Quicksilver Resources (KWK) 10-K 2014 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2014

OR

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

For the transition period from to

Commission file number:    001-14837

QUICKSILVER RESOURCES INC.

(Exact name of registrant as specified in its charter)

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

817-665-5000

(Registrant’s telephone number, including area code)

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

Title of each class

Common Stock, $0.01 par value per share

Preferred Share Purchase Rights,

$0.01 par value per share

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, 2014, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $335,217,945 based on the closing sale price of $2.67 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 March 17, 2015
Common Stock, $0.01 par value per share	183,213,235 shares

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Part III of this Annual Report are incorporated by reference to the definitive proxy statement for the Registrant’s 2015 Annual Meeting of Stockholders or will be provided in an amendment filed on Form 10-K/A.

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

“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

“Mtpa” means millions of tonnage per annum of LNG

“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

“QRCI” means Quicksilver Resources Canada Inc., our wholly owned subsidiary

“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, which is within our Barnett Shale Asset

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

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

“Bankruptcy Code” means title 11 of the United States Code

“Bankruptcy Court” means the United States Bankruptcy Court for the District of Delaware

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“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

“CCAA” means the Companies’ Creditors Arrangement Act (Canada)

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

“Chapter 11” means chapter 11 of the Bankruptcy Code

“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 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.

“Forbearance Agreement” means the Waiver and Forbearance Agreement entered into by us and QRCI on March 16, 2015 with the administrative agents and certain of the lenders under the Combined Credit Agreements

“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

“Houlihan Lokey” means Houlihan Lokey Capital, Inc.

“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 our Barnett Shale Asset

“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 natural 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 which were sold in the Southwestern Transaction

“OSHA” means Occupational Safety & Health Administration

“OTC Pink” means OTC Pink, a centralized electronic quotation service for over-the-counter securities, operated by OTC Markets Group Inc.

“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 facility, 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” means Southwestern Energy Company

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

“Substantial Equityholder” means all persons or entities who at March 19, 2015 or in the future beneficially own at least 4.75% of our outstanding equity securities

“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.

“U.S. Debtors” means us and our subsidiaries Barnett Shale Operating LLC, Cowtown Drilling, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline Funding, Inc., Cowtown Pipeline L.P., Cowtown Pipeline Management, Inc., Makarios Resources International Holdings LLC, Makarios Resources International Inc., QPP Holdings LLC, QPP Parent LLC, Quicksilver Production Partners GP LLC, Quicksilver Production Partners LP, and Silver Stream Pipeline Company LLC that filed Chapter 11 petitions

“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 and to a lesser extent Crockett and Upton Counties, Texas

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INDEX TO ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2014

PART I
ITEM 1.	Business	13
ITEM 1A.	Risk Factors	24
ITEM 1B.	Unresolved Staff Comments	37
ITEM 2.	Properties	37
ITEM 3.	Legal Proceedings	37
ITEM 4.	Mine Safety Disclosures	37
PART II
ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
ITEM 6.	Selected Financial Data	40
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk	69
ITEM 8.	Financial Statements and Supplementary Data	73
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	129
ITEM 9A.	Controls and Procedures	129
ITEM 9B.	Other Information	131
PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	131
ITEM 11.	Executive Compensation	131
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	131
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	131
ITEM 14.	Principal Accountant Fees and Services	131
PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	132
	Signatures	139

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,” “contemplate,” “estimate,” “anticipate,” “believe,” “project,” “target,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

• risks and uncertainties associated with the Chapter 11 process, including our inability to develop, confirm and consummate a plan under Chapter 11 of the Bankruptcy Code or an alternative restructuring transaction, including a sale of all or substantially all of our assets, which may be necessary to continue as a going concern;

• inability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing;

• failure to satisfy our short- or long-term liquidity needs, including our inability to generate sufficient cash flow from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs and our ability to continue as a going concern;

• domestic and foreign supply and demand for natural gas, NGL and oil and related 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;

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

• our inability to manage our significant exposure to fluctuations in commodity prices as a result of our limited hedge positions;

• 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;

• the volatility and decline in our stock price, and the inability of our common stock to remain quoted on the OTC Pink;

• delays in obtaining oilfield equipment and increases in drilling and completion 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 entering into and completing a transaction involving the sale of any or all of our Canadian assets, including our Horn River Asset;

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

• inability to meet our minimum volume delivery requirements in our gathering, processing, fractionation and transportation agreements or otherwise satisfy minimum volume deficiency payment obligations;

• the effects of existing or future litigation;

• changes in general economic conditions; and

• additional factors described elsewhere in this Annual Report.

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This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K, including any amendments thereto. All such risk factors are difficult to predict, and are subject to material uncertainties that may affect actual results and may be beyond our control. The forward-looking statements included in this 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 natural 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 1.1 Tcfe at December 31, 2014. Our four core development and exploration areas include the Barnett Shale, Horn River and Horseshoe Canyon and our oil exploration opportunity in the Delaware basin in western Texas. We actively study these basins and other basins in North America, which may result in future oil and natural gas acquisitions.

We were organized as a Delaware corporation in 1997 and became a public company in 1999. As of March 17, 2015, members of the Darden family and entities controlled by them beneficially owned approximately 25% of our outstanding common stock. Our common stock is quoted under the symbol “KWKAQ” on the OTC Pink.

