Canada. Accordingly, in 2013, tax expense has been limited to the tax effects of reclassification adjustments from other comprehensive income and the tax refund received in the U.S. The valuation allowance is the principle reason our effective tax rates in the U.S. and Canada differ from the statutory rates. We expect that taxes will continue to be limited in 2014 given a valuation allowance is expected in both the U.S. and Canada. Taxation in the U.S. for the three years utilized a federal tax rate of 35% and a state tax rate of 1%. The Canadian effective tax rates for 2013 utilized a combined federal and provincial rate of 25.2% while 2012 and 2011 utilize a combined federal and provincial rate of 25%.

During 2012, we recognized a U.S. and Canadian valuation allowance of $534.0 million and $61.3 million, respectively, as we determined that it is no longer more likely than not that we will realize the deferred tax benefits primarily related to our cumulative net operating losses because we have been in a cumulative three-year loss for both the U.S. and Canada.

Canadian taxes increased for 2011 due to the recognition of capital gain resulting from the formation of Fortune Creek.

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Quicksilver Resources Inc. and its Restricted Subsidiaries

Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 18 to our consolidated financial statements included in Item 8 in this Annual Report.

The combined results of operations for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated results of operations, which are discussed above under “Results of Operations.” The combined financial position of Quicksilver and our restricted subsidiaries and our consolidated financial position are materially the same except for the property, plant and equipment purchased by the unrestricted subsidiaries, which consist of the balances held by Fortune Creek, which were included in the consolidated financial position as of December 31, 2012. The combined operating cash flows, financing cash flows and investing cash flows for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated operating cash flows, financing cash flows and investing cash flows, which are discussed below in “Cash Flow Activity.”

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.

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 December 31, 2013.

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.

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Operating Cash Flows

	Years Ended December 31,
	2013			2012		2011
	(In thousands)
Net cash provided by (used in) operating activities	$	(51,700	)	$	227,727	$	253,053

Net cash used in operating activities for 2013 increased from 2012 due to expenses related to our debt refinancing, lower realized prices (including derivative effects), lower production volumes, payment to NGTL and negative changes in working capital. Net cash used in operating activities for 2013 also includes hedge cash settlements of $12.6 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.

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

Investing Cash Flows

	Years Ended December 31,
	2013			2012			2011
	(In thousands)
Capital expenditures	$	(101,288	)	$	(485,479	)	$	(690,607	)
Proceeds from Tokyo Gas Transaction	463,999			—			—
Proceeds from Synergy Transaction	42,297			—			—
Proceeds from Crestwood earn-out	—			41,097			—
Proceeds from sale of BBEP units	—			—			272,965
Proceeds from sales of properties & equipment	7,171			72,725			4,163
Purchases of marketable securities	(213,738		)	—			$	—
Maturities and sales of marketable securities	47,603			—			$	—
Net cash provided by (used in) investing activities	$	246,044		$	(371,657	)	$	(413,479	)

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

For 2012 and 2011, we spent significant cash resources for the development of our large acreage positions in our core areas in the Barnett Shale and Horn River. During 2013, we received a $464.0 million payment from the Tokyo Gas Transaction in April and a $42.3 million payment from the Synergy Transaction in August. A portion of the cash received from the Tokyo Gas Transaction was invested in interest bearing time deposits and commercial paper with maturities of less than one year. We intend to hold these investments until maturity. During 2012, we collected $41.1 million from Crestwood pursuant to the earn-out provisions of our agreement with them, and received a confidential equalization payment upon closing of the SWEPI transaction. During 2011, we sold 15.7 million BBEP Units for an average price of $17.40 or total proceeds of $273.0 million that was used to repay borrowings outstanding under our senior secured credit facilities.

Our 2013 capital costs incurred included 65% associated with direct drilling and completion activities, while 20% was spent for leasehold acquisition and 10% was spent for surface land acquisition in Canada. The majority of our drilling and completion expenditures in 2013 were associated with our Barnett Shale and Niobara Assets. Leasehold expenditures reflected extensions in our Niobrara and West Texas Assets.

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Our 2012 capital costs incurred included 75% associated with direct drilling and completion activities, while 8% was spent for leasehold acquisitions and 3% spent for midstream activities. The majority of 2012 drilling and completion expenditures were associated with our Horn River and Barnett Shale Assets, but also included activity in our West Texas Asset and our Niobrara Asset. Leasehold expenditures reflected new acreage acquisitions and extensions in our Niobrara Asset and in our West Texas Asset. Midstream capital expenditures were concentrated in our Horn River Asset.

Our 2011 capital expenditures included 59% that was associated with drilling and completion activities, while 24% was spent for leasehold acquisitions and 11% spent for midstream activities. The majority of 2011 drilling and completion expenditures were associated with our Barnett Shale Asset, but also included increased activity in our Niobrara Asset and our Horn River Asset with expenditures of $36 million and $95 million, respectively. Leasehold expenditures reflected new acreage acquisitions in our Niobrara Asset of approximately $79 million and in our West Texas Asset of approximately $52 million. Midstream capital expenditures were concentrated in our Horn River Asset and principally related to the construction of the gathering system that was contributed in the formation of Fortune Creek.

Financing Cash Flows

	Years Ended December 31,
	2013			2012			2011
	(In thousands)
Net borrowings (payments)	$	(71,030	)	$	157,529		$	12,714
Debt issuance costs	(26,296		)	(3,022		)	(12,506		)
Partnership funds received (distributed)	(14,965		)	(14,285		)	122,913
Proceeds from exercise of stock options	—			11			1,299
Purchase of treasury stock	(1,927		)	(3,144		)	(4,864		)
Net cash provided by (used in) financing activities	$	(114,218	)	$	137,089		$	119,556

Net financing cash flows in 2013 include net payments of $71.0 million under our Combined Credit Agreements. During the quarter ended June 30, 2013, we executed a number of refinancing transactions, which are more fully described in Note 11 to the consolidated financial statements included in Item 8 of this Annual Report, to extend our debt maturities and reduce the weighted average interest costs. Issuance costs related to these transactions were $23.4 million. Proceeds from the Second Lien Term Loan and the issuance of the Second Lien Note due 2019 and Senior Notes due 2021 were used to pay for validly tendered Senior Notes due 2015 and Senior Notes due 2016 and accrued interest and transaction expenses. During the quarter ended September 30, 2013, we repurchased $2.3 million aggregate principal amount of our Senior Notes due 2015. Distributions of Fortune Creek partnership funds of $15.0 million were paid in 2013 to our partner based on our partner's preferential distribution rights.

Net financing cash flows in 2012 include net borrowings of $157.5 million under our senior secured credit facilities, partially offset by $14.3 million of distributions from Fortune Creek. Net financing cash flows in 2011 include net borrowings of $227.5 million under our senior secured credit facilities and $122.9 million of funds received from Fortune Creek, partially offset by $48.4 million of purchases and retirement of our senior notes and repurchases of substantially all our $150 million convertible debentures.

Liquidity and Borrowing Capacity

At December 31, 2013, the Combined Credit Agreements’ global borrowing base was $350 million and the global letter of credit capacity was $280 million. At December 31, 2013, there was $97.6 million available under the Combined Credit Agreements.

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

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

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

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

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

• Permit up to $825 million of second lien debt

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

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

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

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

• Amend certain definitions which impact the financial covenant calculations.

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

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 for the next 12 months, 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 December 31, 2013 and for all of 2013, we did not meet this test and, as a result, we are limited in our ability to, among other things, incur additional debt, except for specific baskets. We do retain, however, the ability to utilize the full borrowing capacity under our Combined Credit Agreements and 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.

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. We believe we have and will have sufficient liquidity and capital resources to defer these springing maturities until at least the last half of 2015.

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We retained a portion of cash received from our 2013 asset sales. Our indentures require us to reinvest or repay senior debt with net cash proceeds from asset sales 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, but may also repay a portion of our senior indebtedness.

Additional information about our debt and related covenants is more fully described in Note 11 to the consolidated financial statements in Item 8 of this Annual 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 and 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 borrowing base, which is redetermined twice each year. This semi-annual scheduled redetermination occurs each spring and autumn. We have made only preliminary strides in the spring 2014 redetermination process and cannot yet determine what, if any, adjustment occurs to the borrowing base. A reduction to the 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 forming Fortune Creek, our Canadian subsidiary contributed an existing 20-mile, 20-inch gathering line and its related compression facilities and committed to minimum capital expenditures of $300 million for drilling and completion activities in our Horn River Asset between 2012 and 2014. In March 2014, we agreed with KKR to an amendment to extend the time to meet the minimum capital expenditures from the end of 2014 to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving our Horn River Asset. We have incurred $180 million as of December 31, 2013. To the extent the remaining minimum capital expenditure commitment of $120 million is not met, we will incur a cash penalty in an amount equal to the shortfall, which will then become due and payable. If we do not secure a partner in our Horn River Asset, we might not have sufficient liquidity to satisfy the minimum capital expenditure commitment. As part of the amendment, we contributed C$28 million to Fortune Creek, which was subsequently distributed to KKR. 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 $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 December 31, 2013, as compared to our balance sheet as of December 31, 2012:

• Cash, cash equivalents and marketable securities increased $250.5 million as we retained a portion of the Tokyo Gas Transaction payment in cash, cash equivalents and marketable securities.

• Our accounts receivable balance decreased $5.5 million primarily due to lower production volumes compared to December 31, 2012 as well as a decrease of $3.1 million related to NGL hedge settlement accruals in 2012.

• Our net property, plant and equipment balance decreased $168.3 million. The Tokyo Gas Transaction resulted in a decrease of $132.7 million. The Synergy Transaction resulted in a decrease of $51.0 million. Additional decreases were due to DD&A incurred of $59.4 million and $25.7 million related to U.S.-Canadian exchange rate changes. Offsetting these decreases, we incurred capital cost of $98.7 million during 2013.

• The valuation of our current and non-current derivative assets and liabilities was $73.7 million lower on a net basis, which was primarily due to settlements during the year without additional derivatives being added and an increase in the natural gas forward curve.

• The $8.3 million decrease in accounts payable was due primarily to a reduction in accrued capital expenditures of $0.5 million and a decrease in trade payables of $7.5 million from December 31, 2012 as activity has decreased from December 31, 2012.

• Our accrued liabilities decreased $27.8 million, primarily due to early payment of accrued interest in connection with our refinancing, partially offset by an increase in accrued employee incentive compensation.

• Long-term debt decreased $74.3 million primarily from net payments under the Combined Credit Agreements of $169.8 million, recognition of $12.0 million of interest rate swaps and changes to the U.S.-Canadian exchange rate resulting in a decrease of $7.1 million, partially offset by net borrowings of $98.8 million as a result of our refinancing of our debt and $15.9 million of amortized discounts, including the impact of the redemption from the refinancing of our debt.

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Contractual Obligations and Commercial Commitments

Contractual Obligations

Information regarding our contractual and scheduled interest obligations, at December 31, 2013, is set forth in the following table:

	Payments Due by Period
	Total		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
	(In thousands)
Long-term debt	$	2,027,851	$	—	$	579,851	$	1,123,000	$	325,000
Scheduled interest obligations	828,674		158,639		414,667		201,743		53,625
GPT contracts	538,284		86,628		245,172		111,158		95,326
Drilling rig contracts	4,240		4,240		—		—		—
Purchase obligations	3,291		3,071		220		—		—
Asset retirement obligations	106,570		433		1,260		840		104,037
Operating lease obligations	33,138		3,912		12,187		8,879		8,160
Total obligations	$	3,542,048	$	256,923	$	1,253,357	$	1,445,620	$	586,148

• Long-Term Debt.  As of December 31, 2013, our outstanding indebtedness included $625 million of senior secured second lien term loan, $200 million of senior secured second lien notes due 2019, $11 million of senior notes due 2015, $8 million of senior notes due 2016, $298 million of senior notes due 2019, $325 million of senior notes due 2021, $350 million of senior subordinated notes, and outstanding amounts under our Combined Credit Agreements. Based upon our debt outstanding and interest rates as of December 31, 2013, we anticipate interest payments, including our scheduled interest obligations, to be $158.6 million in 2014. Our Combined Credit Agreements and both of our secured second lien instruments are subject to springing maturities. Further information can be found in Note 11 to our consolidated financial statements found in Item 8 of this Annual Report.

• Scheduled Interest Obligations.  As of December 31, 2013, we had scheduled interest payments of $44.3 million annually on our senior secured second lien term loan based on current rates, $14.2 million annually on our senior secured second lien term note due 2019 based on current rates, $0.9 million annually on our senior notes due 2015, $1.0 million annually on our senior notes due 2016, $27.2 million annually on our senior notes due 2019, $35.7 million annually on our senior notes due 2021, $24.9 million annually on our $350 million of senior subordinated notes, and $10.4 million annually on our Combined Credit Agreements based on the amount outstanding and current rates.

• Gathering, Processing and Transportation Contracts.  Under contracts with various third parties, we are obligated to provide minimum daily natural gas volume for gathering, processing, fractionation or transportation, as determined on a monthly basis, or pay for any volume deficiencies at a specified reservation fee rate.

• Drilling Rig Contracts.  We utilize drilling rigs from third parties in our development and exploration programs. The outstanding drilling rig contract requires payment of a specified day rate of $20,000 for the entire lease term regardless of our utilization of the drilling rig.

• Purchase Obligations.  At December 31, 2013, we were under contract to purchase goods and services for use in field and gas plant operations.

• Asset Retirement Obligations.  Our obligations result from the acquisition, construction or development and the normal operation of our long-lived assets.

• Operating Lease Obligations.  We lease office buildings and other property under operating leases.

We have capital commitments within our Horn River Asset related to the Fortune Creek gathering system. Further information can be found in Note 15 to our consolidated financial statements found in Item 8 of this Annual Report.

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Commercial Commitments

We had the following commercial commitments as of December 31, 2013:

	Amounts of Commitments by Expiration Period
	Total		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
	(In thousands)
Surety bonds	$	6,618	$	6,618	$	—	$	—	$	—
Standby letters of credit	41,188		41,188		—		—		—
Total	$	47,806	$	47,806	$	—	$	—	$	—

• Surety Bonds.  Our surety bonds have been issued to fulfill contractual, legal or regulatory requirements. Surety bonds generally have an annual renewal option.

• Standby Letters of Credit.  Our letters of credit have been issued to fulfill regulatory or contractual requirements. All of these letters of credit were issued under our Combined Credit Agreements and generally have an annual renewal option.

CRITICAL ACCOUNTING ESTIMATES

Our consolidated financial statements are prepared in accordance with GAAP. In connection with the preparation of our financial statements, we are required to make assumptions and estimates about future events, and apply judgments that affect the reported amounts of assets, liabilities, revenue, expense and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.

Our significant accounting policies are discussed in Note 2 to the consolidated financial statements included in Item 8 of this Annual Report. Management believes that the following accounting estimates are the most critical in fully understanding and evaluating our reported financial results, and they require management's most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain. Management has reviewed these critical accounting estimates and related disclosures with our Audit Committee.

Oil and Gas Reserves

Policy Description

Proved oil and gas reserves are the estimated quantities of oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. We use an unweighted average of the preceding 12-month first-day-of-the-month prices for determination of proved reserve values included in calculating full cost ceiling limitations and for annual proved reserve disclosures. We assume continued use of technologies with demonstrated success of yielding expected results, including the use of drilling results, well performance, well logs, seismic data, geological maps, well stimulation techniques, well test data and reservoir simulation modeling.

Operating costs are the period end operating costs at the time of the reserve estimate and are held constant into future periods. Our estimates of proved reserves are determined and reassessed at least annually using available geological and reservoir data as well as production performance data. Revisions may result from changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions.

We recognize PUD reserves beyond one offset location where reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. In our Barnett Shale Asset and Horseshoe Canyon Asset, we had 87 proved undeveloped drilling locations at December 31, 2013, including 13 locations that

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are more than one offset. Additional information regarding our proved oil and gas reserves may be found under “Oil and Natural Gas Reserves” found in Item 1 of this Annual Report.

Judgments and Assumptions

All of the reserve data in this Annual Report are based on estimates. Estimates of our oil, natural gas and NGL reserves are prepared in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating recoverable underground accumulations of oil, natural gas and NGLs. There are numerous uncertainties inherent in estimating recoverable quantities of proved oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of oil, natural gas and NGLs that are ultimately recovered.

The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. The weighted average annual revisions to our reserve estimates over the last five years have been less than 7% of the weighted average previous year’s estimate (excluding revisions due to price changes). However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in ceiling test-related impairments. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling limitation, estimation of proved reserves is also a significant component of the calculation of depletion expense. For example, if estimates of proved reserves decline, the depletion rate will increase, resulting in a decrease in net income.

Full Cost Ceiling Calculations

Policy Description

We use the full cost method to account for our oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration, and development of oil and gas properties are capitalized and accumulated in cost centers on a country-by-country basis. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is calculated and recognized. The application of the full cost method generally results in higher capitalized costs and higher depletion rates compared to its alternative, the successful efforts method. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production basis using proved oil and gas reserves. Excluded from amounts subject to depletion are costs associated with unevaluated properties.

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (1) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on the unweighted average of the preceding 12-month first day-of the-month prices adjusted to reflect local differentials and contract provisions, unescalated year-end costs and derivatives that are accounted for as hedges which are included in our oil and gas revenue, (2) the cost of properties not being amortized, (3) the lower of cost or market value of unproved properties included in the cost being amortized less (4) income tax effects related to differences between the book and tax bases of the oil and gas properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required.

Judgments and Assumptions

The discounted present value of future net cash flows from our proved oil, natural gas and NGL reserves is the major component of the ceiling calculation, and is determined in connection with the estimation of our proved oil, natural gas and NGL reserves. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of reserve estimation requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data.

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While the quantities of proved reserves require substantial judgment, the associated prices of natural gas, NGL and oil reserves, and the applicable discount rate that are used to calculate the discounted present value of the reserves do not require judgment. The current SEC rule requires the use of the future net cash flows from proved reserves discounted at 10%. Therefore, the future net cash flows associated with the proved reserves is not based on our assessment of future prices or costs. In calculating the ceiling, we adjust the future net cash flows by the discounted value of derivative contracts in place that hedge future prices. This valuation is determined by calculating the difference between reserve pricing and the contract prices for such hedges also discounted at 10%. At December 31, 2013, no derivatives were included in the ceiling.

Because the ceiling calculation dictates that our historical experience be held constant indefinitely and requires a 10% discount factor, the resulting value is not necessarily indicative of the fair value of the reserves or the oil and gas properties. Oil and natural gas prices have historically been volatile. At any time that we conduct a ceiling test, forecasted prices can be either substantially higher or lower than our historical experience. Also, marginal borrowing rates may be well below the required 10% used in the calculation. Rates below 10%, if they could be utilized, would have the effect of increasing the otherwise calculated ceiling amount. Therefore, oil and gas property ceiling test-related impairments that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Derivative Instruments

Policy Description

We enter into derivatives to mitigate risk associated with the prices received from our natural gas, NGL and oil production. We may also utilize derivatives to hedge the risk associated with interest rates on our outstanding debt. All derivatives are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates.

Effective December 31, 2012, we discontinued the use of hedge accounting on all existing hedge contracts. Net deferred hedge gains deferred in AOCI associated with these contracts as of December 31, 2012 will be reclassified to earnings during the same periods in which the hedged transactions are recognized in our earnings. In the future we will recognize changes in the fair values of derivative contracts as gains or losses in the earnings of the periods in which they occur. If the underlying transaction is no longer probable of occurring, we would recognize the related deferred hedge gain or loss in revenue from natural gas, NGL and oil production during the period in which it is no longer probable of occurring.

We enter into derivatives with counterparties who are our lenders at the inception of the derivative. All versions of our credit facility provide for collateralization of amounts outstanding from our derivatives in addition to amounts outstanding under the facility. Additionally, default on any of our obligations under derivatives with counterparty lenders could result in acceleration of the amounts outstanding under the credit facility. Our credit facility and our internal credit policies require that any counterparties, including facility lenders, with whom we enter into commodity derivatives have credit ratings that meet or exceed BBB- or Baa3 from Standard and Poor’s or Moody’s, respectively. The fair value for each derivative takes credit risk into consideration, whether it be our counterparties’ or our own. Derivatives are classified as current or non-current derivative assets and liabilities, based on the expected timing of settlements.

Judgments and Assumptions

The estimates of the fair values of our commodity and interest rate derivative instruments require substantial judgment. Valuations are based upon multiple factors such as futures prices, volatility data from major oil and gas trading points, length of time to maturity, credit risks and interest rates. We compare our estimates of fair value for these instruments with valuations obtained from independent third parties and counterparty valuation confirmations. The values we report in our financial statements change as these estimates are revised to reflect actual results. Future changes to forecasted or realized commodity prices could result in significantly different values and realized cash flows for such instruments.

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Stock-Based Compensation

Policy Description

An estimate of fair value is determined for all share-based payment awards. Recognition of compensation expense for share-based payment awards is recognized over the vesting period or, for awards that vest only upon achievement of performance criteria, recognition is recorded only when achievement of the performance criteria is considered probable.

Judgments and Assumptions

Estimating the grant date fair value of our stock-based compensation requires management to make assumptions and to apply judgment to determine the grant date fair value of our awards. These assumptions and judgments include estimating the future volatility of our stock price, expected dividend yield, future employee turnover rates and future employee stock option exercise behaviors. Changes in these assumptions can materially affect the fair value estimate.

We do not believe there is a reasonable likelihood that there will be a material change in the future estimates or assumptions that we use to determine stock-based compensation expense. However, if actual results are not consistent with our estimates or assumptions, we may be exposed to changes in stock-based compensation expense that could be material. If actual results are not consistent with the assumptions used, the stock-based compensation expense reported in our financial statements may not be representative of the actual economic cost of the stock-based compensation.

Income Taxes

Policy Description

Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that we expect will be in effect during years in which we expect the temporary differences will reverse. Canadian taxes are computed at rates in effect or expected to be in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested in Canada and thus are not considered available for distribution to us. If we did choose to repatriate any Canadian profits, we would need to accrue and pay taxes on these amounts. Net operating loss carry-forwards and other deferred tax assets are reviewed annually for recoverability, and if necessary, are recorded net of a valuation allowance.

Judgments and Assumptions

We must assess the likelihood that deferred tax assets will be recovered from future taxable income. To the extent that we believe our deferred tax assets are not more likely than not to be realized, we must establish a valuation allowance. In making that assessment, we consider both positive and negative evidence related to the likelihood of realization of the deferred tax assets on a jurisdictional basis to determine, based on the weight of available evidence, whether it is more likely than not that some or all of the deferred tax assets will not be realized. Examples of positive and negative evidence include historical taxable income or losses, forecasted income or losses, the estimated timing of the reversals of existing temporary differences as well as prudent and feasible tax planning strategies. We consider a cumulative loss in recent years as a significant piece of negative evidence. A valuation allowance, by taxing jurisdiction, is established when necessary to reduce deferred tax assets to the amounts more likely than not expected to be realized. Significant management judgment is also required in determining the amount of financial statement benefit to record for uncertain tax positions. We consider the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. Our income tax provision would increase or decrease in the period in which the assessment is changed.

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OFF-BALANCE SHEET ARRANGEMENTS

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

Additional off-balance sheet arrangements are detailed in “Contractual Obligations and Commercial Commitments.”

RECENTLY ISSUED ACCOUNTING STANDARDS

The information regarding recent accounting pronouncements materially affecting our consolidated financial statements is included in Note 2 to our consolidated financial statements in Item 8 of this Annual Report, which is incorporated herein by reference.

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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. The following summarizes future production hedged with commodity derivatives as of December 31, 2013.

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.

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 $68.2 million, $194.6 millionand $84.9 million for 2013, 2012 and 2011, respectively, and a gain was recognized in net derivative gains of $21.2 million and $42.8 million for 2013 and 2012, respectively. An unrealized gain of $8.7 million, loss of $17.9 million and gain of $45.9 million were recognized for 2013, 2012 and 2011, respectively.

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.

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The following table details our open derivative positions at December 31, 2013:

			Remaining Contract Period	Volume	Weighted Average Price Per Mcf or Bbl	Fair Value
Segment	Product	Type				Total			2014			2015			2016		2017		2018		Thereafter
						(In thousands)
Canada	Gas	Swap	Jan 2014 - Dec 2015	10 MMcfd	6.42	16,410			8,137			8,273			—		—		—		—
Canada	Gas	Swap	Jan 2014 - Dec 2015	10 MMcfd	6.45	16,629			8,247			8,382			—		—		—		—
Canada	Gas	Swap	Jan 2014 - Dec 2015	10 MMcfd	4.04	(921		)	(544		)	(377		)	—		—		—		—
Canada	Gas	Swap	Jan 2014 - Dec 2021	10 MMcfd	4.63	10,024			1,589			1,749			1,792		1,661		1,405		1,828
U.S	Gas	Swap	Jan 2014 - Dec 2014	10 MMcfd	3.91	(1,019		)	(1,019		)	—			—		—		—		—
U.S	Gas	Swap	Jan 2014 - Dec 2014	10 MMcfd	3.89	(1,092		)	(1,092		)	—			—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2015	5 MMcfd	6.23	7,513			3,722			3,791			—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2015	5 MMcfd	6.20	7,404			3,667			3,737			—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2015	20 MMcfd	6.00	26,704			13,211			13,493			—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2015	10 MMcfd	6.00	13,352			6,605			6,747			—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2015	5 MMcfd	5.68	5,511			2,719			2,792			—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2015	7.5 MMcfd	5.48	7,283			3,586			3,697			—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2015	7.5 MMcfd	5.50	7,147			3,518			3,629			—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2015	5 MMcfd	4.15	(60		)	(72		)	12			—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2015	5 MMcfd	4.13	(133		)	(108		)	(25		)	—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2015	5 MMcfd	4.26	322			120			202			—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2015	5 MMcfd	4.25	304			111			193			—		—		—		—
U.S.	Gas	Swap	Jan 2014 - Dec 2021	10 MMcfd	4.54	7,709			1,279			1,440			1,486		1,362		1,116		1,026
U.S.	Gas	Swap	Jan 2014 - Dec 2021	5 MMcfd	4.38	1,675			348			429			455		400		285		(242		)
U.S.	Gas	Swap	Jan 2014 - Dec 2021	10 MMcfd	4.37	3,077			659			823			873		764		537		(579		)
U.S.	Gas	Swap	Jan 2014 - Dec 2021	5 MMcfd	4.35	1,266			293			375			401		347		234		(384		)
U.S.	NGL	Swap	Jan 2014 - Sept 2014	1 MBbld	30.43	(432		)	(432		)	—			—		—		—		—
U.S.	NGL	Swap	Jan 2014 - Sept 2014	2 MBbld	30.55	(801		)	(801		)	—			—		—		—		—
U.S.	NGL	Swap	Jan 2014 - Sept 2014	1 MBbld	30.55	(400		)	(400		)	—			—		—		—		—
Canada	Gas Basis1	Swap	Jan 2014 - Dec 2014	5 MMcfd	(0.475)	104			104			—			—		—		—		—
Canada	Gas Basis1	Swap	Jan 2014 - Dec 2014	5 MMcfd	(0.475)	104			104			—			—		—		—		—
Canada	Gas Basis1	Swap	Jan 2014 - Dec 2014	10 MMcfd	(0.475)	209			209			—			—		—		—		—
Canada	Gas Basis1	Swap	Jan 2014 - Dec 2014	10 MMcfd	(0.47)	227			227			—			—		—		—		—
Canada	Gas Basis1	Swap	Jan 2014 - Dec 2014	10 MMcfd	(0.45)	300			300			—			—		—		—		—
			Grand Total			$	128,416		$	54,287		$	59,362		$	5,007	$	4,534	$	3,577	$	1,649

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

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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.

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. In June 2013, we repurchased substantially all our senior notes due 2015 resulting in early recognition of the associated deferred gain. For 2013, 2012 and 2011, we recognized $12.0 million, $5.1 million and $4.8 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 December 31, 2013, each $50 million in borrowings would result in additional annual interest payments of $2.0 million. If the current borrowing availability under our Combined Credit Agreements were to be fully utilized by year-end 2014 at interest rates as of December 31, 2013, we estimate that annual interest payments would increase by $3.9 million. If interest rates change by 1% on our December 31, 2013 variable debt balances of $211 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 December 31, 2013, would not impact our applicable interest rate on this debt, as the floor would not be exceeded. A 1% decrease in the interest rate would not impact our applicable interest rate on this debt, as we have not exceeded the floor at December 31, 2013.

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

Foreign Currency Risk

Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. Non-functional currency transactions resulted in a $2.4 million loss, $0.1 million gain and $2.5 million loss for 2013, 2012 and 2011, 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.

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ITEM 8. Financial Statements and Supplementary Data

QUICKSILVER RESOURCES INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Reports of Independent Registered Public Accounting Firms	66
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) for the Years Ended December 31, 2013, 2012 and 2011	68
Consolidated Balance Sheets as of December 31, 2013 and 2012	69
Consolidated Statements of Equity for the Years ended December 31, 2013, 2012 and 2011	70
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	71
Notes to Consolidated Financial Statements for the Years Ended December 31, 2013, 2012 and 2011	72
Supplemental Selected Quarterly Financial Data (Unaudited)	113
Supplemental Oil and Gas Information (Unaudited)	114
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	122

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Quicksilver Resources Inc.

We have audited the accompanying consolidated balance sheet of Quicksilver Resources Inc. as of December 31, 2013 and 2012, and the related consolidated statements of income (loss) and comprehensive income (loss), equity, and cash flows for the years ended December 31, 2013 and 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Quicksilver Resources Inc. at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for the years ended December 31, 2013 and 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Quicksilver Resources Inc.'s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 Framework) and our report dated March 17, 2014 expressed an adverse opinion on the effectiveness of internal control over financial reporting because of a material weakness.

/s/ Ernst & Young LLP

Fort Worth, Texas

March 17, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Quicksilver Resources Inc.

Fort Worth, Texas

We have audited the accompanying consolidated statements of income (loss) and comprehensive income (loss), equity, and cash flows of Quicksilver Resources Inc. and subsidiaries (the “Company”) for the year ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of Quicksilver Resources Inc. for the year ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Fort Worth, Texas

April 15, 2012

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QUICKSILVER RESOURCES INC.

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

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

In thousands, except for per share data

	2013			2012			2011
Revenue
Production	$	463,491		$	630,947		$	800,543
Sales of purchased natural gas	64,913			62,405			86,645
Net derivative gains	29,928			11,444			51,780
Other	3,230			4,242			4,655
Total revenue	561,562			709,038			943,623
Operating expense
Lease operating	82,265			95,333			102,874
Gathering, processing and transportation	148,569			166,316			190,560
Production and ad valorem taxes	17,066			25,395			29,226
Cost of purchased natural gas	64,840			62,041			85,398
Depletion, depreciation and accretion	62,612			163,624			225,763
Impairment	1,863			2,625,928			107,059
General and administrative	55,306			75,697			79,582
Other operating	3,725			1,562			557
Total expense	436,246			3,215,896			821,019
Gain on Tokyo Gas Transaction	339,328			—			—
Crestwood earn-out	—			41,097			—
Operating income (loss)	464,644			(2,465,761		)	122,604
Loss from earnings of BBEP	—			—			(8,439		)
Other income (expense) - net	(17,384		)	1,108			219,768
Fortune Creek accretion	(19,245		)	(19,472		)	—
Interest expense	(251,847		)	(164,051		)	(186,024		)
Income (loss) before income taxes	176,168			(2,648,176		)	147,909
Income tax (expense) benefit	(14,550		)	295,570			(57,863		)
Net income (loss)	161,618			(2,352,606		)	90,046
Reclassification adjustments related to settlements of derivative contracts into production revenue- net of income tax	(46,931		)	(128,161		)	(58,125		)
Net change in derivative fair value - net of income tax	—			74,384			156,160
Foreign currency translation adjustment	(4,681		)	412			(13,364		)
Other comprehensive income (loss)	$	(51,612	)	$	(53,365	)	$	84,671
Comprehensive income (loss)	$	110,006		$	(2,405,971	)	$	174,717
Earnings (loss) per common share - basic	$	0.92		$	(13.83	)	$	0.53
Earnings (loss) per common share - diluted	$	0.92		$	(13.83	)	$	0.52

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

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QUICKSILVER RESOURCES INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2013 AND 2012

In thousands, except for share data

	2013			2012
ASSETS
Current assets
Cash and cash equivalents	$	89,103		$	4,951
Marketable securities	166,343			—
Total cash, cash equivalents and marketable securities	255,446			4,951
Accounts receivable - net of allowance for doubtful accounts	58,645			64,149
Derivative assets at fair value	57,523			113,367
Other current assets	22,346			25,046
Total current assets	393,960			207,513
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $221,605 and $307,267, respectively)	640,443			780,960
Other property and equipment	220,362			248,098
Property, plant and equipment - net	860,805			1,029,058
Derivative assets at fair value	73,357			105,270
Other assets	41,604			39,947
	$	1,369,726		$	1,381,788
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	28,822			37,131
Accrued liabilities	102,850			130,660
Derivative liabilities at fair value	3,125			—
Total current liabilities	134,797			167,791
Long-term debt	1,988,946			2,063,206
Partnership liability	126,132			130,912
Asset retirement obligations	106,256			115,949
Derivative liabilities at fair value	323			17,485
Other liabilities	19,242			19,242
Commitments and contingencies (Note 14)
Stockholders' equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding	—			—
Common stock, $0.01 par value, 400,000,000 shares authorized, and 183,994,879 and 179,015,118 shares issued, respectively	1,840			1,790
Additional paid in capital	770,092			751,394
Treasury stock of 6,698,640 and 5,921,102 shares, respectively	(51,422		)	(49,495		)
Accumulated other comprehensive income	109,881			161,493
Retained deficit	(1,836,361		)	(1,997,979		)
Total stockholders' equity	(1,005,970		)	(1,132,797		)
	$	1,369,726		$	1,381,788

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

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QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

In thousands

	Common Stock		Additional Paid-in Capital		Treasury Stock			Accumulated Other Comprehensive Income			Retained Earnings (Deficit)			Total
Balances at December 31. 2010	1,755		714,869		(41,487		)	130,187			264,581			1,069,905
Net income	—		—		—			—			90,046			90,046
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $26,679	—		—		—			(58,125		)	—			(58,125		)
Net change in derivative fair value, net of income tax of $73,339	—		—		—			156,160			—			156,160
Foreign currency translation adjustment	—		—		—			(13,364		)	—			(13,364		)
Issuance & vesting of stock compensation	13		20,849		(4,864		)	—			—			15,998
Stock option exercises	2		1,297		—			—			—			1,299
Balances at December 31, 2011	1,770		737,015		(46,351		)	214,858			354,627			1,261,919
Net loss	—		—		—			—			(2,352,606		)	(2,352,606		)
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $66,417	—		—		—			(128,161		)	—			(128,161		)
Net change in derivative fair value, net of income tax of $36,206	—		—		—			74,384			—			74,384
Foreign currency translation adjustment	—		—		—			412			—			412
Issuance & vesting of stock compensation	19		14,369		(3,144		)	—			—			11,244
Stock option exercises	1		10		—			—			—			11
Balances at December 31, 2012	$	1,790	$	751,394	$	(49,495	)	$	161,493		$	(1,997,979	)	$	(1,132,797	)
Net income	—		—		—			—			161,618			161,618
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $21,581	—		—		—			(46,931		)	—			(46,931		)
Foreign currency translation adjustment	—		—		—			(4,681		)	—			(4,681		)
Issuance & vesting of stock compensation	50		18,698		(1,927		)	—			—			16,821
Balances at December 31, 2013	$	1,840	$	770,092	$	(51,422	)	$	109,881		$	(1,836,361	)	$	(1,005,970	)

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

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QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS END DECEMBER 31, 2013, 2012 AND 2011