CHAPTER 11 FILINGS

During the third quarter of 2014, we launched a formal marketing process, led by Houlihan Lokey, covering any and all of our operating assets. During the formal marketing process, we also received additional amendments to the financial covenants to our Combined Credit Agreements. These amendments, which included the replacement of the minimum interest coverage ratio with a minimum EBITDAX requirement, provided relief from the continued pressure on our cash flows relative to our obligations, which in turn allowed time for the formal marketing process. Bids were initially due in December 2014, but the bid deadline was subsequently extended to late January 2015. After the bid deadline passed, we evaluated the bids that were received with our advisors. Following discussions with various bidders, we concluded that the marketing process had not yet produced any viable options for asset sales or other strategic alternatives that would likely have a material impact on our capital structure or liquidity.

In February 2015, in light of (a) not yet having identified a transaction that would have a material impact on our capital structure or liquidity, (b) the potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, and (c) other potential defaults, we elected not to make the approximately $13.6 million interest payment on our Senior Notes due 2019, which was due on February 17, 2015. During the 30-day grace period provided for in the Senior Notes due 2019 Indenture, we continued discussions with our creditors. The discussions with our creditors did not produce an agreement that would enable us to effectively address, in a holistic manner, the impending issues adversely impacting our business, including (i) potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, (ii) potential near-term liquidity shortfalls due to the springing maturities, (iii) potential near-term breaches of certain financial covenants resulting from sharp declines in natural gas and NGL prices, and (iv) certain other potential defaults under our Combined Credit Agreements and the Second Lien Term Loan.

Accordingly, on March 17, 2015, the Company and our subsidiaries Barnett Shale Operating LLC, Cowtown Drilling, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline Funding, Inc., Cowtown Pipeline L.P., Cowtown Pipeline Management, Inc., Makarios Resources International Holdings LLC, Makarios Resources International Inc., QPP Holdings LLC, QPP Parent LLC, Quicksilver Production Partners GP LLC, Quicksilver Production Partners LP, and Silver Stream Pipeline Company LLC each filed a voluntary petition under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court to restructure our obligations and capital structure. The Chapter 11 cases are being jointly administered for procedural purposes only by the Bankruptcy Court under the caption In re Quicksilver Resources Inc., et. al., Case No. 15-10585 (Jointly Administered).

We are currently operating our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As part of our “first day” motions in the Chapter 11 proceedings, we obtained Bankruptcy Court approval to, among other things and subject to the applicable caps contained in the orders of the Bankruptcy Court, on an interim basis, pay employee wages, health benefits and certain other employee obligations, to pay certain lienholders and critical vendors and forward funds belonging to third parties, including royalty holders and other partners. A final hearing on the motions to satisfy

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our obligations to certain third parties and to forward funds held by us that belong to third parties will be held on April 15, 2015.

On March 16, 2015, we, along with QRCI, entered into the Forbearance Agreement with the administrative agents and certain of the lenders under the Combined Credit Agreements. As a result of the Chapter 11 filing, the obligations under the Combined Credit Agreements were automatically accelerated. However, pursuant to the Forbearance Agreement, the administrative agents and the lenders agreed to, among other things, (i) forbear from exercising their rights and remedies in connection with specified defaults under the Amended and Restated Canadian Credit Facility related to our Chapter 11 filing until the earlier of June 16, 2015 or certain other events specified in the Forbearance Agreement, including, among other things, the commencement by QRCI or certain specified Canadian subsidiary guarantors of insolvency proceedings and (ii) waive compliance with certain specified terms and conditions relating to the renewal of outstanding evergreen letters of credit under the Combined Credit Agreements.

For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A, “Risk Factors.” As a result of these risks and uncertainties, the number of our outstanding shares and our shareholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Annual Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

In particular, subject to certain exceptions, under the Bankruptcy Code, the U.S. Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the U.S. Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert claims against the applicable U.S. Debtor's estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the U.S. Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the U.S. Debtor in this Annual Report, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the U.S. Debtor is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the U.S. Debtors expressly preserve all of their rights with respect thereto.

There can be no assurances regarding our ability to successfully develop, confirm and consummate one or more plans of reorganization or other alternative restructuring transactions, including a sale of all or substantially all of our assets, that satisfies the conditions of the Bankruptcy Code and, is authorized by the Bankruptcy Court.

STRATEGIC TRANSACTIONS IN THE LAST FIVE YEARS

In September 2014, we executed a joint exploration agreement with an undisclosed third party involving our assets in the Midland Basin located in Crockett and Upton counties. As part of the agreement, we expect to be fully carried for the drilling and completion of up to five wells to be operated by a third party. We retained a 12.5% interest in the project.

In May 2014, we completed the sale of our Niobrara Asset to Southwestern. The purchase price was subject to customary purchase price adjustments, which resulted in Southwestern paying us $95.6 million. The decision to sell this acreage was largely rooted in the planned exit of our operating partner, SWEPI, from its North American shale plays, including the shared interest in our Niobrara Asset.

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

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

In October 2013, we executed an agreement with Eni involving our West Texas Asset 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 is responsible for 100% of the cost for drilling, completion and production facilities up to a total of $52 million, thereby earning a 50% interest in our acreage. Upon Eni’s fulfillment of the $52 million carry, which was substantially met as of the first quarter of 2015, we participate equally in the future revenue, operating costs and capital expenditures on the wells drilled and completed pursuant to the joint exploration agreement. In November 2013, we also executed a farm-out agreement with another partner covering 7,500 gross acres also located in Pecos County.

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, including the assignment of a 25% interest of certain contracts related to 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 natural 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 contract 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.

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.

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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, 2014, we had total proved reserves of approximately 1.1 Tcfe, of which 82% is natural gas and 18% is NGLs. For 2014, we had total production of 90 Bcfe or 247.4 MMcfed.