In thousands

	2013			2012			2011
Operating activities:
Net income (loss)	$	161,618		$	(2,352,606	)	$	90,046
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion	62,612			163,624			225,763
Impairment expense	1,863			2,625,928			107,059
Write-off of MLP related fees and expenses	—			7,505			—
Gain on Tokyo Gas Transaction	(339,328		)	—			—
Crestwood earn-out	—			(41,097		)	—
Deferred income tax expense (benefit)	21,581			(289,981		)	64,492
Non-cash (gain) loss from hedging and derivative activities	3,904			57,826			(51,780		)
Stock-based compensation	17,979			22,246			20,862
Non-cash interest expense	26,920			9,854			16,510
Fortune Creek accretion	19,245			19,472			—
Gain on disposition of BBEP units	—			—			(217,893		)
Loss from BBEP in excess of cash distributions	—			—			28,269
Other	6,783			1,037			1,311
Changes in assets and liabilities
Accounts receivable	(3,994		)	30,950			(31,803		)
Prepaid expenses and other assets	322			(4,435		)	(6,017		)
Accounts payable	(7,133		)	(8,895		)	(11,434		)
Income taxes payable	7,828			1,183			(4,803		)
Accrued and other liabilities	(31,900		)	(14,884		)	22,471
Net cash provided by (used in) operating activities	(51,700		)	227,727			253,053
Investing activities:
Capital expenditures	(101,288		)	(485,479		)	(690,607		)
Proceeds from Tokyo Gas Transaction	463,999			—			—
Proceeds from Synergy Transaction	42,297			—			—
Proceeds from Crestwood earn-out	—			41,097			—
Proceeds from sale of BBEP units	—			—			272,965
Proceeds from sale of properties and equipment	7,171			72,725			4,163
Purchases of marketable securities	(213,738		)	—			—
Maturities and sales of marketable securities	47,603			—			—
Net cash provided by (used in) investing activities	246,044			(371,657		)	(413,479		)
Financing activities:
Issuance of debt	1,237,352			467,959			855,822
Repayments of debt	(1,308,382		)	(310,430		)	(843,108		)
Debt issuance costs paid	(26,296		)	(3,022		)	(12,506		)
Partnership funds received	—			—			122,913
Distribution of Fortune Creek Partnership funds	(14,965		)	(14,285		)	—
Proceeds from exercise of stock options	—			11			1,299
Purchase of treasury stock	(1,927		)	(3,144		)	(4,864		)
Net cash provided by (used in) financing activities	(114,218		)	137,089			119,556
Effect of exchange rate changes in cash	4,026			(1,354		)	(921		)
Net change in cash and cash equivalents	84,152			(8,195		)	(41,791		)
Cash and cash equivalents at beginning of period	4,951			13,146			54,937
Cash and cash equivalents at end of period	$	89,103		$	4,951		$	13,146

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

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QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

1. NATURE OF OPERATIONS

We are an independent oil and gas company incorporated in the state of Delaware and headquartered in Fort Worth, Texas. We engage in the acquisition, exploration, development, production and sale of natural gas, NGLs and oil in North America. As of December 31, 2013, our significant oil and gas reserves and operations are located in:

• Texas

• Alberta

• British Columbia

We have offices located in:

• Fort Worth, Texas

• Glen Rose, Texas

• Calgary, Alberta

Our results of operations are largely dependent on the difference between the prices received for our natural gas, NGL and oil products and the cost to find, develop, produce and market such resources. Natural gas, NGL and oil prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond our control. These factors include worldwide political instability, quantities of natural gas in storage, foreign supply of natural gas and oil, the price of foreign imports, the level of consumer demand and the price of available alternative fuels. We actively manage a portion of the financial risk relating to natural gas, NGL and oil price volatility through derivatives.

Due to the depressed price environment for natural gas, we incurred significant impairments in 2012 on our oil and gas assets and in turn, tax valuation allowances which contributed to the consolidated net loss for 2012. At December 31, 2013, we continue to have significant indebtedness, whose interest costs consume significant amounts of our operating cash flow. As more fully described in Note 11, at December 31, 2013 we did not meet an incurrence test in our indentures which is not an event of default, but as a result, we are limited in our ability to, among other things, incur additional debt. 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 in our indentures. At December 31, 2013, there was $97.6 million available from the $350 million global borrowing base under the Combined Credit Agreements. The next semi-annual redetermination of the Combined Credit Agreement is scheduled for April 2014. We have made only preliminary strides in the April 2014 redetermination process and cannot yet determine what, if any, adjustment occurs to the borrowing base. We anticipate our 2014 capital program, contractual commitments and recurring operating needs will be funded by cash flow from operations or cash on hand and supplemented by proceeds from asset sales. While we believe we have sufficient liquidity even without completing the Southwestern Transaction (as described in Note 3) completing it will improve our expected liquidity.

Given the capital intensive nature of our business, the amount of capital expenditures we deploy or do not deploy would have a significant impact on our EBITDA in 2015 and future periods. We project that we will comply with the financial maintenance covenants associated with our Combined Credit Agreements in 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. Further, in order to comply with the requirements under our debt agreements, including the financial maintenance covenants, we may need to alter our capital program, adjust our incentive awards and repay a portion of our senior indebtedness. Note 11 contains additional discussion of our covenant requirements. 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

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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.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our consolidated financial statements include our accounts and those of all of our majority-owned subsidiaries, companies over which we exercise control through majority voting rights or other means of control and variable interest entities of which we are the primary beneficiary. We eliminate all inter-company balances and transactions in preparing consolidated financial statements. We account for our ownership in unincorporated partnerships and companies, including our prior interest in BBEP, under the equity method when we have significant influence over those entities, but because of terms of the ownership agreements, we do not meet the criteria for consolidation of the entities.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities, the 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. Management believes its estimates and assumptions are reasonable, but 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.

Significant estimates underlying these financial statements include the estimated quantities of our proved reserves (including the associated future net cash flows from those proved reserves and costs to develop those reserves) used to compute depletion expense, the full cost ceiling limitation and estimates of current revenue. Other estimates that require assumptions concerning future events and substantial judgment include the estimated fair value of derivatives, asset retirement obligations and stock-based compensation. Income taxes also involve the use of considerable judgment in the estimation and evaluation of deferred income tax assets and our ability to recover operating loss carry-forwards and assessment of uncertain tax positions.

Cash Equivalents

Cash equivalents consist of time deposits and liquid debt investments with original maturities of three months or less at the time of purchase.

Accounts Receivable

We sell our production to various purchasers, each of which is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although we rarely require collateral, we require appropriate credit ratings and, in some instances, obtain parental guarantees. Receivables are generally collected within 30 to 60 days. When collections of specific amounts due are no longer reasonably assured, we establish an allowance for doubtful accounts though we have not had a significant instance of nonpayment. During 2013, one purchaser individually accounted for 18% of cash collected for our production revenue. During 2012, two purchasers individually accounted for 21% and 15% of cash collected for our production revenue. During 2011, two purchasers accounted for 15% and 11% of cash collected for our production revenue.

Hedging and Derivatives

We enter into derivatives to mitigate risk associated with the prices received from our natural gas, NGL and oil production. We may also utilize derivatives to hedge the risk associated with interest rates on our outstanding debt. All derivatives are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates.

Effective December 31, 2012, we discontinued the use of hedge accounting on all existing hedge contracts. Net deferred hedge gains deferred in AOCI associated with these contracts as of December 31, 2012 are reclassified to earnings during the same periods in which the hedged transactions are recognized in our earnings. Since then, we recognize changes in the fair values of derivative contracts as gains or losses in the earnings of the periods in which they occur.

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We enter into derivatives with counterparties who are our lenders at the inception of the derivative. Our credit facility provides for collateralization of amounts outstanding from our derivatives in addition to amounts outstanding under the facility. Additionally, default on any of our obligations under derivatives with counterparty lenders could result in acceleration of the amounts outstanding under the credit facility. Our credit facility and our internal credit policies require that any counterparties, including facility lenders, with whom we enter into commodity derivatives have credit ratings that meet or exceed BBB- or Baa3 from Standard and Poor’s or Moody’s, respectively. The fair value for each derivative takes credit risk into consideration, whether it be our counterparties’ or our own. Derivatives are classified as current or non-current derivative assets and liabilities, based on the expected timing of settlements.

Investments in Equity Affiliates

During December 2011, we liquidated our investment in BBEP which we had accounted for using the equity method. Prior to this liquidation, we reviewed our investment for impairment whenever events or circumstances indicated that the investment’s carrying amount may not be recoverable. We recorded our portion of BBEP’s earnings during the quarter in which its financial statements became publicly available. Consequently, our 2011 annual results of operations include BBEP’s earnings for the 12 months ended September 30, 2011. Note 7 contains more information on our BBEP investment.

Property, Plant, and Equipment

We follow the full cost method in accounting for our oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in separate Canadian and U.S. cost centers. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals reduce the accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is calculated and recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved reserves. We may, at our option, exclude costs associated with unevaluated properties from amounts subject to depletion.

Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations (collectively, “the cost center ceiling”). The cost center ceiling equals the sum of (1) estimated future net revenue from proved reserves, discounted at 10% per annum, including the effects of derivatives that are accounted for as hedges of our oil and gas revenue, (2) the cost of properties not being amortized, (3) the lower of cost or market value of unproved properties included in the cost being amortized, less (4) income tax effects related to differences between the book and tax basis of the natural gas and oil properties. If the net book value reduced by the related net deferred income tax liability, unless in a valuation allowance, and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required. Note 8 to these financial statements contains further discussion of the ceiling test.

Other properties and equipment are stated at original cost and depreciated using the straight-line method based on estimated useful lives ranging from five to forty years. If indicators of impairment are identified, an undiscounted cash flow analysis is performed to determine if an impairment exists. If the undiscounted cash flow analysis indicates an impairment, a discounted cash flow analysis is performed and the asset is reduced to the indicated value.

Inventory

Inventories are primarily comprised of materials and parts including oil and gas drilling or repair items such as tubing, casing, chemicals, operating supplies and ordinary maintenance materials and parts. The materials, parts and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or fair value, on a first-in, first-out cost basis. Fair value represents net realizable value, which is the amount that we are allowed to bill to the joint accounts under joint operating agreements to which we are a party. Impairments for materials and supplies inventories are recorded as lease operating expense in the accompanying consolidated statements of operations.

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Asset Retirement Obligations

We record the fair value of the liability for asset retirement obligations in the period in which it is legally or contractually incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is recognized as expense through depletion or depreciation over the asset’s useful life. Changes in the liability for the asset retirement obligations are recognized for (1) the passage of time and (2) revisions to either the timing or the amount of estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted liability to its estimated settlement value.

Revenue Recognition

Revenue is recognized when title to the products transfers to the purchaser. We use the “sales method” to account for our production revenue, whereby we recognize revenue on all production sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2013 and 2012, our aggregate production imbalances were not material.

Environmental Compliance and Remediation

Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred. Those environmental remediation costs which improve a property are capitalized.

Debt

We record all debt instruments at face value. When an issuance of debt is made at other than par, a discount or premium is separately recorded. The discount or premium is amortized over the life of the debt using the effective interest method.

Income Taxes

Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must reflect tax rates expected to be in effect in years in which the temporary differences reverse. Canadian taxes are calculated at rates expected to be in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested in Canada and thus not considered available for distribution to the parent company. It is not practicable to determine our unrecognized deferred tax liability for temporary differences related to investments in foreign subsidiaries that are essentially permanent in duration. Net operating loss carry-forwards and other deferred tax assets are reviewed annually for recoverability, and, if necessary, are recorded net of a valuation allowance. Note 13 contains additional discussion regarding income taxes.

Stock-based Compensation

We measure and recognize compensation expense for all share-based payment awards made to employees and directors based on their estimated fair value at the time the awards are granted. Our board of directors may elect to issue awards payable in cash. For awards with service requirements, we recognize the expense associated with the awards over the vesting period. The liability for fair value of cash awards is reassessed at every balance sheet date, such that the vested portion of the liability is adjusted to reflect revised fair value through compensation expense. For awards that vest only upon achievement of performance criteria, recognition is recorded only when achievement of the performance criteria is considered probable.

Disclosure of Fair Value of Financial Instruments

Our financial instruments include cash, commercial paper, time deposits, accounts receivable, notes payable, accounts payable, long-term debt and financial derivatives. The fair value of long-term debt is estimated as the present value of future cash flows discounted at rates consistent with comparable maturities and includes consideration of credit risk. The carrying amounts reflected in the balance sheet for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value.

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Foreign Currency Translation

Our Canadian subsidiary maintains its general ledger using the Canadian dollar. All balance sheet accounts of our Canadian operations are translated into U.S. dollars at the period end exchange rate and statement of income items are translated at the weighted average exchange rate for the period. The resulting translation adjustments are made directly to a component of accumulated other comprehensive income within stockholders’ equity. Gains and losses from foreign currency transactions are included in the consolidated results of operations.

Variable Interest Entities

An entity is a variable interest entity (VIE) if it meets the following criteria: (1) the entity has equity that is insufficient to permit the entity to finance its activities without additional subordinated financial support from other parties, or (2) the entity has equity investors that cannot make significant decisions about the entity’s operations or that do not absorb their proportionate share of the expected losses or receive the expected returns of the entity.

VIEs require assessment of who the primary beneficiary is and whether the primary beneficiary should consolidate the VIE. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the variable interest entity that most significantly impacts the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. Application of the VIE consolidation requirements may require the exercise of significant judgment by management.

In 2011, we began to include the financial position of Fortune Creek and the results of operations were included beginning with the period ended December 31, 2012 in our consolidated financial statements. The results from operations of Fortune Creek for 2011 were immaterial. Note 15 contains additional discussion regarding Fortune Creek.

Earnings per Share

We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. Note 17 includes the calculation of earnings per share.

Recently Issued Accounting Standards

No pronouncements materially affecting our financial statements have been issued since the filing of our 2012 Annual Report on Form 10-K.

3. DIVESTITURES

In March 2014, we executed an agreement with Southwestern Energy Company to sell a majority of our Niobrara Asset for cash proceeds of $90 million. The Southwestern Transaction is expected to close in May 2014.

In October and November 2013, we executed two separate agreements involving our West Texas Asset, the largest of which is a joint venture with Eni whereby we will jointly evaluate, explore and develop approximately 52,500 gross acres currently held by us in Pecos County, Texas. Under the terms of the agreement, Eni will pay up to $52.0 million in three phases to earn a 50% interest in our acreage. Upon completion of the three phases, we will participate equally in all future revenue, operating costs and capital expenditures with Eni.

In August 2013, we completed the sale of our Southern Alberta Basin Asset to Synergy with an effective date of January 1, 2013. The purchase price was $46.0 million, which was subject to customary purchase price adjustments, resulting in a final purchase price of $42.3 million. We determined that the Synergy Transaction did not represent a significant disposal of reserves, therefore our U.S. oil and gas properties were reduced by these proceeds and we did not recognize a gain.

In April 2013, we sold an undivided 25% interest in our Barnett Shale Asset to TGBR for a purchase price of $485.0 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

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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.

In December 2012, we entered into an agreement with SWEPI LP to jointly develop our oil and gas interests in the Niobrara formation of the Sand Wash Basin and to establish an Area of Mutual Interest (“AMI”) covering in excess of 850,000 acres. Each party assigned to the other a 50% working interest in the majority of its combined acreage so that each party owns a 50% interest in more than 320,000 acres and has the right to a 50% interest in any acquisition within the AMI. SWEPI paid us an equalization payment for 50% of the acreage contributed by us in excess of the acreage that SWEPI contributed. SWEPI is the operator of the majority of the jointly owned lands. Subsequently, these assets are being sold in the Southwestern Transaction described above.

4. DERIVATIVES AND FAIR VALUE MEASUREMENTS

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

	Asset Derivatives As of December 31,				Liability Derivatives As of December 31,
	2013		2012		2013		2012
	(in thousands)				(in thousands)
Level 2 inputs	$	107,395	$	207,042	$	3,448	$	959
Level 3 inputs	23,485		11,595		—		16,526
Total	$	130,880	$	218,637	$	3,448	$	17,485

The fair value of “Level 2” derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value reported by counterparties. The fair value of derivative instruments designated as “Level 3” was estimated using prices quoted in markets where 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 shorter term derivatives. The fair value of both the “Level 2” and the “Level 3” assets and liabilities are determined using a discounted cash flow model using the terms of the derivative instrument, market prices for the periods covered by the derivatives, and the credit adjusted risk-free interest rates. The “Level 3” unobservable inputs are the market prices for the estimated market values for the period from 2018 to 2021, as there is not an active market for that period of time. These unobservable inputs included within the fair value calculation range from $4.00 to $4.80 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:

	As of December 31,
	2013			2012
	(In thousands)
Balance at beginning of period	$	(4,931	)	$	150,989
Total gains (losses) for the period:
Unrealized gain on derivatives	40,398			19,451
Transfers out of Level 3	—			(180,732		)
Settlements in production revenue	—			(3,738		)
Settlements in net derivative losses	(11,982		)	(25,203		)
Unrealized gains reported in OCI	—			34,302
Balance at end of period	$	23,485		$	(4,931	)
Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date	$	41,909		$	19,451

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

Commodity Price Derivatives

As of December 31, 2013, we had natural gas and NGL swaps as follows:

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.

Effective December 31, 2012, we discontinued the use of hedge accounting. Changes in value subsequent to this date are recognized in net derivative gains (losses) in the period in which they occur. The net deferred hedge gain that was included in AOCI as of December 31, 2012 is being released into revenue from natural gas, NGL and oil production during the following periods in which we expect the underlying production to occur:

	(In thousands)
2014	$	37,084
2015	33,191
2016	13,476
2017	12,531
2018 and thereafter	$	41,443
	$	137,725

Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months would result in a gain of $25.0 million net of income taxes.

Interest Rate Derivatives

In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We received cash of $41.5 million in the settlements, including $10.7 million for interest previously accrued and earned. Upon the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain of $30.8 million as a reduction of interest expense over the lives of our senior notes due 2015 and our senior subordinated notes.

In June 2013, we repurchased substantially all our senior notes due 2015 resulting in early recognition of the previously deferred gain of $8.3 million. During 2013 and 2012, we recognized $12.0 million and $5.1 million, respectively, of those deferred gains as a reduction of interest expense. The remaining $4.8 million deferral of the 2010 early settlements from the senior subordinated notes interest rate swaps will continue to be recognized as a reduction of interest expense over the life of those instruments currently scheduled as follows:

	(In thousands)
2014	2,039
2015	2,194
2016	569
	$	4,802

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Fair Value Disclosures

The estimated fair value of all of our derivative instruments at December 31, 2013 and 2012 were as follows:

	Asset Derivatives				Liability Derivatives
	As of December 31,				As of December 31,
	2013		2012		2013		2012
	(In thousands)				(In thousands)
Derivatives not designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	60,063	$	113,367	$	2,540	$	—
Noncurrent derivative assets	105,315		107,542		31,958		2,272
Current derivative liabilities	—		—		3,125		—
Noncurrent derivative liabilities	—		92		323		17,577
Total derivatives not designated as hedges	$	165,378	$	221,001	$	37,946	$	19,849

Derivative assets and liabilities shown in the table above are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in the accompanying consolidated balance sheets. The change in carrying value of our commodity price derivatives since December 31, 2012 principally resulted from the overall increase in market prices for natural gas relative to the prices in our open derivative instruments, offset by settlements during the period.

The changes in the carrying value of our derivatives accounted for as hedges for 2012 are presented below:

	For the Year Ended December 31, 2012
	Commodity Hedges
	(In thousands)
Derivative fair value at beginning of period	$	342,799
Settlements in production revenue	(176,084		)
Settlements in net derivative gains	(3,820		)
Ineffectiveness reported in net derivative gains	1,281
Unrealized gains reported in OCI	107,112
Derecognition of hedge	(271,288		)
Derivative fair value at end of period	$	—

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Investments

We hold certain short-term marketable securities related to interest bearing time deposits and commercial paper. We classify our marketable securities within “Level 2.” 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 2013 and do not anticipate selling or transferring these investments before their maturity date. At December 31, 2013, we had the following marketable securities:

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

We had no marketable securities at December 31, 2012.

Financial instruments not carried at fair value

Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheet as of December 31, 2013 and December 31, 2012 are included in Note 11.

5. ACCOUNTS RECEIVABLE

Accounts receivable consisted of the following:

	As of December 31,
	2013			2012
	(In thousands)
Accrued production revenue	$	34,785		$	49,762
Joint interest billings	15,630			10,957
Income taxes	7,931			—
Canadian value added taxes	60			172
NGL hedge settlement accrual	—			3,149
Other	328			160
Allowance for doubtful accounts	(89		)	(51		)
	$	58,645		$	64,149

6. OTHER CURRENT ASSETS

Other current assets consisted of the following:

	As of December 31,
	2013		2012
	(In thousands)
Inventories	$	18,334	$	21,454
Deposits	1,044		513
Other prepaid expense	2,968		3,079
	$	22,346	$	25,046

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7. INVESTMENT IN BBEP

Since December 31, 2011 we own no BBEP Units. We recognized gains of $217.9 million for the year ended December 31, 2011 as other income for the difference between our weighted average carrying value of $3.51 per BBEP Unit and the net sales proceeds.

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

	For the Twelve Months Ended September 30, 2011
	(in thousands)
Revenue (1)	$	425,386
Operating expense	313,388
Operating income	111,998
Interest and other (2)	40,759
Income tax (benefit) expense	1,070
Noncontrolling interests	183
Net income available to BBEP	$	69,986
Net income available to common unitholders	$	69,986

⁽¹⁾  For the twelve months ended September 30, 2011, unrealized gains of $24.0 million on commodity derivatives were recognized.

⁽²⁾  The twelve months ended September 30, 2011 included $3.3 million for unrealized gains on interest rate swaps.

8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	As of December 31,
	2013			2012
	(In thousands)
Oil and gas properties
Subject to depletion	$	5,687,557		$	5,770,913
Unevaluated costs	221,605			307,267
Accumulated depletion	(5,268,719		)	(5,297,220		)
Net oil and gas properties	640,443			780,960
Other property and equipment
Pipelines and processing facilities	347,093			375,248
General properties	72,125			75,147
Accumulated depreciation	(198,856		)	(202,297		)
Net other property and equipment	220,362			248,098
Property, plant and equipment, net of accumulated depletion and depreciation	$	860,805		$	1,029,058

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Ceiling Test Analysis and Impairment

The charges for impairment are summarized below:

		Pre-tax Charges for Impairment
	Segment	2013		2012		2011
		(in thousands)
U.S.
Oil and gas properties	Exploration and production	$	—	$	2,152,128	$	—
Other property and equipment	Midstream	54		7,328		57,996
Other property and equipment	Exploration and production	1,809		537		—
Canada
Oil and gas properties	Exploration and production	—		465,935		49,063
		$	1,863	$	2,625,928	$	107,059

As described in Note 2, we are required to perform a quarterly ceiling test for impairment of our oil and gas properties in each of our cost centers. We did not recognize impairment in 2013 during our quarterly ceiling tests. We did recognize other property and equipment impairment charges in 2013 for surface land and pipeline in Texas.

In 2012, we recognized impairment expense each quarter as the average of the first of month prices for the preceding 12 months declined each quarter. For our U.S. oil and gas properties, the Henry Hub price declined 33% from the price used at December 31, 2011 and the pricing used for NGLs declined 28% from the price used at December 31, 2011. For our Canadian oil and gas properties, the AECO price declined 36% from the price used at December 31, 2011. In 2012, the impairment on our oil and gas properties in both the U.S. and Canada was impacted by the exclusion of our derivatives from the ceiling test due to the discontinuance of hedge accounting. Other property and equipment impairment charges during 2012 were a result of reduced anticipated utilization of pipelines and facilities in Colorado and Texas and reduced use of a compressed natural gas facility in Texas.

The charge for impairment of our oil and gas properties in Canada in 2011 was recognized as a result of a 12% decrease in AECO natural gas price utilized in our Canadian ceiling test from December 31, 2010 to March 31, 2011.

We also recognized an impairment charge of $58.0 million in 2011 related to certain Barnett Shale midstream assets to reduce their carrying value to estimated fair value as a result of decreased development by us and others in response to decreased natural gas prices during the fourth quarter of 2011.

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Unevaluated Natural Gas and Oil Properties Not Subject to Depletion

Under full cost accounting, we may exclude certain unevaluated property costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties not subject to depletion at December 31, 2013 and 2012 and the year in which they were incurred follows:

	December 31, 2013 Costs Incurred During										December 31, 2012 Costs Incurred During
	2013		2012		2011		Prior		Total		2012		2011		2010		Prior		Total
	(In thousands)										(In thousands)
U.S.
Acquisition costs	$	—	$	3,013	$	13,484	$	—	$	16,497	$	6,844	$	42,339	$	1,447	$	32,429	$	83,059
Exploration costs	14		364		—		—		378		2,676		207		—		—		2,883
Capitalized interest	1,093		1,374		—		—		2,467		4,093		—		—		—		4,093
Total U.S.	$	1,107	$	4,751	$	13,484	$	—	$	19,342	$	13,613	$	42,546	$	1,447	$	32,429	$	90,035
Canada
Acquisition costs	$	—	$	2,956	$	1,300	$	68,586	$	72,842	$	333	$	—	$	643	$	80,488	$	81,464
Exploration costs	$	7,044	$	31,746	$	41,092	$	30,413	$	110,295	$	36,356	$	44,837	$	18,500	$	20,171	$	119,864
Capitalized interest	$	3,947	$	2,724	$	3,522	$	8,933	$	19,126	$	2,796	$	3,614	$	2,830	$	6,664	$	15,904
Total Canada	$	10,991	$	37,426	$	45,914	$	107,932	$	202,263	$	39,485	$	48,451	$	21,973	$	107,323	$	217,232
Total	$	12,098	$	42,177	$	59,398	$	107,932	$	221,605	$	53,098	$	90,997	$	23,420	$	139,752	$	307,267

The following table summarizes the regions where we have unevaluated property costs not subject to depletion.

	As of December 31,
	2013		2012
	(In thousands)
Barnett Shale	$	—	$	40,716
West Texas	19,343		49,318
Horn River Basin	202,262		217,233
Total	$	221,605	$	307,267

Costs are transferred into the amortization base on an ongoing basis, as projects are evaluated and proved reserves established or impairment determined. Pending determination of proved reserves attributable to the above costs, we cannot assess the future impact on the amortization rate. Unevaluated acquisition costs in our Horn River Asset will require up to an estimated nine more years of exploration and development activity before evaluation is complete, which is covered by the remaining primary term of the underlying leases. Unevaluated acquisition costs in our West Texas Asset will require up to an estimated three more years of exploration and development activity before evaluation is complete, which is covered by the remaining primary term and the renewal term of the underlying leases.

Other Matters

Capitalized overhead costs that directly relate to exploration and development activities were $13.6 million, $16.8 million and $18.3 million for 2013, 2012 and 2011, respectively. For 2013, depletion per Mcfe was $0.51 and $0.14 for the U.S. and Canada, respectively. For 2012, depletion per Mcfe was $1.14 and $0.83 for the U.S. and Canada, respectively. For 2011, consolidated depletion per Mcfe was $1.35. Depreciation expense was $17.1 million, $18.6 million and $20.3 million for 2013, 2012 and 2011, respectively.

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9. OTHER ASSETS

Other assets consisted of the following:

	As of December 31,
	2013			2012
	(In thousands)
Deferred financing costs	$	84,951		$	59,059
Less accumulated amortization	(50,171		)	(27,335		)
Net deferred financing costs	34,780			31,724
Governmental and notes receivable	6,464			7,385
Other	360			838
	$	41,604		$	39,947

Costs related to the acquisition of debt are deferred and amortized over the term of the debt.

10. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:

	As of December 31,
	2013		2012
	(In thousands)
Interest payable	$	38,260	$	67,116
Accrued operating expense	37,747		38,733
Prepayments from partners	425		—
Revenue payable	22,589		21,013
Accrued state income and franchise taxes	1,080		1,183
Accrued production and property taxes	870		609
Environmental liabilities	36		122
Accrued product purchases	270		336
Current asset retirement obligations	433		577
Other	1,140		971
	$	102,850	$	130,660

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11. LONG-TERM DEBT

Long-term debt consisted of the following:

	As of December 31,
	2013		2012
	(In thousands)
Combined Credit Agreements	$	211,200	$	388,150
Second Lien Term Loan, net of unamortized discount of $17,428	607,572		—
Second Lien Notes due 2019, net of unamortized discount of $5,577	194,423		—
Senior notes due 2015, net of unamortized discount of $30 and $2,149	10,472		435,851
Senior notes due 2016, net of unamortized discount of $105 and $10,825	8,044		579,795
Senior notes due 2019, net of unamortized discount of $4,757 and $5,378	293,243		292,622
Senior notes due 2021, net of unamortized discount of $15,810	309,190		—
Senior subordinated notes due 2016	350,000		350,000
Total debt	1,984,144		2,046,418
Unamortized deferred gain—terminated interest rate swaps	4,802		16,788
Long-term debt	$	1,988,946	$	2,063,206

Maturities are as follows:

	2014	2015	2016	2017	2018	Thereafter
	(in thousands)
Combined Credit Agreements	—	—	211,200	—	—	—
Second Lien Term Loan	—	—	—	—	—	625,000
Second Lien Notes due 2019	—	—	—	—	—	200,000
Senior notes due 2015	—	10,502	—	—	—	—
Senior notes due 2016	—	—	8,149	—	—	—
Senior notes due 2019	—	—	—	—	—	298,000
Senior notes due 2021	—	—	—	—	—	325,000
Senior subordinated notes due 2016	—	—	350,000	—	—	—
Total Indebtedness	—	10,502	569,349	—	—	1,448,000

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 earliest 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 exceeds $100 million. The table above does not reflect these accelerated maturities. We believe we have and will have sufficient liquidity and capital resources to defer these springing maturities until at least the last half of 2015.

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 December 31, 2013. At December 31, 2013, we had $97.6 million available under the Combined Credit Agreements, all of which could be used for letters of credit.

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

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

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

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

• Permit up to $825 million of second lien debt

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

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

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

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

• Amend certain definitions which impact the financial covenant calculations.

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

Our ability to remain in compliance with covenants in our Combined Credit Agreements may be affected by events beyond our control, including market prices for our products. Any future inability to comply with these covenants, unless waived or amended by the requisite lenders, could adversely affect our liquidity by rendering us unable to borrow further under our credit facilities and by accelerating the maturity of our indebtedness. Note 1 contains additional information regarding our ability to comply with our financial covenants.

Debt Refinancing

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

Second Lien Term Loan

In June 2013, we entered into a $625 million six-year Second Lien Term Loan which is a secured senior obligation of Quicksilver. The loans thereunder were made at 97% of par, which resulted in net proceeds of $606.3 million. The Second Lien Term Loan has a variable annual interest rate based on adjusted LIBOR (as defined in the Second Lien Term Loan, which is subject to a floor of 1.25%) plus an applicable margin of 5.75% or Alternate Base Rate (as defined in the Second Lien Term Loan, which is subject to a floor of 2.25%) plus an applicable margin of 4.75%.

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Second Lien Notes due 2019

In June 2013, we issued $200 million of Second Lien Notes due 2019 which are secured senior obligations of Quicksilver. The notes were issued at 97% of par, which resulted in net proceeds of $194 million. The Second Lien Notes have a variable annual interest rate based on LIBOR (as defined in the indenture governing the Second Lien Notes due 2019, which is subject to a floor of 1.25%) plus an applicable margin of 5.75%. Interest is payable on the last day of each quarter.

Senior Notes Due 2015

In June 2008, we issued $475 million of senior notes due 2015, which are unsecured senior obligations of Quicksilver. The notes were issued at 98.66% of par. Interest at the rate of 8.25% is payable semiannually on February 1 and August 1.

In June 2013, we made a cash tender offer and consent solicitation for the Senior Notes due 2015 at a price of $1,027.90 plus interest of $32.08 per $1,000 outstanding. We accepted and paid for all validly tendered notes, representing $425.2 million of the then outstanding $438.0 million, which resulted in an aggregate payment of $450.7 million for such repurchase. We also entered into a supplemental indenture to eliminate substantially all of the restrictive covenants and certain events of default with respect to such notes. Subsequent to the June tender offer and consent solicitation, we have repurchased an additional $2.3 million aggregate principal amount of the Senior Notes due 2015.

Senior Notes Due 2016

In June 2009, we issued $600 million of senior notes due 2016, which are unsecured senior obligations of Quicksilver. The notes were issued at 96.72% of par, which resulted in proceeds of $580.3 million that were used to repay a portion of debt. Interest at the rate of 11.75% is payable semiannually on January 1 and July 1.

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

Senior Notes Due 2019

In August 2009, we issued $300 million of senior notes due 2019, which are unsecured senior obligations of Quicksilver. The notes were issued at 97.61% of par, which resulted in proceeds of $292.8 million that were used to repay a portion of our 2007 Senior Secured Credit Facility. Interest at the rate of 9.125% is payable semiannually on February 15 and August 15.

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

Senior Notes due 2021

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

Senior Subordinated Notes

In 2006, we issued $350 million of senior subordinated notes due 2016. The senior subordinated notes are unsecured senior subordinated obligations of Quicksilver. Interest at the rate of 7.125% is payable semiannually on April 1 and October 1.

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Indenture Restrictions

We have an incurrence test under our indentures applicable to debt, restricted payments, mergers and consolidations and designation of unrestricted subsidiaries that requires EBITDA to exceed interest expense by 2.25 times. At December 31, 2013, we did not meet this test and, as a result, we are limited in our ability to, among other things, incur additional debt, except for specific baskets. We do retain, however, the ability to utilize the full borrowing capacity under our Combined Credit Agreements and to refinance existing debt. Not meeting this ratio does not represent an event of default under our debt. We cannot predict when or if we will meet the incurrence test.

We retained a portion of cash received from our 2013 asset sales. Our indentures require us to reinvest or repay senior debt with net cash proceeds from asset sales 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, but may also repay a portion of our senior indebtedness.

Interest Expense

Interest expense was $251.8 million and $164.1 million, net of capitalized interest of $7.7 million and $18.4 million, for the years ended December 31, 2013 and 2012, respectively.

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Summary of All Outstanding Debt

The following table summarizes certain significant aspects of our long-term debt outstanding at December 31, 2013:

	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 (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 December 31, 2013 (4)	3.95%		7.00%	7.00%	8.25%	11.75%	9.125%	11.00%		7.125%
Base interest rate options (5)(6)	LIBOR, ABR, CDOR		LIBOR floor of 1.25%; ABR floor of 2.25%	LIBOR floor of 1.25%	N/A	N/A	N/A	N/A		N/A
Financial covenants (7)	- Minimum current ratio of 1.0 - Minimum EBITDA to cash interest expense ratio of 1.10 - 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 (7)	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions - Limitations on derivatives and investments		- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Asset sales	- Asset sales	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions		- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions
Optional redemption (7)	Any time		Any time, subject to re-pricing event June 21, 2014: 102 2015: 101	Any time, subject to re-pricing event June 21, 2014: 102 2015: 101	August 1, 2013: 101.938 2014: par	July 1, 2013: 105.875 2014: 102.938 2015: par	August 15, 2014: 104.563 2015: 103.042 2016: 101.521 2017: par	July 1, 2019: 102.000 2020: par		April 1, 2013: 101.188 2014: par
Make-whole redemption (7)	N/A		N/A	N/A	N/A	N/A	Callable prior to August 15, 2014 at make-whole call price of Treasury +50 bps	Callable prior to July 1, 2019 at make-whole call price of Treasury +50 bps		N/A
Change of control (7)	Event of default		Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest		Put at 101% of principal plus accrued interest
Equity clawback (7)	N/A		N/A	N/A	N/A	N/A	N/A	Redeemable until July 1, 2016 at 111.00%, plus accrued interest for up to 35%		N/A
Estimated fair value (8)	$211.2 million		$625 million	$200 million	$10.6 million	$7.8 million	$298 million	$354.3 million		$341.3 million

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

⁽²⁾ The principal amount for the Combined Credit Agreements represents the global borrowing base as of December 31, 2013.

⁽³⁾ The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the 2015 Senior Notes, the 2016 Senior Notes, the 2016 Senior Subordinated Notes, the 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%.

⁽⁷⁾ The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions and related definitions contained in the documents governing the various components of our debt.

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⁽⁸⁾ 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).

12. ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated asset retirement obligation from January 1, 2012 through December 31, 2013.