Assuming access to sufficient capital resources, we believe the development of our leasehold interest in our core areas, in concert with our exploration activities in our West Texas Asset, could provide us the opportunity over the next several years to grow reserves and production. However, given our limited access to additional capital resources, we are unlikely to have the capital required to substantially add to our reserves and production through exploration and development activities. Details of our 2015 capital program and our projected production levels can be found in Item 7 of this Annual Report.

Barnett Shale

At December 31, 2014, we held approximately 89,000 net acres in the Barnett Shale. Proved reserves were 0.8 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 2014, sales of NGLs represented 21% of our Barnett Shale Asset production and 14% of consolidated production revenue.

We focused our 2014 drilling and completion activity in our Barnett Shale Asset in an attempt to increase production and cash flows from operations, with a limited capital plan. As operator, we drilled 19 (11.2 net) wells and completed 28 (17.7 net) wells in our Barnett Shale Asset. At December 31, 2014, we had a total of 980 (587.7 net) producing wells in our Barnett Shale Asset.

We employed a single drilling rig program in the Barnett Shale during the first quarter of 2015.

West Texas

In our West Texas Asset, our focus is on approximately 60,000 gross (27,000 net) acres in Pecos County, which is being developed with Eni and an undisclosed third party. In 2014, we drilled and completed two wells in Pecos County with Eni. The Stallings #1H was completed in August 2014 and has produced approximately 60,000 Boe as of March 17, 2015. The Mitchell #1H was completed in October 2014 and has produced approximately 45,000 Boe as of March 17, 2015. We drilled and completed the Puckett C well in Pecos County and the well is in flowback. A fourth well, the Stallings #2H, was drilled in the first quarter of 2015 and we expect to start completion of the well in the second quarter of 2015. These drilling and completion costs are expected to be substantially covered by Eni as part of their $52 million funding requirement. We are in discussions with Eni to drill and complete four additional wells in 2015 in our West Texas Asset; however, any such agreement is subject to final documentation and Bankruptcy Court approval.

Additionally, on near-term expiring acreage in Crockett and Upton Counties, we executed an exploration agreement with undisclosed third parties. As part of the agreement, we expect to be fully carried for the drilling and completion of up to five wells, which will be operated by a party to the agreement. We retained a 12.5% interest in the project or approximately 2,000 net acres. We believe the acreage, in both the Pecos County development and the Crockett and Upton County development, is prospective for the Bone Springs and Wolfcamp formations.

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We did not recognize a material amount of proved reserves from our West Texas Asset at December 31, 2014.

Horn River

We hold approximately 126,000 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, 2014 were 66.5 Bcfe. While our Horn River Asset contains the most prolific wells in our portfolio, we do not have sufficient liquidity to develop the asset.

QRCI did not pay an uneconomic Canadian gathering and processing commitment, which included significant unused firm capacity, due in late February 2015. In early March 2015, the third party service provider issued a demand letter regarding the missed payment and suspended service resulting in our Horn River Asset being shut-in. Further, a termination notice was issued effective March 19, 2015. We are exploring alternatives to gather and process our Horn River Asset production; however, we may not be able to find economic alternatives in the near-term, or at all.

In connection with this Canadian gathering and processing contract, we had previously issued a letter of credit in the amount of C$33 million. Upon termination, the third party drew down the full face amount of the letter of credit. We do not believe the third party was legally entitled to draw down the entire amount of the letter of credit and we have reserved all of our rights, entitlements and remedies in that regard.

We expect that we and the third party will disagree as to what are the remaining obligations under the relevant agreement and the length of the remaining term of the agreement and as to the remedies and defenses available to the parties. While we expect to vigorously dispute the amount, we expect that the third party will claim to be entitled to up to approximately C$126 million (including the proceeds of the letter of credit) as the aggregate of the monthly tolls for firm capacity for the alleged remainder of the term of the relevant agreement.

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. In early 2014, we began demolition activities to clear the site of the remaining paper mill facilities. Further, in July 2014, we filed an export license application with the National Energy Board of Canada to export up to 20 Mtpa of LNG from our Campbell River site.

Horseshoe Canyon

As of December 31, 2014, proved reserves in our Horseshoe Canyon Asset were 211.4 Bcfe situated across approximately 343,000 net acres. Our Horseshoe Canyon Asset is characterized by predictable and repeatable well results on shallow decline curves.

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OIL AND NATURAL GAS RESERVES

Our proved reserve estimates and related disclosures for 2014, 2013 and 2012 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 Douglas R. Parkhurst, Vice President - Chief Reservoir Engineer, is responsible for the preparation and maintenance of our engineering data and review of our proved reserve estimates with Schlumberger and LaRoche. Mr. Parkhurst has over 16 years of experience in the oil and natural gas industry. Mr. Parkhurst earned a Bachelor of Science degree in Petroleum Engineering from Texas Tech University. 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 natural 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 natural 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 18 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. Parkhurst and the other members of our executive management team.

The Audit Committee of our Board has met with our executive management team, Mr. Parkhurst, 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 our Board.