	As of December 31,
	2013			2012
	(In thousands)
Beginning asset retirement obligations	$	116,526		$	85,822
Additional liability incurred	3,922			4,072
Change in estimates	7,582			21,080
Accretion expense	5,109			4,122
Asset retirement costs incurred	(1,560		)	(1,846		)
Settlement of liability in excess of obligation recorded	742			2,229
Disposition	(21,935		)	—
Currency translation adjustment	(3,697		)	1,047
Ending asset retirement obligations	106,689			116,526
Less current portion	(433		)	(577		)
Long-term asset retirement obligation	$	106,256		$	115,949

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13. INCOME TAXES

Significant components of our deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows:

	As of December 31,
	2013			2012
	(In thousands)
Deferred tax assets:
Property, plant and equipment	$	209,134		$	483,771
Net operating loss carry-forwards	183,982			109,100
Investment in Fortune Creek	3,763			3,763
AMT tax credit	47,883			55,814
Settlements of interest rate swaps	1,681			5,876
Deferred compensation expense	11,711			11,141
State	3,680			—
Other	791			2,710
Deferred tax assets	462,625			672,175
Deferred tax liabilities:
Net derivative gains	(44,039		)	(73,195		)
Other	(991		)	—
Deferred tax liabilities	(45,030		)	(73,195		)
Net deferred tax asset (liability)	417,595			598,980
Valuation allowance	(417,595		)	(598,980		)
Total deferred tax asset (liability)	$	—		$	—
Reflected in the consolidated balance sheets as:
Current deferred income tax liability	$	—		$	—
Non-current deferred income tax liability	—			—
	$	—		$	—

The components of net income (loss) before income tax for 2013, 2012 and 2011 are as follows:

	2013			2012			2011
				(In thousands)
U.S.	$	184,034		$	(2,142,730	)	$	146,090
Canada	(7,866		)	(505,446		)	1,819
Total	$	176,168		$	(2,648,176	)	$	147,909

No rate changes occurred in any taxing jurisdiction for 2011 or 2012. For 2013 and beyond, we have utilized a rate of 25.2% in Canada and a federal rate of 35% and a state rate of 1% in the U.S. to value our deferred tax positions, with the U.S. federal and state future rates mirroring existing applicable rates.

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The components of income tax expense for 2013, 2012 and 2011 are as follows:

	2013			2012			2011
				(In thousands)
Current state income tax expense (benefit)	$	900		$	1,752		$	(1,706	)
Current U.S. federal income tax expense (benefit)	(7,931		)	—			(5,565		)
Current Canadian income tax expense	—			—			642
Total current income tax expense (benefit)	(7,031		)	1,752			(6,629		)
Deferred U.S. federal income tax expense (benefit)	205,820			(763,639		)	58,890
U.S. federal valuation allowance expense	(186,713		)	533,974			—
Deferred state income tax expense (benefit)	(3,680		)	—			1,980
State valuation allowance expense	3,680			—			—
Deferred Canadian income tax expense (benefit)	827			(128,982		)	3,622
Canadian valuation allowance expense	1,647			61,325			—
Total deferred income tax expense (benefit)	21,581			(297,322		)	64,492
Total income tax expense (benefit)	$	14,550		$	(295,570	)	$	57,863

The following table reconciles the statutory federal income tax rate to the effective tax rate for 2013, 2012 and 2011:

	2013		2012		2011
U.S. federal statutory tax rate	35.00	%	35.00	%	35.00	%
Permanent differences	4.80	%	(0.06	)%	1.51	%
State income taxes net of federal deduction	0.31	%	(0.04	)%	0.12	%
Canadian income taxes	(0.26	)%	(1.93	)%	2.41	%
Other	(0.15	)%	0.67	%	0.08	%
Derivatives deferred in OCI	12.43	%	—	%	—	%
Valuation allowance	(43.87	)%	(22.48	)%	—	%
Effective income tax rate	8.26	%	11.16	%	39.12	%

As of December 31, 2012, we had net operating tax loss carry-forwards for federal tax purposes of $340 million. During the year ended December 31, 2013, we generated additional net operating losses of $185 million. The total $525 million is included in deferred tax assets, and will expire between 2029 and 2033. The net operating loss carry-forwards can be used to offset future taxable income. As of December 31, 2013, we have $48 million of alternative minimum tax credit carry-forwards to offset any future alternative minimum tax payments, which have no expiration.

The deferred tax expense in 2013 is principally composed of the reversal in 2013 of deferred tax liabilities related to hedging in other comprehensive income that had previously reduced the valuation allowance necessary. During 2013, we reduced the U.S. federal deferred tax asset and corresponding valuation allowance by $187 million primarily due to the recognition of a deferred tax liability related to the Tokyo Gas Transaction. We also established a U.S. state valuation allowance of $3.7 million. The Canadian valuation allowance increased by $1.6 million primarily due to permanent items related to nondeductible expenses. Additionally, our basis in the Fortune Creek Partnership exceeds book basis by $29 million. We expect to realize the deferred tax asset related to this balance only through the partnership’s sale at which time the transaction will be treated as a capital transaction under Canadian tax law, taxed at the Canadian statutory rate of 12.5% for capital gains. We believe that it is more likely than not that we will be unable to realize the benefit of this deferred tax asset. Accordingly in 2011, we recorded a full valuation allowance of $3.7 million for this item.

We file or have filed income tax returns in U.S. federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. We currently have no open audits. Tax years after December 31, 2009 remain subject to audit by the IRS.

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The following schedule reconciles the total amounts of unrecognized tax benefits for 2012:

	As of  December 31,
	2013		2012
	(In thousands)
Beginning unrecognized tax benefits	$	—	$	9,219
Changes	—		(9,219		)
Ending unrecognized tax benefits	$	—	$	—

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

14. COMMITMENTS AND CONTINGENCIES

Contractual Obligations

Information regarding our contractual obligations, at December 31, 2013, is set forth in the following table:

	GPT     Contracts (1)		Drilling Rig     Contracts (2)		Operating     Leases (3)		Purchase     Obligations (4)
	(In thousands)
2014	$	86,628	$	4,240	$	3,912	$	3,071
2015	85,043		—		3,994		220
2016	81,803		—		4,123		—
2017	78,326		—		4,070		—
2018	65,860		—		4,043		—
Thereafter	140,624		—		12,996		—
Total	$	538,284	$	4,240	$	33,138	$	3,291

⁽¹⁾  Under contracts with various third parties, we are obligated to provide minimum daily natural gas volume for gathering, processing, fractionation and transportation, as determined on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our gathering and transportation contracts with CMLP have no minimum volume requirement and, therefore, are not reported in the above amounts.

⁽²⁾  We lease drilling rigs from third parties for use in our development and exploration programs. The outstanding drilling rig contract requires payment of a specified day rate of $20,000 for the entire lease term regardless of our utilization of the drilling rigs.

⁽³⁾  We lease office buildings and other property under operating leases. Rent expense for operating leases with terms exceeding one month was $3.6 million in 2013, $4.2 million in 2012 and $4.8 million in 2011. Minimum payments have not been reduced by minimum sublease rentals of $2.2 million due in the future under noncancelable subleases.

⁽⁴⁾  At December 31, 2013, we were under contract to purchase goods and services for use in field and gas plant operations.

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Commitments and Contingencies

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

At December 31, 2013, we had $6.6 million in surety bonds issued to fulfill contractual, legal or regulatory requirements and $41.2 million in letters of credit outstanding against the credit facility. Surety bonds and letters of credit generally have an annual renewal option.

As a result of our partial working interest sale to Eni in 2009, we entered into a joint development agreement with Eni. The joint development agreement includes a schedule of wells that we agreed to drill and complete with participation by Eni during the development period. In connection with the scheduled drilling of these wells, we committed to drill and complete a minimum number of lateral feet each year and Eni agreed to pay us a turnkey drilling and completion cost per linear foot attributable to Eni. At December 31, 2013 we mutually agreed to end the turnkey drilling and completion provisions within the joint development agreement and both parties are responsible for their respective working interest percentage for drilling and completing activity on joint development wells.

In July 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arose 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.

In December 2012, Vantage Fort Worth Energy LLC (“Plaintiff”) served a lawsuit against us and others in the 352nd Judicial District Court of Texas in Tarrant County asserting claims for trespass to try title, suit to quiet title, trespass and conversion. On May 8, 2013, all parties to the suit entered into a settlement agreement, effective April 1, 2013, whereby we assigned to Plaintiff various property and equipment and Plaintiff agreed to non-suit all of the Defendants in the matter. The court entered its Order of Dismissal with prejudice on May 13, 2013. We recognized an expense of $3.3 million in connection with this settlement.

We are subject to various proceedings and claims that arise in the ordinary course of business. While many of these matters involve inherent uncertainty, we believe, individually or in the aggregate, such matters will not have a material adverse impact on our financial position, results of operations or cash flows. Because of the uncertainty, our assessment may change in the future. If an unfavorable final outcome were to become probable or occur, it may have a material impact on our financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable.

Environmental Compliance

Our operations are subject to stringent, complex and changing laws and regulations pertaining to health, safety and the environment. As an owner, lessor or operator of our facilities, we are subject to laws and regulations at the federal, state, provincial and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities incorporates compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At December 31, 2013, we had recorded less than $0.1 million for liabilities for environmental matters.

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15. FORTUNE CREEK

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

In forming Fortune Creek, our Canadian subsidiary contributed an existing 20-mile, 20-inch gathering line and its related compression facilities and committed to minimum gross capital expenditures of $300 million for drilling and completion activities in our Horn River Asset between 2012 and 2014. In March 2014, we agreed with KKR to an amendment to extend the ending date 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. We have incurred $180 million as of December 31, 2013. The costs to be incurred under the spending requirement generally reflect the gross capital expenditures of all working interests in the well for wells in which we have a working interest regardless of our working interest percentage; therefore, following a transaction involving our Horn River Asset, we may not have to fully fund the remaining obligation. To the extent these minimum capital expenditure commitments are not met, we will incur a cash penalty in an amount equal to the shortfall, which will be applied against the gathering agreement requirement. 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 $0.13 per Mcf until at least 2016.

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

The firm gathering agreement with Fortune Creek is guaranteed by us. With the amendment, signed in March 2014, 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. 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, since May 2012.

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

Note 18 contains financial information for Fortune Creek in our condensed consolidating financial statements.

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16. 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 December 31, 2013, we had 177.3 million shares of common stock outstanding.

The following table shows common share and treasury share activity since January 1, 2011:

	Common     Shares Issued	Treasury     Shares Held
Balance at January 1, 2011	175,524,816	5,050,450
Stock options exercised	209,221	—
Restricted stock activity	1,246,446	329,252
Balance at December 31, 2011	176,980,483	5,379,702
Stock options exercised	1,572	—
Restricted stock activity	2,033,063	541,400
Balance at December 31, 2012	179,015,118	5,921,102
Stock options exercised	—	—
Restricted stock activity	4,979,761	777,538
Balance at December 31, 2013	183,994,879	6,698,640

Quicksilver Stockholder Rights Plan

In 2003, our Board of Directors declared a dividend distribution of one preferred share purchase right for each share of common stock then outstanding. Pursuant to the amendments entered into on March 8, 2013, each right, when it becomes exercisable, entitles stockholders to buy one one thousandth of a share of Quicksilver’s Series A Junior Participating Preferred Stock at an exercise price of $10, subject to customary anti-dilution adjustments.

The rights will be exercisable only if such a person or group acquires 15% or more of our common stock or announces a tender offer the consummation of which would result in ownership by such a person or group (an “Acquiring Person”) of 15% or more of our common stock. This 15% threshold does not apply to certain members of the Darden family and affiliated entities (the "Darden Entities"), which collectively owned, directly or indirectly, approximately 30% of our common stock at February 28, 2014, so long as the Darden Entities do not acquire beneficial ownership of additional shares of our common stock, subject to certain exceptions and subject to the Darden Entities, collectively, being able to acquire additional shares of common stock to maintain the Darden Entities' collective percentage ownership in us.

If an Acquiring Person acquires 15% or more of our outstanding common stock (or any Darden Entity exceeds the thresholds applicable to the Darden Entities), each right (other than the rights of the Acquiring Person, including, if applicable, the Darden Entities) will entitle its holder to purchase, at the right's then-current exercise price, a number of our common shares having a market value of twice such price. If we are acquired in a merger or other business combination transaction after an Acquiring Person has acquired 15% or more of our outstanding common stock (or any Darden Entity has exceeded the thresholds applicable to the Darden Entities), each right (other than the rights of the Acquiring Person, including, if applicable, the Darden Entities) will entitle its holder to purchase, at the right's then-current exercise price, a number of the acquiring company's common shares having a market value of twice such price.

Prior to the acquisition by an Acquiring Person of beneficial ownership of 15% or more of our common stock (or any Darden Entity exceeds the thresholds applicable to the Darden Entities), the rights are redeemable for $0.01 per right at the option of our Board of Directors.

The rights plan will expire by its terms on March 11, 2016.

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Stock-Based Compensation

2006 Equity Plan

In 2006, our Board of Directors and our stockholders approved the 2006 Equity Plan, under which 14 million shares of common stock were reserved for issuance as grants of stock options, appreciation rights, restricted shares, restricted stock units, performances shares, performance units and senior executive plan bonuses. In May 2009, our stockholders approved an amendment to the 2006 Equity Plan, which increased the number of shares available for issuance after such date to 15 million. On May 15, 2013, our stockholders approved an amendment to the 2006 Equity Plan, which increased the shares available for issuance under the plan by 12 million shares. Our executive officers, other employees, consultants and non-employee directors are eligible to participate in the 2006 Equity Plan. Options reflect an exercise price of no less than the fair market value on the date of grant and have a term that expires ten years from the date of grant. At December 31, 2013 and 2012, 15.4 million shares and 9.7 million shares, respectively, were available for issuance under the 2006 Equity Plan.

Stock Options

The following summarizes the values from and assumptions for the Black-Scholes option pricing model:

	2013	2012	2011
Weighted average grant date fair value	$1.05	$4.21	$9.16
Weighted average risk-free interest rate	1.31%	1.14%	2.38%
Expected life	4.9 years	6.0 years	6.0 years
Weighted average volatility	68.97%	68.20%	66.77%
Expected dividends	—	—	—

The following table summarizes our stock option activity for 2013:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
					(In years)	(In thousands)
Outstanding at January 1, 2013	4,979,980		$	10.23
Granted	2,037,467		1.95
Exercised	—		—
Canceled	(85,004	)	6.63
Expired	(160,865	)	8.86
Outstanding at December 31, 2013	6,771,578		$	7.82	6.4	$	—
Exercisable at December 31, 2013	4,576,677		$	9.30	5.3	$	—

We estimate that a total of 6.3 million stock options will become vested including those options already exercisable. The unexercised options have a weighted average exercise price of $8.24 and a weighted average remaining contractual life of 6.2 years.

As of December 31, 2013 the unrecognized compensation cost related to outstanding unvested options was $2.1 million, which is expected to be recognized in expense through August 2016. Compensation expense related to stock options of $3.9 million, $7.4 million and $7.0 million was recognized for 2013, 2012 and 2011, respectively. The income tax benefit recognized in income, prior to any tax valuation allowance consideration, related to this compensation expense during 2013 and 2012 was $1.3 million and $2.4 million, respectively. The total intrinsic value of options exercised during 2012 and 2011 was $0.1 million and $1.2 million, respectively. No options were exercised in 2013.

98

Restricted Stock and Stock Units

The following table summarizes our restricted stock and stock unit activity for 2013:

	Payable in shares				Payable in cash
	Shares		Weighted Average Grant Date Fair Value		Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2013	3,099,135		$	8.48	678,217		$	7.71
Granted	6,511,441		2.76		1,483,306		2.81
Vested	(2,524,332	)	6.69		(284,406	)	8.51
Canceled	(1,418,154	)	3.68		(304,776	)	3.86
Outstanding at December 31, 2013	5,668,090		$	3.90	1,572,341		$	3.69

As of December 31, 2013, the unrecognized compensation cost related to outstanding unvested restricted stock and RSUs was $13.3 million, which is expected to be recognized through December 2016. Grants of restricted stock and RSUs during 2013 had an estimated grant date fair value of $22.1 million. The fair value of RSUs to be settled in cash was $4.8 million and $1.9 million during 2013 and 2012, respectively. For 2013, 2012 and 2011, compensation expense related to restricted stock and RSUs of $16.8 million, $15.7 million and $13.9 million, respectively, was recognized. The income tax benefit recognized in income, prior to any tax valuation allowance consideration, related to this compensation expense was $5.2 million during each of 2013 and 2012. The total fair value of shares vested during 2013, 2012 and 2011 was $7.1 million, $16.3 million and $13.6 million, respectively.

In 2013, we recognized $2.4 million in stock-based compensation to correct for assumptions on forfeitures and vesting for retirement eligible and imminently retirement eligible individuals, which pertain to periods before 2013.

Accumulated Other Comprehensive Income

At December 31, 2013, AOCI included $94.5 million, net of tax, and $15.4 million for derivatives and foreign currency translation, respectively. At December 31, 2012, AOCI included $141.4 million, net of tax, and $20.1 million for derivatives and foreign currency translation, respectively.

99

17. EARNINGS PER SHARE

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

	Years Ended December 31,
	2013			2012			2011
	(In thousands, except per share data)
Net income (loss) attributable to Quicksilver	$	161,618		$	(2,352,606	)	$	90,046
Basic income allocable to participating securities (1)	(4,252		)	—			(1,106		)
Income (loss) available to shareholders	$	157,366		$	(2,352,606	)	$	88,940
Weighted average common shares – basic	171,518			170,106			168,993
Effect of dilutive securities (2)
Share-based compensation awards	141			—			742
Weighted average common shares — diluted	171,659			170,106			169,735
Earnings (loss) per common share — basic	$	0.92		$	(13.83	)	$	0.53
Earnings (loss) per common share — diluted	$	0.92		$	(13.83	)	$	0.52

⁽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 2013, 5.6 million shares associated with our stock options and 0.2 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2012, 5.0 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2011, the effects of 9.8 million shares associated with our convertible debentures for the period outstanding were antidilutive, and 1.9 million shares associated with our stock options and 0.1 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations.