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

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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,
	2014	2013	2012	2014	2013	2012	2014	2013	2012
Natural gas (MMcf)
U.S.	619,751	702,147	725,361	10,726	122,303	122,687	630,477	824,450	848,048
Canada	277,828	260,159	266,783	—	5,896	—	277,828	266,056	266,783
Total	897,579	962,306	992,144	10,726	128,199	122,687	908,305	1,090,506	1,114,831
NGL (MBbl)
U.S.	33,954	34,603	47,284	—	5,131	8,890	33,954	39,734	56,174
Canada	11	9	10	—	—	—	11	9	10
Total	33,965	34,612	47,294	—	5,131	8,890	33,965	39,743	56,184
Oil (MBbl)
U.S.	287	139	2,416	—	60	113	287	199	2,529
Canada	—	—	—	—	—	—	—	—	—
Total	287	139	2,416	—	60	113	287	199	2,529
Total (MMcfe)
U.S.	825,197	910,601	1,023,562	10,726	153,445	176,703	835,922	1,064,046	1,200,265
Canada	277,893	260,215	266,845	—	5,896	—	277,893	266,112	266,845
Total	1,103,090	1,170,816	1,290,407	10,726	159,341	176,703	1,113,815	1,330,158	1,467,110

	Years Ended December 31,
	2014		2013		2012
Representative prices for reserve estimation purposes:
Natural gas – Henry Hub, per MMBtu	$	4.35	$	3.67	$	2.76
Natural gas – AECO, per MMBtu	4.22		2.90		2.35
Oil – WTI Cushing, per Bbl	94.99		97.18		94.71
Standardized measure of discounted future net  cash flows (1) (in millions)	$	988.1	$	823.0	$	715.1

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

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

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PROVED UNDEVELOPED RESERVES

Our 2014 drilling and completion activities related to our proved undeveloped locations as of December 31, 2013 were as follows:

	For the Year Ended December 31, 2014
	Drilled		Completed		Producing
	Gross	Net	Gross	Net	Gross	Net
Barnett Shale	14.0	7.8	12.0	6.8	12.0	6.8
Horseshoe Canyon	15.0	6.9	15.0	6.9	15.0	6.9
Total	29.0	14.7	27.0	13.7	27.0	13.7

Costs incurred in 2014 relating to the drilling and completion activities, including allocable leasehold costs, related to our proved undeveloped locations as of December 31, 2013 were $37.3 million.

Our 2015 gross drilling and completion 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 $3.3 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.

The following table summarizes our proved undeveloped reserves activity during the year ended December 31, 2014 (in MMcfe):

Beginning proved undeveloped reserves	159,341
Transfers to proved developed	(45,327	)
Revisions of previous estimates	(103,288	)
Ending proved undeveloped reserves	10,726

The revisions of previous estimates are primarily related to our inability to recognize development plans beyond the current year given our liquidity position and the uncertainty of sources of capital to fund a drilling and completions program at December 31, 2014.

As of December 31, 2014, we had total proved undeveloped reserves of 10.7 Bcfe all located in our Barnett Shale Asset on four well locations, all of which are scheduled for development before the end of 2015. We expect to spend $8.8 million to drill, complete and tie-in wells on these proved locations.

DEVELOPMENT AND EXPLORATION ACTIVITIES AT YEAR END

At December 31, 2014, we had one drilling rig operating in our Barnett Shale Asset and one drilling rig operating in our West Texas Asset and no completion work was in progress. In the U.S. we had 20 (14.4 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 or Horseshoe Canyon Assets at December 31, 2014. In our Horn River Asset 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, 103 (82.1 net) wells in our Horseshoe Canyon Asset were awaiting completion or tie-in to sales lines at December 31, 2014.

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DRILLING ACTIVITY

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

	Years Ended December 31,
	2014		2013		2012
	Gross	Net	Gross	Net	Gross	Net
Development:
U.S.
Productive (1)	19	11.2	14	5.4	22	20.5
Non-productive	—	—	—	—	—	—
Canada
Productive (2)	37	21.6	3	0.4	2	2.0
Non-productive	—	—	—	—	—	—
Total	56	32.8	17	5.8	24	22.5
Exploratory:
U.S.
Productive	5	1.8	—	—	8	5.7
Non-productive	—	—	—	—	—	—
Canada
Productive	—	—	—	—	2	2.0
Non-productive	—	—	—	—	—	—
Total	5	1.8	—	—	10	7.7
Total:
Productive	61	34.6	17	5.8	34	30.2
Non-productive	—	—	—	—	—	—
Total	61	34.6	17	5.8	34	30.2

⁽¹⁾  U.S. development drilling includes non-operated drilling of 6 wells (1.1 net) and 2 wells (0.0 net) for 2013 and 2012, respectively. U.S. exploratory drilling includes non-operated drilling of 2 wells (0.3 net) for 2014.

⁽²⁾  Canadian development drilling includes non-operated drilling of 29 wells (14.4 net) and 3 wells (0.4 net) for 2014 and 2013, respectively.

VOLUME, SALES PRICES AND OIL AND NATURAL 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

Wehave contracts with third parties that require we provide minimum daily natural gas or NGL volume for gathering, processing, fractionation and transportation, as determined on a monthly basis, or pay for any deficiencies at a specified unused firm capacity rate. We will utilize production volumes from our wells, royalty volumes we control and other third-party volumes towards meeting our commitments below.

In Canada, we have incurred unused firm capacity expenses of $13.9 million, $7.4 million and $6.7 million for 2014, 2013 and 2012, respectively. As of December 31, 2014, we estimate such shortfall in our Horn River Asset in 2015 could be between $20 million and $24 million depending on our production levels and our ability to fulfill our commitment through third-party production. In late February 2015, QRCI did not pay an uneconomic Canadian gathering and processing commitment, which included significant unused firm capacity expense. In early March 2015, the third party service provider issued a demand letter regarding the missed payment and suspended service. Further, a termination notice was issued effective March 19, 2015. Upon termination, the third party drew C$33 million of an outstanding letter of credit. We expect that we and the third party will disagree as to what are the remaining obligations under the relevant agreement and the length of the remaining term of the agreement and as to the remedies and defenses available to the parties. While we expect to vigorously dispute the amount, we expect that the third party will claim to be entitled to up to approximately C$126 million (including the proceeds of the letter of credit) as the aggregate of the monthly tolls for firm capacity for the alleged remainder of the term of the relevant agreement. The table below includes estimated volumes with respect to this Canadian gathering and processing contract as of December 31, 2014.

We estimate the shortfall in 2015 due to unused firm capacity in our Horn River Asset, excluding the terminated contract, could be between $9 million and $12 million, which we expect to fund through cash on hand, cash from operations or through a negotiated reduction of our obligations.

As of December 31, 2014, our prospective volume obligations under existing agreements are summarized below:

	Total	2015	2016	2017	2018	2019	Thereafter
				(in MMcfe)
Gathering
Horn River	721,065	73,039	73,239	73,039	119,574	129,979	252,195
Processing, Treating and Fractionation
Barnett Shale	266,247	29,565	29,646	29,565	29,565	29,565	118,341
Horn River	103,637	30,359	30,443	30,359	9,108	3,368	—
Transportation
Barnett Shale	242,618	76,044	62,363	57,609	32,102	14,500	—
Horseshoe Canyon	18,494	4,175	3,362	3,289	3,289	3,289	1,090
Horn River	39,605	16,573	16,619	6,413	—	—	—

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 $0.73 to $0.88 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 2014, Targa Liquids Marketing and Trade and Kinder Morgan Texas Pipeline LP, the largest purchasers of our production, accounted for 17% and 13%, respectively, of our cash collected for natural gas, NGL and oil sales.

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As further discussed in Note 14 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. If we fail to make these expenditures we would be required to make a cash payment in the amount of the shortfall and if we are unable to make this payment or fulfill the volume commitments discussed above through cash payments, KKR has the right to liquidate the partnership and could assert a guarantee claim against us.

ACQUISITION, EXPLORATION AND DEVELOPMENT CAPITAL EXPENDITURES

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

	U.S.		Canada		Consolidated
	(in thousands)
2014
Proved acreage	$	—	$	—	$	—
Unproved acreage	21,722		5,519		27,241
Development costs	78,894		22,065		100,959
Exploration costs	63		—		63
Total	$	100,679	$	27,584	$	128,263
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

PRODUCTIVE OIL AND NATURAL GAS WELLS

The following table summarizes productive wells:

	As of December 31, 2014
	Natural Gas		Oil
	Gross	Net	Gross	Net
U.S.	983	590.0	6	3.1
Canada	2,949	1,462.7	3	0.1
Total	3,932	2,052.7	9	3.2

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OIL AND NATURAL GAS ACREAGE

Our principal oil and natural gas properties consist of non-producing and producing oil and natural gas leases and mineral acreage, including reserves of oil and natural gas 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.

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

	As of December 31, 2014
	Developed Acreage		Undeveloped Acreage
	Gross	Net	Gross	Net
Barnett Shale	99,847	63,806	41,960	24,953
West Texas	2,342	663	87,573	28,341
Other U.S.	11,401	7,816	178,642	103,578
U.S.	113,590	72,285	308,175	156,872
Horseshoe Canyon	466,237	287,501	64,221	55,052
Horn River Basin	15,617	13,730	122,208	112,773
Canada	481,854	301,231	186,429	167,825
Total	595,444	373,516	494,604	324,697

Other U.S. includes acreage where we previously had operations, including Colorado, Montana and Wyoming and West Texas acreage outside of Pecos, Crockett and Upton Counties. Theses areas are not included in our current development plans and this acreage will be allowed to expire.

The following table summarizes information regarding the total number of net undeveloped acres as of December 31, 2014:

		2015 Expirations		2016 Expirations		2017 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	24,953	3,921	381	3,890	2	7,164	2,748
West Texas	28,341	678	197	22,198	—	3,696	133
Other U.S.	103,578	49,262	3,819	19,234	—	15,450	—
Horseshoe Canyon	55,052	2,779	—	24,044	—	9,745	—
Horn River Basin	112,773	—	—	—	—	—	—
Total	324,697	56,640	4,397	69,366	2	36,055	2,881

Approximately 30% of each of our Barnett Shale and Horseshoe Canyon Assets undeveloped acreage does not expire as it is held by producing leases or is owned by us. In our Horn River Asset, approximately 10% of our undeveloped net acres expire in 2018 or 2019, while the remaining 90% has expiration terms between 2020 and 2023.

Acreage scheduled to expire in our core areas that we believe will provide an economic return can be held through drilling and producing operations or through the exercise of extension options. We may also be successful in negotiating agreeable terms to extend the lease expiration beyond the original expiration and extension period. To the extent the acreage is not economic due to location, lease renewal costs or well results in the area, acreage will be allowed to expire. Our current year capital program considers all development and lease payments required to meet near-term drilling plans.

Substantially all of our undeveloped acreage in Pecos County within our West Texas Asset is subject to continuous development clauses. These clauses will require that we and/or our partners drill a significant number

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of well locations between 2016 and 2018 to hold the related undeveloped acreage beyond the initial lease term expiration date. If we are unable to meet the requirements of these continuous development clauses in our West Texas Asset, we may lose the remaining undeveloped acreage associated with those leases.

COMPETITION

We compete for acquisitions of prospective oil and natural gas properties and oil and natural gas reserves. We also compete for drilling rigs and equipment used to drill for and produce oil and natural 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 and development areas. However, we face competition from a substantial number of other companies, many of which have larger technical staffs and greater and more stable 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.

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, the Government of 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,

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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, British Columbia and Alberta 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 emissions from oil and natural 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 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 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.

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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 March 17, 2015, we had 293 employees, none of whom are covered by collective bargaining agreements.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following information is provided with respect to our executive officers as of March 17, 2015.