100

18. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The following tables provide information about the entities that guarantee our senior notes and senior subordinated notes. The guarantees are full and unconditional and joint and several.

Under SEC rules, we are required to present financial information segregated between our guarantor and non-guarantor subsidiaries. The indentures under both our senior notes and our senior subordinated notes distinguish between “restricted” subsidiaries and “unrestricted” subsidiaries and further specify supplemental information that is not required under GAAP. The following table illustrates our subsidiaries and their status pursuant to the senior notes due 2015, senior notes due 2016, senior notes due 2019, senior notes due 2021 and the senior subordinated notes:

Guarantor Subsidiaries - Restricted	Non-Guarantor Subsidiaries
	Restricted	Unrestricted
Cowtown Pipeline Funding, Inc.	Quicksilver Resources Canada Inc.	Makarios Resources International Holdings LLC (2)
Cowtown Pipeline Management, Inc.	Cowtown Drilling Inc. (1)	1622834 Alberta Inc. (2)
Cowtown Pipeline L.P.	Quicksilver Resources Partners Operating Ltd. (2)	Makarios Midstream Inc. (2)
Cowtown Gas Processing L.P.	0942065 B.C. Ltd. (3)	Makarios Resources International Inc. (2)
Barnett Shale Operating LLC (2)	0942069 B.C Ltd. (3)	Quicksilver Production Partners GP LLC (2)
QPP Parent LLC (3)		Quicksilver Production Partners LP (2)
QPP Holdings LLC (3)
Silver Stream Pipeline Company LLC (3)

⁽¹⁾ This entity was inactive for the three-year period ended December 31, 2013.

⁽²⁾  These entities were created in 2011.

⁽³⁾  These entities were created in 2012.

We own 100% of each of the restricted subsidiaries.

Quicksilver and the restricted subsidiaries conduct all of our exploration and production activities, and the unrestricted subsidiaries primarily conduct midstream operations. Neither the restricted non-guarantor subsidiaries nor the unrestricted non-guarantor subsidiaries guarantee the obligations under the senior notes or the senior subordinated notes.

However, the restricted non-guarantor subsidiaries, like the restricted guarantor subsidiaries, are limited in their activity by the covenants in the indentures for such matters as:

• incurring additional indebtedness;

• paying dividends;

• selling assets;

• making investments; and

• making restricted payments.

Subject to restrictions set forth in the indentures, we may in the future designate one or more additional subsidiaries as unrestricted.

The following tables present financial information about Quicksilver and our restricted subsidiaries for the annual periods covered by the consolidated financial statements. Under the indenture, Fortune Creek is not considered to be a subsidiary and therefore it is presented separately from the other subsidiaries for these purposes.

101

Condensed Consolidating Balance Sheets

	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		Consolidating 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
Quicksilver 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

102

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

103

Condensed Consolidating Statements of Income

	For the Year Ended 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		Consolidating Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
Revenue	$	416,516		$	788	$	144,258		$	—	$	561,562		$	—	$	22,364	$	(22,364	)	$	561,562
Operating expenses	329,975			346		118,481			—		448,802			—		9,808		(22,364		)	436,246
Tokyo Gas Transaction gain	339,328			—		—			—		339,328			—		—		—			339,328
Equity in net earnings of subsidiaries	(9,896		)	—		(6,682		)	9,896		(6,682		)	12,563		—		(5,881		)	—
Operating income (loss)	415,973			442		19,095			9,896		445,406			12,563		12,556		(5,881		)	464,644
Fortune Creek accretion	—			—		—			—		—			—		—		(19,245		)	(19,245		)
Interest expense and other	(242,279		)	—		(26,959		)	—		(269,238		)	—		7		—			(269,231		)
Income tax expense	(12,076		)	—		(2,474		)	—		(14,550		)	—		—		—			(14,550		)
Net income (loss)	$	161,618		$	442	$	(10,338	)	$	9,896	$	161,618		$	12,563	$	12,563	$	(25,126	)	$	161,618
Other comprehensive loss	(40,166		)	—		(11,446		)	—		(51,612		)	—		—		—			(51,612		)
Equity in OCI of subsidiaries	(11,446		)	—		—			11,446		—			—		—		—			—
Comprehensive income (loss)	$	110,006		$	442	$	(21,784	)	$	21,342	$	110,006		$	12,563	$	12,563	$	(25,126	)	$	110,006

104

	For the Year Ended December 31, 2012
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Restricted Subsidiary Eliminations			Quicksilver and Restricted  Subsidiaries			Unrestricted Non-Guarantor Subsidiaries		Fortune Creek		Consolidating Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
Revenue	$	611,477		$	4,574		$	95,887		$	(2,900	)	$	709,038		$	—	$	14,639	$	(14,639	)	$	709,038
Operating expenses	2,643,690			4,109			577,696			(2,900		)	3,222,595			—		7,940		(14,639		)	3,215,896
Crestwood earn-out	41,097			—			—			—			41,097			—		—		—			41,097
Equity in net earnings of subsidiaries	(437,510		)	—			(12,747		)	437,510			(12,747		)	6,726		—		6,021			—
Operating income (loss)	(2,428,626		)	465			(494,556		)	437,510			(2,485,207		)	6,726		6,699		6,021			(2,465,761		)
Fortune Creek accretion	—			—			—			—			—			—		—		(19,472		)	(19,472		)
Interest expense and other	(152,077		)	—			(10,914		)	—			(162,991		)	21		27		—			(162,943		)
Income tax (expense) benefit	228,097			(163		)	67,658			—			295,592			—		—		(22		)	295,570
Net income (loss)	$	(2,352,606	)	$	302		$	(437,812	)	$	437,510		$	(2,352,606	)	$	6,747	$	6,726	$	(13,473	)	$	(2,352,606	)
Other comprehensive income (loss)	(57,273		)	—			3,908			—			(53,365		)	—		—		—			(53,365		)
Equity in OCI of subsidiaries	3,908			—			—			(3,908		)	—			—		—		—			—
Comprehensive income (loss)	$	(2,405,971	)	$	302		$	(433,904	)	$	433,602		$	(2,405,971	)	$	6,747	$	6,726	$	(13,473	)	$	(2,405,971	)

105

	For the Year Ended December 31, 2011
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Consolidating Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
Revenue	$	778,741		$	4,573		$	163,864		$	(3,555	)	$	943,623
Operating expenses	603,582			64,476			156,516			(3,555		)	821,019
Equity in net earnings of subsidiaries	(40,725		)	—			—			40,725			—
Operating income (loss)	134,434			(59,903		)	7,348			40,725			122,604
Income from earnings of BBEP	(8,439		)	—			—			—			(8,439		)
Interest expense and other	39,252			18			(5,526		)	—			33,744
Income tax (expense) benefit	(75,201		)	20,960			(3,622		)	—			(57,863		)
Net income (loss)	$	90,046		$	(38,925	)	$	(1,800	)	$	40,725		$	90,046
Other comprehensive income (loss)	67,493			—			17,178			(17,178		)	67,493
Equity in OCI of subsidiaries	17,178			—			—			—			17,178
Comprehensive income (loss)	$	174,717		$	(38,925	)	$	15,378		$	23,547		$	174,717

106

Condensed Consolidating Statements of Cash Flows

	For the Year Ended December 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	$	(78,565	)	$	—	$	16,456		$	(62,109	)	$	—	$	10,409		$	(51,700	)
Capital expenditures	(67,263		)	—		(33,520		)	(100,783		)	—		(505		)	(101,288		)
Proceeds from Tokyo Gas Transaction	463,999			—		—			463,999			—		—			463,999
Proceeds from Synergy Transaction	42,297			—		—			42,297			—		—			42,297
Proceeds from sale of properties and equipment	7,128			—		43			7,171			—		—			7,171
Purchase of marketable securities	(213,738		)	—		—			(213,738		)	—		—			(213,738		)
Maturities and sales of marketable securities	47,603			—		—			47,603			—		—			47,603
Net cash flow provided by (used in) investing activities	280,026			—		(33,477		)	246,549			—		(505		)	246,044
Issuance of debt	1,215,266			—		22,086			1,237,352			—		—			1,237,352
Repayments of debt	(1,157,969		)	—		(150,413		)	(1,308,382		)	—		—			(1,308,382		)
Debt issuance costs	(26,296		)	—		—			(26,296		)	—		—			(26,296		)
Intercompany Note	(147,103		)	—		147,103			—			—		—			—
Distribution of Fortune Creek Partnership funds	—			—		—			—			—		(14,965		)	(14,965		)
Purchase of treasury stock	(1,927		)	—		—			(1,927		)	—		—			(1,927		)
Net cash flow provided by (used in) financing activities	(118,029		)	—		18,776			(99,253		)	—		(14,965		)	(114,218		)
Effect of exchange rates on cash	—			—		(1,755		)	(1,755		)	—		5,781			4,026
Net increase in cash and equivalents	83,432			—		—			83,432			—		720			84,152
Cash and equivalents at beginning of period	4,618			—		—			4,618			—		333			4,951
Cash and equivalents at end of period	$	88,050		$	—	$	—		$	88,050		$	—	$	1,053		$	89,103

107

	For the Year Ended December 31, 2012
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Quicksilver and Restricted Subsidiaries			Unrestricted Non-Guarantor Subsidiaries		Fortune Creek			Quicksilver Resources Inc. Consolidated
	(In thousands)
Net cash flow provided by operating activities	$	163,353		$	656		$	49,271		$	213,280		$	—	$	14,447		$	227,727
Capital expenditures	(231,934		)	(656		)	(242,158		)	(474,748		)	—		(10,731		)	(485,479		)
Proceeds from Crestwood earn-out	41,097			—			—			41,097			—		—			41,097
Proceeds from sale of properties and equipment	72,362			—			363			72,725			—		—			72,725
Net cash flow used in investing activities	(118,475		)	(656		)	(241,795		)	(360,926		)	—		(10,731		)	(371,657		)
Issuance of debt	228,500			—			239,459			467,959			—		—			467,959
Repayments of debt	(264,018		)	—			(46,412		)	(310,430		)	—		—			(310,430		)
Debt issuance costs	(1,972		)	—			(1,050		)	(3,022		)	—		—			(3,022		)
Distribution of Fortune Creek Partnership funds	—			—			—			—			—		(14,285		)	(14,285		)
Proceeds from exercise of stock options	11			—			—			11			—		—			11
Purchase of treasury stock	(3,144		)	—			—			(3,144		)	—		—			(3,144		)
Net cash flow provided by (used in) financing activities	(40,623		)	—			191,997			151,374			—		(14,285		)	137,089
Effect of exchange rates on cash	—			—			527			527			—		(1,881		)	(1,354		)
Net increase (decrease) in cash and equivalents	4,255			—			—			4,255			—		(12,450		)	(8,195		)
Cash and equivalents at beginning of period	363			—			—			363			—		12,783			13,146
Cash and equivalents at end of period	$	4,618		$	—		$	—		$	4,618		$	—	$	333		$	4,951

108

	For the Year Ended December 31, 2011
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Quicksilver and Restricted Subsidiaries			Fortune Creek			Consolidating Eliminations			Quicksilver Resources Inc. Consolidated
	(In thousands)
Net cash flow provided by operating activities	$	202,043		$	2,225		$	48,785		$	253,053		$	—		$	—		$	253,053
Capital expenditures	(518,454		)	(2,225		)	(169,928		)	(690,607		)	—			—			(690,607		)
Proceeds from sale of BBEP units	272,965			—			—			272,965			—			—			272,965
Investment in Fortune Creek	—			—			(12,783		)	(12,783		)	—			12,783			—
Proceeds from sale of properties and equipment	2,959			—			1,204			4,163			—			—			4,163
Net cash flow provided by (used in) investing activities	(242,530		)	(2,225		)	(181,507		)	(426,262		)	—			12,783			(413,479		)
Issuance of debt	587,500			—			268,322			855,822			—			—			855,822
Repayments of debt	(588,862		)	—			(254,246		)	(843,108		)	—			—			(843,108		)
Debt issuance costs	(9,160		)	—			(3,346		)	(12,506		)	—			—			(12,506		)
Proceeds from exercise of stock options	1,299			—			—			1,299			—			—			1,299
Partnership funds received	—			—			—			—			135,696			(12,783		)	122,913
Creation of partnership liability	—			—			122,913			122,913			(122,913		)	—			—
Purchase of treasury stock	(4,864		)	—			—			(4,864		)	—			—			(4,864		)
Net cash flow provided by (used in) financing activities	(14,087		)	—			133,643			119,556			12,783			(12,783		)	119,556
Effect of exchange rates on cash	—			—			(921		)	(921		)	—			—			(921		)
Net increase (decrease) in cash and equivalents	(54,574		)	—			—			(54,574		)	12,783			—			(41,791		)
Cash and equivalents at beginning of period	54,937			—			—			54,937			—			—			54,937
Cash and equivalents at end of period	$	363		$	—		$	—		$	363		$	12,783		$	—		$	13,146

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19. SEGMENT INFORMATION

We operate in two geographic segments, the U.S. and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. Additionally, we operate a significantly smaller midstream segment in the U.S. and Canada, where we provide natural gas gathering and processing services, primarily to our U.S. and Canadian exploration and production segments. Following the formation of our partnership with KKR, beginning in January 2012, we have additional midstream operations in Canada through Fortune Creek. Revenue earned by Fortune Creek for the gathering and processing of our gas is eliminated on a consolidated basis as is the GPT recognized by our producing properties. Based on the immateriality of our midstream segment, we have combined our U.S. and Canadian midstream information. We evaluate performance based on operating income and property and equipment costs incurred.

	Exploration & Production						Midstream									Quicksilver Consolidated
	U.S.			Canada						Corporate			Elimination
	(In thousands)
2013
Revenue	$	416,462		$	141,870		$	25,594		$	—		$	(22,364	)	$	561,562
DD&A	37,540			17,508			5,249			2,315			—			62,612
Impairment expense	1,809			—			54			—			—			1,863
Operating income (loss)	476,610			32,648			13,008			(57,622		)	—			464,644
Property and equipment costs incurred	64,976			16,838			7,055			9,792			—			98,661
2012
Revenue	$	598,892		$	105,949		$	21,735		$	—		$	(17,538	)	$	709,038
DD&A	123,370			32,686			5,182			2,386			—			163,624
Impairment expense	2,152,665			465,935			7,328			—			—			2,625,928
Operating income (loss)	(1,921,073		)	(474,768		)	8,163			(78,083		)	—			(2,465,761		)
Property and equipment costs incurred	189,997			174,867			18,742			6,850			—			390,456
2011
Revenue	$	806,657		$	135,948		$	4,573		$	—		$	(3,555	)	$	943,623
DD&A	171,438			47,116			4,889			2,320			—			225,763
Impairment expense	—			49,063			57,996			—			—			107,059
Operating income (loss)	251,495			12,914			(59,903		)	(81,902		)	—			122,604
Property and equipment costs incurred	487,145			131,699			64,119			11,516			—			694,479
Property, plant and equipment—net
December 31, 2013	$	451,840		$	306,423		$	97,118		$	5,424		$	—		$	860,805
December 31, 2012	614,071			294,921			111,523			8,543			—			1,029,058
Total assets
December 31, 2013	$	895,388		$	359,951		$	108,963		$	5,424		$	—		$	1,369,726
December 31, 2012	784,104			371,532			217,609			8,543			—			1,381,788

110

20. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Years Ended December 31,
	2013		2012			2011
	(In thousands)
Interest, net of capitalized interest	$	254,901	$	154,663		$	170,814
Income taxes	833		(20,682		)	(4,249		)

Other significant non-cash transactions are as follows:

	Years Ended December 31,
	2013		2012		2011
	(In thousands)
Working capital related to capital expenditures	$	10,324	$	10,939	$	107,586
Note receivable received for sale of land and building	—		—		5,300

21. EMPLOYEE BENEFITS

Quicksilver has a 401(k) retirement plan available to all U.S. full time employees who are at least 21 years of age. We make matching contributions and a fixed annual contribution and have the ability to make discretionary contributions to the plan. Expense associated with company contributions was $1.8 million, $2.3 million and $2.3 million for 2013, 2012 and 2011, respectively.

We have a retirement plan available to all Canadian employees. The plan provides for a match of employees’ contributions by us and a fixed annual contribution. Expense associated with company contributions for 2013, 2012 and 2011 was $0.7 million, $0.7 million and $0.8 million, respectively.

We maintain a self-funded health benefit plan that covers all eligible U.S. employees. The plan has been reinsured on an individual claim and total group claim basis. We have an individual stop loss of $125,000. For 2013, 2012 and 2011 we recognized expense of $4.0 million, $5.0 million and $4.8 million, respectively, for this plan.

22. TRANSACTIONS WITH RELATED PARTIES

As of February 28, 2014, members of the Darden family and entities controlled by them beneficially own 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 2013, we paid $0.2 million in commission to an entity controlled by members of the Darden family in connection with the sublease of a portion of our office space. Additionally, we paid $0.1 million in 2012 and $0.2 million in 2011 for rent and property management services on buildings owned by entities controlled by members of the Darden family. Rental rates were determined based on comparable rates charged by third parties. In December 2011, we purchased a manufacturing facility from an entity controlled by members of the Darden family for $1.1 million. We previously leased this facility from the seller for the manufacture of oil and gas equipment.

During 2013, 2012 and 2011, we paid $0.3 million, $0.5 million and $0.9 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 $0.1 million in each of 2013, 2012 and 2011.

111

In May 2013, we entered into an agreement with Thomas F. Darden with respect to Mr. Darden’s retirement and Mr. Darden’s provision of consulting services following his retirement. Effective May 15, 2013, Mr. Darden retired from his executive position and continued to serve as a non-officer employee through December 31, 2013. Mr. Darden continues to serve as a member of the Board of Directors as Chairman Emeritus. In recognition of his contributions to the Tokyo Gas Transaction, Mr. Darden received a cash bonus of $1.1 million paid in two equal installments in May 2013 and August 2013, and a stock option grant with an aggregate grant date fair value of $1.1 million granted in May 2013. Both the cash bonus and the stock option grant are included in the Tokyo Gas Transaction gain on our consolidated financial statements. In connection with his retirement, he received full vesting of his outstanding unvested equity awards (242,724 shares of restricted stock and 304,407 options); reimbursement of legal fees in connection with the agreement, up to $40,000; and payment of accrued and unused vacation and estimated COBRA premiums. Mr. Darden is engaged as a consultant for the three-year period following his retirement as an employee and receives a monthly consulting fee of $45,000. In addition, while a consultant, Mr. Darden is entitled to an office allowance of $12,500 per month, and additional reimbursements, with respect to certain business expenses. In addition, Mr. Darden is eligible to receive bonuses of up to $2.5 million in the aggregate under certain circumstances in connection with certain possible future strategic transactions occurring on or before December 31, 2016.