Name	Age	Position(s)
Glenn Darden	59	Director, President and Chief Executive Officer
Anne Darden Self	57	Director, Vice President - Human Resources
Vanessa Gomez LaGatta	37	Senior Vice President - Chief Financial Officer and Treasurer
Stan Page	57	Senior Vice President - U.S. Operations
John D. Rushford	55	Senior Vice President and Chief Operating Officer of Quicksilver Resources Canada Inc.
Romy Massey	37	Vice President - Chief Accounting Officer
John Little	50	Strategic Alternatives Officer

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 and Anne Darden Self 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.

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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.

VANESSA GOMEZ LAGATTA became our Senior Vice President - Chief Financial Officer and Treasurer in January 2015, after serving as our Vice President - Treasurer since September 2009. Ms. LaGatta has over 15 years of financial experience in the energy industry. Ms. LaGatta also served as Quicksilver’s representative on the Board of Directors of Crestwood Midstream Partners GP LLC (the general partner of a publicly-traded midstream services provider) from August 2012 to October 2013. Prior to joining Quicksilver, Ms. LaGatta served as a Director of Credit Suisse’s Investment and Corporate Banking group, where she held various positions of increasing responsibility from 2001 to 2009.

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 natural 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.

ROMY MASSEY became our Vice President - Chief Accounting Officer in December 2014, after serving as our Controller since August 2012. Ms. Massey served as our Assistant Controller from January 2012 to August 2012. Ms. Massey has also served as Assistant Secretary since May 2014. Ms. Massey has 14 years of combined public accounting, corporate finance and financial reporting experience. Ms. Massey joined the Company from PricewaterhouseCoopers, where she was employed from September 2001 to January 2012 and served in various positions of increasing responsibility, including as Assurance Manager and Assurance Senior Manager from September 2007 to January 2012.

JOHN LITTLE was appointed our Strategic Alternatives Officer in September 2014 pursuant to an engagement agreement between us and Deloitte Transactions and Business Analytics LLP, a financial advisory services firm. Mr. Little has served as a principal of Deloitte or its affiliates since 2004, during which time he has led numerous engagements in a variety of industries.

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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.

We are subject to the risks and uncertainties associated with Chapter 11 proceedings.

For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan, and our continuation as a going concern, are subject to the risks and uncertainties associated with bankruptcy. These risks include the following:

• our ability to develop, confirm and consummate a Chapter 11 plan or alternative restructuring transaction, including a sale of all or substantially all of our assets;

• our ability to obtain court approval with respect to motions filed in the Chapter 11 proceedings from time to time;

• our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;

• our ability to maintain contracts that are critical to our operations;

• our ability to fund and execute our business plan;

• the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;

• the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for us to propose and confirm a Chapter 11 plan, to appoint a Chapter 11 trustee, or to convert the Chapter 11 proceedings to a chapter 7 proceeding; and

• the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 proceedings that may be inconsistent with our plans.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 proceedings, we cannot accurately predict or quantify the ultimate impact that events that occur during our Chapter 11 proceedings will have on our business, financial condition and results of operations.

We believe it is highly likely that the shares of our existing common stock will be cancelled in our Chapter 11 proceedings.

We have a significant amount of indebtedness that is senior to our existing common stock in our capital structure. As a result, we believe that it is highly likely that the shares of our existing common stock will be cancelled in our Chapter 11 proceedings and will be entitled to a limited recovery, if any. Any trading in shares of our common stock during the pendency of the Chapter 11 proceedings is highly speculative and poses substantial risks to purchasers of shares of our common stock.

Our businesses could suffer from a long and protracted restructuring.

Our future results are dependent upon the successful confirmation and implementation of a Chapter 11 plan or other alternative restructuring transaction, including a sale of all or substantially all of our assets. Failure to obtain confirmation of a Chapter 11 plan or approval and consummation of an alternative restructuring transaction in a timely manner may harm our ability to obtain financing to fund our operations, and there is a significant risk that the value of our enterprise would be substantially eroded to the detriment of all stakeholders. If a Chapter 11 plan that complies with the application provisions of the Bankruptcy Code cannot be agreed upon, it is possible that we would have to liquidate our assets, in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as a viable, reorganized entity.

There can be no assurance as to whether we will successfully reorganize and emerge from the Chapter 11 proceedings or, if we do successfully reorganize, as to when we would emerge from the Chapter 11 proceedings.

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Even after a Chapter 11 plan is confirmed and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders, suppliers and other third parties to do business with a company that recently emerged from bankruptcy proceedings.

We have substantial liquidity needs and may be required to seek additional financing. If we are unable to obtain 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.

Our principal sources of liquidity historically have been cash flow from operations, sales of oil and natural gas properties, borrowings under the Combined Credit Agreements, and issuances of debt securities. Our capital program will require additional financing above the level of cash generated by our operations to fund 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. In addition, drilling activity may be directed by our partners in certain areas and we may have to forfeit acreage if we do not have sufficient capital resources to fund our portion of expenses.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for the Chapter 11 proceedings and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. We cannot assure you that cash on hand and cash flow from operations will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to the Chapter 11 cases until we are able to emerge from our Chapter 11 proceedings.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of any cash collateral order entered by the Bankruptcy Court in connection with the Chapter 11 proceedings, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction, and (v) the cost, duration and outcome of the Chapter 11 proceedings. Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. In the event that cash on hand and cash flow from operations is not sufficient to meet our liquidity needs, we may be required to seek additional financing. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

In certain instances, a Chapter 11 case may be converted to a case under chapter 7 of the Bankruptcy Code.

If the Bankruptcy Court finds that it would be in the best interest of creditors and/or the U.S. Debtors, the Bankruptcy Court may convert our Chapter 11 bankruptcy case to a case under chapter 7 of the Bankruptcy Code. In such event, a chapter 7 trustee would be appointed or elected to liquidate the U.S. Debtors’ assets for distribution in accordance with the priorities established by the Bankruptcy Code. The U.S. Debtors believe that liquidation under chapter 7 would result in significantly smaller distributions being made to the U.S. Debtors’ creditors than those provided for in a Chapter 11 plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a disorderly fashion over a short period of time rather than reorganizing or selling in a controlled manner the U.S. Debtors’ businesses as a going concern, (ii) additional administrative expenses involved in the appointment of a chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

We may be subject to claims that will not be discharged in the Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to March 17, 2015 or before confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the Bankruptcy Code and the

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terms of the plan of reorganization. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

Our financial results may be volatile and may not reflect historical trends.

During the Chapter 11 proceedings, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments and may significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing.

In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

Transfers of our equity, or issuances of equity in connection with our Chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.

Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We have net operating loss carryforwards of approximately $810 million as of December 31, 2014. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more stockholders owning 5% or more of a corporation’s common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Following the implementation a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation.

We could lose all of our equity investment in QRCI and fail to receive any recovery for our intercompany indebtedness with QRCI if QRCI files for creditor protection under the CCAA.

If QRCI files for creditor protection under the CCAA, we could potentially lose all of our equity investment in QRCI and QRCI could cease to be our subsidiary. QRCI has a significant amount of indebtedness that is senior to our existing equity in QRCI, and we believe that it is highly likely that our existing equity in QRCI would be cancelled in any CCAA proceedings. We also have an unsecured intercompany note with QRCI for an aggregate principal amount of approximately $413 million as of December 31, 2014. We believe that we would be entitled to receive our pro rata share of the consideration that would be distributed to unsecured creditors in any CCAA proceedings. However, it is possible that the other stakeholders in the CCAA proceedings could seek to recharacterize our unsecured indebtedness as an equity investment due to the intercompany nature of the indebtedness. If such stakeholders were successful, then we would also be unlikely to receive any recovery for the amount of the indebtedness under the intercompany note since all of the equity in QRCI would likely be cancelled in any CCAA proceedings.

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 and the proposed liquefaction facility 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.

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Additionally, we have minimum gross capital expenditure requirements in our Horn River Asset that if we are unable to meet would result in a substantial cash penalty payable to Fortune Creek. If we are unable to satisfy this obligation through cash payments, KKR has the right to liquidate the partnership and could assert a guarantee claim against us.

Commodity prices fluctuate widely, and low prices could 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 fund our capital program and our other liquidity needs, as well as our ability to borrow and raise additional capital. Lower prices may also reduce the amount of natural gas, NGLs and oil that we can economically produce.

Prices for our production fluctuate widely, particularly as evidenced by price movements between 2008 and 2014. Factors that can cause these fluctuations include, but are not limited to:

• 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. Further, we routinely sell a portion of our production at monthly fixed index prices. Our ability to continue to enter into monthly fixed index sales agreements may be limited as a result of our counterparties' view of our financial condition, particularly involving our Canadian entity. As such, we may be subject to selling our gas on a daily spot index, which may cause greater volatility in our revenues.

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 natural gas properties which, among other things, imposes limits to the capitalized cost of our assets. The capitalized cost cannot exceed the present value of the estimated cash flows from the underlying oil and natural 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 natural 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.

We have significant exposure to fluctuations in commodity prices since a significant portion of our estimated future production is not covered by commodity derivatives and we may not be able to enter into commodity derivatives covering our estimated future production on favorable terms or at all.

As of March 31, 2015, our portfolio of commodity derivatives is only 20 MMcfd through the end of 2015. During the Chapter 11 proceedings, our ability to enter into new commodity derivatives covering additional estimated future production will be dependent upon either entering into unsecured hedges or obtaining Bankruptcy Court approval to enter into secured hedges. As a result, 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

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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.

If we are able to enter into any commodity derivatives, they may limit the benefit we would receive from increases in commodity prices. These arrangements would 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 any 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.

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 2014 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. 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 natural 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 natural 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,

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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 natural 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 natural 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 natural 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 natural 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 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.

Significant payments required from us under firm capacity contracts could have a material adverse effect on our business, financial condition or results of operations.

Under contracts with various third parties, we are obligated to provide minimum daily natural gas or NGL 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. In late February 2015, QRCI did not pay an uneconomic Canadian gathering and processing commitment, which included significant unused firm capacity. In early March 2015, the third party service provider issued a demand letter regarding the missed payment and suspended service.

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Further, a termination notice was issued effective March 19, 2015. Upon termination, the third party drew down C$33 million of an issued letter of credit. We expect that we and the third party will disagree as to what are the remaining obligations under the relevant agreement and the length of the remaining term of the agreement and as to the remedies and defenses available to the parties. While we expect to vigorously dispute the amount, we expect that the third party will claim to be entitled to up to approximately C$126 million (including the proceeds of the letter of credit) as the aggregate of the monthly tolls for firm capacity for the alleged remainder of the term of the relevant agreement.

We estimate the expense for unused firm capacity in 2015 due in our Horn River Asset, excluding the terminated contract, could be between $9 million and $12 million, depending on our production levels and our ability to fulfill our commitments through third-party production. If we are unable to satisfy this obligation through cash payments, KKR has the right to liquidate Fortune Creek and could assert a guarantee claim against us.

Our business involves many hazards and operational risks.

Our operations are subject to many risks inherent in the oil and natural gas industry, including, but not limited to, 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 or our financial outlook, 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.