112

SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following table presents selected quarterly financial data derived from our consolidated financial statements. This summary should be read in conjunction with our consolidated financial statements and related notes also contained in this Item 8 to our Annual Report on Form 10-K.

	Quarter Ended
	March 31			June 30			September 30			December 31
	(In thousands, except per share data)
2013(1) (2) (3)
Operating revenue	$	118,703		$	175,497		$	153,116		$	114,246
Operating income (loss)	(3,874		)	394,894			60,049			13,575
Net income (loss)	(59,707		)	242,523			10,577			(31,775		)
Basic net earnings per share	$	(0.35	)	$	1.37		$	0.06		$	(0.18	)
Diluted net earnings per share	(0.35		)	1.37			0.06			(0.18		)
2012(4) (5) (6) (7)
Operating revenue	$	172,866		$	194,018		$	118,188		$	223,966
Operating loss	(267,985		)	(1,153,012		)	(576,551		)	(468,213		)
Net loss	(211,565		)	(802,022		)	(790,520		)	(548,499		)
Basic net earnings per share	$	(1.24	)	$	(4.72	)	$	(4.65	)	$	(3.22	)
Diluted net earnings per share	(1.24		)	(4.72		)	(4.65		)	(3.22		)

⁽¹⁾  Operating income for the second quarter of 2013 includes gains of $333.2 million related to the Tokyo Gas Transaction which was subsequently adjusted in later quarters to be a gain of $339.3 million. The period also includes an immaterial correction of $3.6 million for equity-based compensation granted to retirement-eligible employees whose awards required no future service at the time of grant but which expense was being recognized over multiple periods. The impact to the first quarter of 2013 expense was $1.2 million and the impact to 2012 and prior years was $2.4 million.

⁽²⁾  Operating income for the third quarter of 2013 includes an increase of $8.2 million to correct for immaterial items which pertain to earlier quarters in 2013, comprised of an increase to the gain related to the Tokyo Gas Transaction of $7.8 million arising from a change to the amount of unevaluated properties allocated to TGBR.

⁽³⁾  Operating income for the fourth quarter of 2013 includes a decrease of $5.9 million to correct for immaterial items which pertain to prior 2013 quarters. These items include an adjustment to non-cash expense to settle litigation recognized in the first quarter of 2013 of $3.0 million, non-cash decrease in the gain related to the Tokyo Gas Transaction of $1.7 million arising from a change in the amount of surface real estate conveyed to TGBR, increase in the amortization of deferred financing costs and original issue discount of $0.8 million and strategic transaction fees of $0.5 million arising in the second quarter of 2013.

⁽⁴⁾  Operating loss for the first quarter of 2012 includes charges for impairment of $178.0 million and $139.9 million for our U.S. and Canadian oil and gas properties, respectively.

⁽⁵⁾  Operating loss for the second quarter of 2012 includes charges for impairment of $1,042.7 million and $157.0 million for our U.S. and Canadian oil and gas properties, respectively.

⁽⁶⁾  Operating loss for the third quarter of 2012 includes charges for impairment of $479.9 million and $66.3 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $4.9 million impairment charge for other property and equipment in Colorado. Net loss includes a valuation allowance for the U.S. of $359.9 million.

⁽⁷⁾  Operating loss for the fourth quarter of 2012 includes charges for impairment of $451.5 million and $102.8 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $2.9 million impairment charge related to non-oil and gas properties. Net loss includes a valuation allowance for Canada of $61.3 million.

113

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Proved oil and gas reserves estimates for our properties in the U.S. and Canada were prepared by independent petroleum engineers from Schlumberger Technology Corporation and LaRoche Petroleum Consultants, Ltd., respectively. The reserve reports were prepared in accordance with guidelines established by the SEC. Natural gas, NGL and oil prices used in the 2013, 2012 and 2011 reserve reports are the unweighted average of the preceding 12-month first-day-of-the-month prices as of the date of the reserve reports. For all years, operating costs, production and ad valorem taxes and future development costs were based on year-end costs with no escalation.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represent estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of our natural gas, NGL and oil reserves or the costs that would be incurred to obtain equivalent reserves.

The changes in our proved reserves for the three years ended December 31, 2013 were as follows:

	Natural Gas (MMcf)						NGL (MBbl)						Oil (MBbl)
	U.S.		Canada		Total		U.S.		Canada		Total		U.S.		Canada	Total
December 31, 2010	1,941,723		265,888		2,207,611		112,444		12		112,456		3,308		—	3,308
Revisions (3)	(172,643	)	15,066		(157,577	)	(8,519	)	1		(8,518	)	(43	)	—	(43	)
Extensions and discoveries (2)	155,662		76,067		231,729		2,652		—		2,652		43		—	43
Production	(95,838	)	(26,390	)	(122,228	)	(4,432	)	(2	)	(4,434	)	(273	)	—	(273	)
December 31, 2011	1,828,904		330,631		2,159,535		102,145		11		102,156		3,035		—	3,035
Revisions (3)	(910,386	)	(33,945	)	(944,331	)	(45,379	)	1		(45,378	)	(479	)	—	(479	)
Extensions and discoveries (2)	25,858		9		25,867		3,518		—		3,518		345		—	345
Sales in place (1)	(20,616	)	—		(20,616	)	(42	)	—		(42	)	(85	)	—	(85	)
Production	(75,712	)	(29,912	)	(105,624	)	(4,069	)	(2	)	(4,071	)	(287	)	—	(287	)
December 31, 2012	848,048		266,783		1,114,831		56,173		10		56,183		2,529		—	2,529
Revisions (3)	234,835		28,648		263,483		750		—		750		62		—	62
Extensions and discoveries (2)	50,992		9,697		60,689		—		—		—		—		—	—
Sales in place (4)	(257,741	)	—		(257,741	)	(14,333	)	—		(14,333	)	(2,207	)	—	(2,207	)
Production	(51,684	)	(39,372	)	(91,056	)	(2,856	)	(1	)	(2,857	)	(185	)	—	(185	)
December 31, 2013	824,450		265,756		1,090,206		39,734		9		39,743		199		—	199
Proved developed reserves
December 31, 2011	1,244,187		299,371		1,543,558		60,902		11		60,913		2,545		—	2,545
December 31, 2012	725,361		266,783		992,144		47,284		10		47,294		2,416		—	2,416
December 31, 2013	702,147		260,159		962,306		34,603		9		34,612		139		—	139
Proved undeveloped reserves
December 31, 2011	584,717		31,260		615,977		41,243		—		41,243		490		—	490
December 31, 2012	122,687		—		122,687		8,890		—		8,890		113		—	113
December 31, 2013	122,303		5,896		128,199		5,131		—		5,131		60		—	60

⁽¹⁾  Sales of reserves in place during 2012 relate to our agreement to allow an outside working interest owner to fund the completion costs for twelve wells in our Barnett Shale Asset for which they received a preferential right to reserves. It also includes a minimal sale of reserves in our Niobrara Asset to SWEPI.

114

⁽²⁾  Extensions and discoveries for each period presented represent extensions to reserves attributable to additional drilling activity subsequent to discovery. U.S. extensions and discoveries for:

• 2013 are attributable to our Barnett Shale Asset;

• 2012 are 96% attributable to our Barnett Shale Asset, 4% to our Niobrara and West Texas Assets (of which 13% were proved developed); and

• 2011 are 100% attributable to our Barnett Shale Asset (of which 11% were proved developed).

Canadian extensions and discoveries for:

• 2013 and 2012 are attributable to our Horseshoe Canyon Asset; and

• 2011 are 97% attributable to our Horn River Asset and 3% are attributable to our Horseshoe Canyon Asset.

⁽³⁾  Revisions for each period presented reflect upward (downward) changes in previous estimates attributable to changes in economic factors of 419,972 MMcfe, (590,064) MMcfe and (54,539) MMcfe in 2013, 2012 and 2011, respectively, and changes in non-economic factors of (151,615) MMcfe, (629,407) MMcfe and (154,405) MMcfe in 2013, 2012 and 2011, respectively, including:

• Removal of proved undeveloped reserves that had not been developed within five years: (76) Bcfe and (250) Bcfe in 2013 and 2012, respectively;

• changes in performance related to offsetting activities, higher pipeline pressures and other factors: (74) Bcfe and (291) Bcfe in 2013 and 2012, respectively and

• revision of type curve of non producing wells based on comparison to producing analogs: (88) Bcfe in 2012.

⁽⁴⁾  Sales of reserves in place during 2013 relate to the Tokyo Gas Transaction (337 Bcfe) and the Synergy Transaction (15 Bcfe).

The carrying value of our oil and gas assets as of December 31, 2013, 2012 and 2011 were as follows:

	U.S.			Canada			Consolidated
	(In thousands)
2013
Proved properties	$	4,645,777		$	1,041,780		$	5,687,557
Unevaluated properties	19,343			202,262			221,605
Accumulated DD&A	(4,268,387		)	(1,000,332		)	(5,268,719		)
Net capitalized costs	$	396,733		$	243,710		$	640,443
2012
Proved properties	$	4,681,860		$	1,089,053		$	5,770,913
Unevaluated properties	90,035			217,232			307,267
Accumulated DD&A	(4,233,391		)	(1,063,829		)	(5,297,220		)
Net capitalized costs	$	538,504		$	242,456		$	780,960
2011
Proved properties	$	4,380,745		$	928,585		$	5,309,330
Unevaluated properties	252,737			180,604			433,341
Accumulated DD&A	(1,965,258		)	(550,937		)	(2,516,195		)
Net capitalized costs	$	2,668,224		$	558,252		$	3,226,476

115

Our consolidated capital costs incurred for acquisition, exploration and development activities during each of the three years in the period ended December 31, 2013, were as follows:

	U.S.		Canada		Consolidated
	(In thousands)
2013
Proved acreage	$	—	$	—	$	—
Unproved acreage	15,843		6,305		22,148
Development costs	49,299		17,422		66,721
Exploration costs	—		—		—
Total	$	65,142	$	23,727	$	88,869
2012
Proved acreage	$	—	$	—	$	—
Unproved acreage	23,711		5,612		29,323
Development costs	131,926		178,808		310,734
Exploration costs	35,244		8,304		43,548
Total	$	190,881	$	192,724	$	383,605
2011
Proved acreage	$	—	$	—	$	—
Unproved acreage	145,099		—		145,099
Development costs	304,373		90,361		394,734
Exploration costs	37,673		41,338		79,011
Total	$	487,145	$	131,699	$	618,844

116

Consolidated results of operations, without giving consideration to any tax valuation allowance, from our producing activities for each of the three years ended December 31, 2013, are set forth below:

	U.S.			Canada			Consolidated
	(In thousands)
2013
Natural gas, NGL and oil revenue	$	331,964		$	131,527		$	463,491
Operating expense	167,425			80,475			247,900
Depletion expense	34,995			5,362			40,357
	129,544			45,690			175,234
Income tax expense	45,340			11,514			56,854
Results from producing activities	$	84,204		$	34,176		$	118,380
2012
Natural gas, NGL and oil revenue	$	538,902		$	92,045		$	630,947
Operating expense	226,542			60,501			287,043
Depletion expense	116,005			24,897			140,902
Impairment expense	2,152,128			465,935			2,618,063
	(1,955,773		)	(459,288		)	(2,415,061		)
Income tax benefit	(684,521		)	(114,822		)	(799,343		)
Results from producing activities	$	(1,271,252	)	$	(344,466	)	$	(1,615,718	)
2011
Natural gas, NGL and oil revenue	$	673,041		$	127,502		$	800,543
Operating expense	267,890			54,770			322,660
Depletion expense	164,493			38,228			202,721
Impairment expense	—			49,063			49,063
	240,658			(14,559		)	226,099
Income tax expense (benefit)	84,230			(4,222		)	80,008
Results from producing activities	$	156,428		$	(10,337	)	$	146,091

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of our natural gas and oil properties. An estimate of such value should consider, among other factors, anticipated future prices of natural gas and oil, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, estimated future capital and operating costs and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

Under the Standardized Measure, future cash inflows for 2013 were estimated by applying the unweighted average of the preceding 12-month first-day-of-the-month prices, adjusted for contracts with price floors but excluding hedges, and unescalated year-end costs to the estimated future production of the year-end reserves. These prices have varied widely and have a significant impact on both the quantities and value of the proved reserves as reduced prices cause wells to reach the end of their economic life much sooner and also make certain proved undeveloped locations uneconomical, both of which reduce reserves. The following representative prices were used in the Standardized Measure and were adjusted by field for appropriate regional differentials:

117

	At December 31,
	2013		2012		2011
Natural gas – Henry Hub, per MMBtu	$	3.67	$	2.76	$	4.12
Natural gas – AECO, per MMBtu	2.90		2.35		3.65
Oil – WTI Cushing, per Bbl	97.18		94.71		95.71

The reference price used for our NGLs was based on WTI Cushing, adjusted for local differentials, gravity and BTU.

Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated proved natural gas and oil properties. Tax credits and net operating loss carry-forwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.

The Standardized Measure at December 31, 2013, 2012 and 2011 was as follows:

	U.S.			Canada			Total
				(In thousands)
December 31, 2013
Future revenue	$	3,825,944		$	656,984		$	4,482,928
Future production costs	(2,022,977		)	(385,776		)	(2,408,753		)
Future development costs	(212,280		)	(79,525		)	(291,805		)
Future income taxes	(134,418		)	59,294			(75,124		)
Future net cash flows	1,456,269			250,977			1,707,246
10% discount	(801,116		)	(83,082		)	(884,198		)
Standardized measure of discounted future cash flows relating to proved reserves	$	655,153		$	167,895		$	823,048
December 31, 2012
Future revenue	$	3,980,643		$	472,539		$	4,453,182
Future production costs	(2,552,863		)	(324,424		)	(2,877,287		)
Future development costs	(239,532		)	(56,354		)	(295,886		)
Future income taxes	81,847			80,206			162,053
Future net cash flows	1,270,095			171,967			1,442,062
10% discount	(667,738		)	(59,204		)	(726,942		)
Standardized measure of discounted future cash flows relating to proved reserves	$	602,357		$	112,763		$	715,120
December 31, 2011
Future revenue	$	11,647,002		$	1,055,711		$	12,702,713
Future production costs	(5,496,246		)	(463,852		)	(5,960,098		)
Future development costs	(1,125,641		)	(146,658		)	(1,272,299		)
Future income taxes	(1,229,968		)	(44,183		)	(1,274,151		)
Future net cash flows	3,795,147			401,018			4,196,165
10% discount	(2,286,449		)	(174,863		)	(2,461,312		)
Standardized measure of discounted future cash flows relating to proved reserves	$	1,508,698		$	226,155		$	1,734,853

The standardized measure was calculated without giving consideration to any tax valuation allowance.

118

The primary changes in the Standardized Measure for 2013, 2012 and 2011 were as follows:

	Years Ended December 31,
	2013			2012			2011
				(In thousands)
Sales of oil and gas net of production costs	$	(147,402	)	$	(149,326	)	$	(477,883	)
Net changes in economic factors	326,698			(1,362,793		)	32,175
Extensions and discoveries	43,328			27,003			251,635
Development costs incurred	2,302			172,563			233,294
Changes in estimated future development costs	20,766			620,127			(60,642		)
Purchase and sale of reserves, net	(237,409		)	(20,529		)	—
Revision of estimates	121,916			(1,219,609		)	(224,784		)
Accretion of discount	50,821			196,315			197,902
Net change in income taxes	(86,667		)	560,485			1,404
Change in timing and other differences	13,575			156,031			(4,626		)
Net increase (decrease)	$	107,928		$	(1,019,733	)	$	(51,525	)

119

ITEM 9. Changes in and Disagreements with Accountants or Accounting and Financial Disclosure

None.

ITEM 9A. Controls and Procedures

Disclosure Controls and Procedures

Disclosure controls and procedures, as defined in SEC literature, are controls and other procedures that are designed to ensure that the information that we are required to disclose in the reports that we file or submit to the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

In connection with the preparation of this Annual Report on Form 10-K, our management, under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2013. In making this this evaluation, our management considered the matters relating to the material weaknesses discussed below.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2013. As described below, we had material weaknesses related to deferred income taxes and in the accounting for significant, non-recurring transactions. Despite these material weaknesses, we have concluded that the financial statements in this Annual Report on Form 10-K present fairly, in all material respects, our consolidated financial position, results of operations and cash flows in conformity with generally accepted accounting principles.

Management’s Report on Internal Control Over Financial Reporting

Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements.

Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with existing policies or procedures may deteriorate.

Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management conducted an assessment of our internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) (1992 Framework). Based on this assessment, our management has concluded that, as of December 31, 2013, it did not maintain effective internal control over financial reporting due to material weaknesses in the operating effectiveness of our controls. Consistent with the material weakness identified at December 31, 2012, we continue to have 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. Given that we currently have a valuation allowance equal to our net deferred tax asset, the present risk to our financial statements is significantly reduced.

Additionally, 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 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.

The effectiveness of our internal control over financial reporting as of December 31, 2013, has been audited by Ernst & Young LLP, our independent registered public accounting firm, and they have issued an attestation report on our internal control over financial reporting which is included herein.

120

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2013, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

121

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Quicksilver Resources Inc.

We have audited Quicksilver Resources Inc.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 Framework) (the COSO criteria). Quicksilver Resources Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified and included in management’s assessment. Management has identified a material weakness in the operating effectiveness of controls related to the reconciliation of deferred income taxes, particularly related to the tax basis in property, plant and equipment. Further, management has identified a material weakness in the operating effectiveness of controls related to the accounting for significant non-recurring transactions. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Quicksilver Resources Inc. as of December 31, 2013, and the related consolidated statement of income (loss) and comprehensive income (loss), equity, and cash flows for the year ended December 31, 2013. These material weaknesses were considered in determining the nature, timing and extent of audit tests applied in our audit of the 2013 financial statements, and this report does not affect our report dated March 14, 2014, which expressed an unqualified opinion on those financial statements.

122

In our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, Quicksilver Resources Inc. has not maintained effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.

/s/ Ernst & Young LLP

Fort Worth, Texas

March 17, 2014

123

ITEM 9B. Other Information

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. In February 2013 we met with and provided additional information to the SEC.

On March 13, 2014, the Compensation Committee of the Board of Directors of the Company approved the award of the following bonuses in respect of 2013 to John C. Regan, Senior Vice President - Chief Financial Officer and Chief Accounting Officer, and Stan G. Page, Senior Vice President - U.S. Operations, effective as of March 31, 2014:

Name	Cash Amount	Equity Amount
John C. Regan	$92,400	$92,400
Stan G. Page	$91,140	$91,140

The equity bonuses have been granted under the Company’s Seventh Amended and Restated 2006 Equity Plan in the form of fully vested shares of the Company’s common stock.

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance

The information concerning our directors set forth under “Corporate Governance Matters” in the proxy statement for our May 14, 2014 annual meeting of stockholders (“2014 Proxy Statement”) is incorporated herein by reference. The information concerning any changes to the procedure by which a security holder may recommend nominees to the board of directors set forth under “Corporate Governance Matters – Committees of the Board” in the 2014 Proxy Statement is incorporated herein by reference. Certain information concerning our executive officers is set forth under the heading “Business – Executive Officers of the Registrant” in Item 1 of this Annual Report. The information concerning compliance with Section 16(a) of the Exchange Act set forth under “Section 16(a) Beneficial Ownership Reporting Compliance” in the 2014 Proxy Statement is incorporated herein by reference.

The information concerning our audit committee set forth under “Corporate Governance Matters – Committees of the Board” in the 2014 Proxy Statement is incorporated herein by reference.

The information regarding our Code of Business Conduct and Ethics set forth under “Corporate Governance Matters – Corporate Governance Principles, Processes and Code of Business Conduct and Ethics” in the 2014 Proxy Statement is incorporated herein by reference.

ITEM 11. Executive Compensation

The information set forth under “Executive Compensation,” “Corporate Governance Matters – Compensation Committee Interlocks and Insider Participation,” “Corporate Governance Matters – Director Compensation for 2013” and “Certain Relationships and Related Transactions” in the 2014 Proxy Statement is incorporated herein by reference.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information set forth under “Security Ownership of Management and Certain Beneficial Holders” in the 2014 Proxy Statement is incorporated herein by reference. The information regarding our equity plans under which shares of our common stock are authorized for issuance as set forth under “Equity Compensation Plan Information” in the 2014 Proxy Statement is incorporated herein by reference.

124

ITEM 13. Certain Relationships and Related Transactions, and Director Independence

The information set forth under “Certain Relationships and Related Transactions” in the 2014 Proxy Statement is incorporated herein by reference.

Information regarding our directors’ independence set forth under “Corporate Governance Matters – Independent Directors” in the 2014 Proxy Statement is incorporated herein by reference.

ITEM 14. Principal Accountant Fees and Services

The information set forth under “Independent Registered Public Accountants” in the 2014 Proxy Statement is incorporated herein by reference.

125

PART IV

ITEM 15.

The following are filed as part of this Annual Report:

Financial Statements

See the index to the consolidated financial statements and related footnotes and other supplemental information included in Item 8 of this Annual Report, which identifies the financial statements filed herewith.

Financial Statement Schedules

All other schedules are omitted from this item because the information is inapplicable or is presented in the consolidated financial statements and related notes in Item 8 of this Annual Report.

126

EXHIBIT INDEX

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
2.1*	Purchase Agreement, dated as of July 22, 2010, among First Reserve Crestwood Holdings LLC, Cowtown Gas Processing L.P., Cowtown Pipeline L.P. and Quicksilver Resources Inc.	8-K	001-14837	2.1	7/23/2010
2.2*	Purchase Agreement Amendment No. 1, dated as of September 17, 2010, among First Reserve Crestwood Holdings LLC, Cowtown Gas Processing L.P., Cowtown Pipeline L.P. and Quicksilver Resources Inc.	10-Q	001-14837	2.2	11/8/2010
2.3*	Purchase and Sale Agreement, dated March 28, 2013, between Quicksilver Resources Inc., as Seller, and TG Barnett Resources LP, as Buyer	8-K	001-14837	2.1	5/6/2013
3.1	Amended and Restated Certificate of Incorporation of Quicksilver Resources Inc. filed with the Secretary of State of the State of Delaware on May 21, 2008	S-3	333-151847	4.1	6/23/2008
3.2	Amended and Restated Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc.	10-Q	001-14837	3.3	5/8/2006
3.3	Amended and Restated Bylaws of Quicksilver Resources Inc.	8-K	001-14837	3.1	5/16/2013
4.1	Form of Common Stock Certificate of Quicksilver Resources Inc.					†
4.2	Indenture, dated as of December 22, 2005, between Quicksilver Resources Inc. and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association)	S-3	333-130597	4.7	12/22/2005
4.3	First Supplemental Indenture, dated as of March 16, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association)	8-K	001-14837	4.1	3/21/2006
4.4	Second Supplemental Indenture, dated as of July 31, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association)	10-K	001-14837	4.5	3/15/2010
4.5	Third Supplemental Indenture, dated as of September 26, 2006, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association)	10-Q	001-14837	4.1	11/7/2006
4.6	Fourth Supplemental Indenture, dated as of October 31, 2007, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association)	10-K	001-14837	4.7	3/15/2010
4.7	Fifth Supplemental Indenture, dated as of June 27, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Trust Company, N.A., as trustee	8-K	001-14837	4.1	6/30/2008
4.8	Sixth Supplemental Indenture, dated as of July 10, 2008, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	8-K	001-14837	4.1	7/10/2008
4.9	Seventh Supplemental Indenture, dated as of June 25, 2009, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	8-K	001-14837	4.1	6/26/2009
4.10	Eighth Supplemental Indenture, dated as of August 14, 2009, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	8-K	001-14837	4.1	8/17/2009

127

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
4.11	Ninth Supplemental Indenture, dated as of December 23, 2011, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-K	001-14837	4.12	4/16/2012
4.12	Tenth Supplemental Indenture, dated as of December 23, 2011, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-K	001-14837	4.13	4/16/2012
4.13	Eleventh Supplemental Indenture, dated as of December 23, 2011, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-K	001-14837	4.14	4/16/2012
4.14	Twelfth Supplemental Indenture, dated as of December 23, 2011, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-K	001-14837	4.15	4/16/2012
4.15	Thirteenth Supplemental Indenture, dated as of February 28, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-Q	001-14837	4.1	5/10/2012
4.16	Fourteenth Supplemental Indenture, dated as of February 28, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-Q	001-14837	4.2	5/10/2012
4.17	Fifteenth Supplemental Indenture, dated as of February 28, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-Q	001-14837	4.3	5/10/2012
4.18	Sixteenth Supplemental Indenture, dated as of February 28, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-Q	001-14837	4.4	5/10/2012
4.19	Seventeenth Supplemental Indenture, dated as of June 13, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-Q	001-14837	4.1	8/9/2012
4.20	Eighteenth Supplemental Indenture, dated as of June 13, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-Q	001-14837	4.2	8/9/2012
4.21	Nineteenth Supplemental Indenture, dated as of June 13, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-Q	001-14837	4.3	8/9/2012
4.22	Twentieth Supplemental Indenture, dated as of June 13, 2012, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	10-Q	001-14837	4.4	8/9/2012
4.23	Twenty-first Supplemental Indenture, dated as of June 12, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	8-K	001-14837	4.1	6/12/2013
4.24	Twenty-second Supplemental Indenture, dated as of June 12, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	8-K	001-14837	4.2	6/12/2013
4.25	Twenty-third Supplemental Indenture, dated as of June 12, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	8-K	001-14837	4.3	6/12/2013

128

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
4.26	Twenty-fourth Supplemental Indenture, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	8-K/A	001-14837	4.4	7/1/2013
4.27	Indenture, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee	8-K/A	001-14837	4.1	7/1/2013
4.28	Indenture, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee and second lien collateral agent	8-K/A	001-14837	4.2	7/1/2013
4.29	Registration Rights Agreement, dated as of June 21, 2013, among Quicksilver Resources Inc., the subsidiary guarantors named therein and Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as representatives of the initial purchasers	8-K/A	001-14837	4.3	7/1/2013
4.30	Amended and Restated Rights Agreement, dated as of December 20, 2005, between Quicksilver Resources Inc. and Computershare Shareowner Services LLC (f/k/a Mellon Investor Services LLC), as Rights Agent	8-A/A	001-14837	4.1	12/21/2005
4.31	Amendment dated as of February 23, 2011 to the Amended and Restated Rights Agreement between Quicksilver Resources Inc. and Computershare Shareowner Services LLC (f/k/a Mellon Investor Services LLC), as Rights Agent	8-K	001-14837	4.1	2/24/2011
4.32	Amendment No. 2, dated as of March 8, 2013, to the Amended and Restated Rights Agreement between Quicksilver Resources Inc. and Computershare Shareowner Services LLC (f/k/a Mellon Investor Services LLC), as Rights Agent	8-K	001-14837	4.1	3/8/2013
10.1	Wells Agreement dated as of December 15, 1970, between Union Oil Company of California and Montana Power Company	S-4/A	333-29769	10.5	8/21/1997
10.2**	Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan	8-K	001-14837	10.4	5/25/2007
10.3**	Form of Non-Qualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan	8-K	001-14837	10.4	1/28/2005
10.4**	Quicksilver Resources Inc. Seventh Amended and Restated 2006 Equity Plan	10-Q	001-14837	10.1	8/8/2013
10.5**	Form of Restricted Share Award Agreement pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended	8-K	001-14837	10.2	5/25/2006
10.6**	Form of Restricted Stock Unit Award Agreement pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended	8-K	001-14837	10.2	11/24/2008
10.7**	Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Award Agreement (Cash Settlement) pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended	8-K	001-14837	10.3	11/24/2008
10.8**	Form of Quicksilver Resources Canada Inc. Restricted Stock Unit Award Agreement (Stock Settlement) pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended	8-K	001-14837	10.4	11/24/2008
10.9**	Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended	10-K	001-14837	10.9	4/16/2012
10.10**	Form of Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended	10-K	001-14837	10.10	4/16/2012

129

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
10.11**	Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended (One-Year Vesting)	8-K	001-14837	10.8	5/25/2006
10.12**	Form of Non-Employee Director Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended (Three-Year Vesting)	8-K	001-14837	10.5	11/24/2008
10.13**	Form of Non-Employee Director Restricted Share Award Agreement pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended (One-Year Vesting)	8-K	001-14837	10.7	5/25/2006
10.14**	Form of Non-Employee Director Restricted Share Award Agreement pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended (Three-Year Vesting)	8-K	001-14837	10.2	5/25/2007
10.15**	Quicksilver Resources Inc. 2011 Executive Bonus Plan	8-K	001-14837	10.1	2/25/2011
10.16**	Quicksilver Resources Inc. 2012 Executive Bonus Plan	8-K	001-14837	10.1	4/19/2012
10.17**	Description of 2011 Cash Bonuses	10-K	001-14837	10.17	4/16/2012
10.18**	Quicksilver Resources Inc. Amended and Restated Change in Control Retention Incentive Plan	8-K	001-14837	10.9	11/24/2008
10.19**	Quicksilver Resources Inc. Second Amended and Restated Key Employee Change in Control Retention Incentive Plan	8-K	001-14837	10.8	11/24/2008
10.20**	Quicksilver Resources Inc. Amended and Restated Executive Change in Control Retention Incentive Plan	8-K	001-14837	10.7	11/24/2008
10.21**	Form of Director and Officer Indemnification Agreement	10-Q	001-14837	10.2	11/8/2010
10.22**	Letter to John C. Regan dated April 16, 2012	10-K	001-14837	10.22	3/22/2013
10.23**	Letter to Jeff Cook dated July 20, 2012	10-Q	001-14837	10.1	11/8/2012
10.24**	Employment Separation Settlement Agreement, dated August 9, 2012, between Quicksilver Resources Inc. and Jeff Cook	10-K	001-14837	10.24	3/22/2013
10.25**	Agreement, dated as of May 15, 2013 between Quicksilver Resources Inc. and Thomas F. Darden	10-Q	001-14837	10.2	8/8/2013
10.26**	Letter to John C. Regan dated July 15, 2013	10-Q	001-14837	10.1	11/6/2013
10.27**	Letter to Stan G. Page dated July 15, 2013	10-Q	001-14837	10.2	11/6/2013
10.28	Credit Agreement, dated as of September 6, 2011, among Quicksilver Resources Inc. and the agents and lenders identified therein	10-Q	001-14837	10.1	11/9/2011
10.29	Amended and Restated U.S. Credit Agreement, dated as of December 22, 2011, among Quicksilver Resources Inc. and the agents and lenders identified therein	8-K	001-14837	10.1	12/27/2011
10.31	Amended and Restated Canadian Credit Agreement, dated as of December 22, 2011, among Quicksilver Resources Canada Inc. and the agents and lenders identified therein	8-K	001-14837	10.2	12/27/2011
10.32	Omnibus Amendment No. 1 to Combined Credit Agreements, dated as of May 23, 2012, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein	10-Q	001-14837	10.3	8/9/2012
10.33	Omnibus Amendment No. 2 to Combined Credit Agreements, dated as of August 6, 2012, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein	10-Q	001-14837	10.4	8/9/2012

130

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
10.34	Omnibus Amendment No. 3 to Combined Credit Agreements, dated as of October 5, 2012, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein	10-K	001-14837	10.31	3/22/2013
10.35	Omnibus Amendment No. 4 to Combined Credit Agreements, dated as of April 30, 2013, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein	10-Q	001-14837	10.3	8/8/2013
10.36	Omnibus Amendment No. 5 to Combined Credit Agreements, dated as of June 21, 2013, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein	8-K/A	001-14837	10.2	7/1/2013
10.37	Omnibus Amendment No. 6 to Combined Credit Agreements, dated as of November 15, 2013, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein	8-K	001-14837	10.1	11/18/2013
10.38	Second Lien Credit Agreement, dated as of June 21, 2013, among Quicksilver Resources Inc., the lenders party thereto and Credit Suisse AG, as administrative agent	8-K/A	001-14837	10.1	7/1/2013
10.39	Asset Purchase Agreement, dated as of May 15, 2009, among Quicksilver Resources Inc., as Seller, and ENI US Operating Co. Inc. and ENI Petroleum US LLC, as Buyers	8-K	001-14837	10.1	5/19/2009
10.40	Project and Expenditure Authorization, dated as of April 6, 2011, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd.	8-K	001-14837	10.1	4/14/2011
10.41	PEA Amending Agreement, dated as of August 28, 2012, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd.	8-K	001-14837	10.1	9/10/2012
10.42	Commitment Letter Agreement, dated as of April 6, 2011, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd.	8-K	001-14837	10.2	4/14/2011
10.43	Amendment to Commitment Letter Agreement, dated as of August 28, 2012, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd.	8-K	001-14837	10.2	9/10/2012
10.44***	Contribution Agreement dated December 23, 2011 among Quicksilver Resources Canada Inc., Fortune Creek Gathering and Processing Partnership and 0927530 B.C. Unlimited Liability Company	8-K/A	001-14837	10.1	12/16/2013
10.45	Guaranty dated December 23, 2011 among Quicksilver Resources Inc., Fortune Creek Gathering and Processing Partnership and 0927530 B.C. Unlimited Liability Company	8-K	001-14837	10.2	12/27/2011
10.46	Gas Gathering Agreement, effective December 1, 2009, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.	8-K	001-33631	10.1	1/8/2010
10.47	Amendment to Gas Gathering Agreement, dated as of October 1, 2010, by and between Quicksilver Resources Inc. and Cowtown Pipeline Partners L.P.	10-K	001-33631	10.2	2/25/2011
10.48	Sixth Amendment and Restated Gas Gathering and Processing Agreement, dated September 1, 2008, among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P.	10-Q	001-33631	10.1	11/6/2008
10.49	Addendum and Amendment to Gas Gathering and Processing Agreement Mash Unit Lateral, effective January 1, 2009, among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Processing Partners L.P.	10-K	001-33631	10.2	3/15/2010

131

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
10.50	Second Amendment to Sixth Amendment and Restated Gas Gathering and Processing Agreement, date as of October 1, 2010, by and among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P.	10-K	001-33631	10.2	2/25/2011
10.51	Amended and Restated Gas Gathering Agreement, effective September 1, 2008, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.	10-K	001-14837	10.54	4/16/2012
10.52	First Amendment to Amended and Restated Gas Gathering Agreement, dated September 29, 2009, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.	10-K	001-14837	10.55	4/16/2012
10.53	Second Amendment to Gas Gathering Agreement, dated October 1, 2010, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.	10-K	001-14837	10.56	4/16/2012
10.54***	Acquisition and Exploration Agreement, dated September 20, 2012, between Quicksilver Resources Inc. and SWEPI LP	8-K/A	001-14837	10.1	2/8/2013
10.55	First Amendment to Acquisition and Exploration Agreement, dated November 20, 2012, between Quicksilver Resources Inc. and SWEPI LP	10-K	001-14837	10.48	3/22/2013
21.1	List of subsidiaries of Quicksilver Resources Inc.					†
23.1	Consent of Ernst & Young LLP					†
23.2	Consent of Deloitte & Touche LLP					†
23.3	Consent of Schlumberger Technology Corporation					†
23.4	Consent of LaRoche Petroleum Consultants, Ltd.					†
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					†
99.1	Report of Schlumberger Technology Corporation					†
99.2	Report of LaRoche Petroleum Consultants, Ltd.					†
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					‡

* Excludes schedules and exhibits we agree to furnish supplementally to the SEC upon request

** Indicates a management contract or compensatory plan or arrangement

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

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SIGNATURES

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

		Quicksilver Resources Inc.
		By:	/s/    John C. Regan
			John C. Regan
Dated:	March 18, 2014		Senior Vice President - Chief Financial Officer and Chief Accounting Officer

133