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

Oil and natural 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,

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our business, financial condition and results of operations would be materially adversely affected. Further, our limited liquidity has caused us to significantly 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 a providers' contractual right to limit or suspend services due to their economic conditions, 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.

Additionally, QRCI may be unable to secure gas gathering and processing services for its Horn River production following the suspension of service by our previous provider. We are exploring alternatives to gather and process our Horn River Asset production; however, we may not be able to find economic alternatives in the near-term, or at all.

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 natural 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 natural 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 natural 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 natural 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 natural gas companies could have a material adverse impact on our business activities, financial condition and results of operations.

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.

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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;

• 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 oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. 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 oil and natural gas exploration and development, and those provisions may be limited or repealed by future legislation.

The Obama administration's 2015 budget proposes to eliminate certain U.S. federal income tax benefits currently available to oil and natural 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; 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

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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. This increased scrutiny has led to heightened enforcement of existing regulations as well as the imposition of new air emission measures, and the EPA plans to propose further expanded requirements to reduce volatile organic compound and methane emissions. 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 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 is conducting a study to determine the environmental and health impacts of hydraulic fracturing and has 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. Generally, the 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.

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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 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.

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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 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 us, 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, though Congress, through the passage of the Business Risk Mitigation and Price Stabilization Act of 2015, amended the Commodity Exchange Act to exclude non-financial end-users, such as us, from margin requirements for uncleared swaps used to hedge or mitigate commercial risk. However, 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 management personnel and employees and the loss of additional personnel could adversely affect our operations.

Our operations are dependent on a relatively small group of key management personnel, including our executive officers. Our recent liquidity issues and our Chapter 11 proceedings have created distractions and uncertainty for our key management personnel and our employees. As a result, we have experienced and may continue to experience increased levels of employee attrition. Because competition for experienced personnel in our industry can be intense, we may be unable to find acceptable replacements with comparable skills and

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experience and their loss could adversely affect our ability to operate our business. In addition, a loss of key personnel or material erosion of employee morale, at the corporate and field levels, could have a material adverse effect on our ability to meet customer and counterparty expectations, thereby adversely affecting our business and results of operations.

Our common stock is no longer listed on a national securities exchange and is quoted only in over-the-counter markets, which carries substantial risks and could continue to negatively impact our stock price, volatility and liquidity.

Our common stock was previously listed on the NYSE under the trading symbol “KWK.” The NYSE placed a trading halt on our common stock in light of its abnormally low trading price and suspended our listing before the opening of the market on January 8, 2015. Our common stock is now quoted on the OTC Pink under the symbol “KWKAQ.”

Securities traded in over-the-counter markets such as the OTC Pink generally have substantially less volume and liquidity than securities traded on a national securities exchange such as the NYSE as a result of various factors, including the reduced number of investors that will consider investing in the securities, fewer market makers in the securities, and a reduction in securities analyst and news media coverage. As a result, holders of shares of our common stock may have difficulty selling their shares and our stock price could experience additional downward pressure. Furthermore, the price of our common stock could be subject to greater volatility and could be more likely to be affected by market conditions and fluctuations, changes in our operating results, market perception of us and our business, developments regarding our restructuring, and announcements by us or other parties with an interest in our business or restructuring.

We may be subject to additional compliance requirements under applicable state laws in connection with the issuance of our securities. The lack of liquidity in our common stock may also make it difficult for us to issue additional securities for financing or other purposes, or to otherwise arrange for any financing we may need in the future.

If we fail to remain current on our reporting requirements, we could be subject enforcement action by the Securities and Exchange Commission or we could incur liability to our stockholders.

Failure to remain current in our reporting obligations under the Securities Exchange Act of 1934 could also subject us to enforcement action by the Securities and Exchange Commission or private rights of action by our stockholders.

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 March 17, 2015, members of the Darden family, together with entities controlled by them, beneficially owned approximately 25% 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 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.

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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.

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 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 2014 developments can be found in Item 1 of this Annual Report, which is incorporated herein by reference.

ITEM 3. Legal Proceedings

On March 17, 2015, the U.S. Debtors filed voluntary petitions under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Chapter 11 cases are being jointly administered for procedural purposes only by the Bankruptcy Court under the caption In re Quicksilver Resources Inc., et. al., Case No. 15-10585 (Jointly Administered). In addition to the Chapter 11 proceedings, we are also a defendant in lawsuits from time to time in the normal course of business. Generally, all actions to enforce or otherwise effect repayment of liabilities preceding the Chapter 11 filing date as well as pending litigation against the U.S. Debtors are stayed during the pendency of the U.S. Debtors’ Chapter 11 cases. Other than the Chapter 11 proceedings, 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 quoted on the OTC Pink under the symbol “KWKAQ.”

The following table sets forth the quarterly high and low in-trading sales prices of our common stock for the periods indicated below as traded on the NYSE under the symbol “KWK.”

	HIGH		LOW
2014
Fourth Quarter	$	0.92	$	0.18
Third Quarter	2.68		0.51
Second Quarter	3.53		2.28
First Quarter	3.67		2.38
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

As of March 17, 2015, there were approximately 506 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 (KWKAQ) 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, 2009 to December 31, 2014, 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

We had no repurchases of Quicksilver common stock during the quarter ended December 31, 2014.

Notice Procedures and Transfer Restrictions

On March 17, 2015, we filed a motion in the Bankruptcy Court for the entry of an order pursuant to Sections 105(a), 362(a)(3) and 541 of the Bankruptcy Code to enable us to avoid limitations on the use of our tax net operating loss carryforwards and certain other tax attributes by imposing certain notice procedures and transfer restrictions on the trading of our equity securities. The Bankruptcy Court granted the requested order on an interim basis on March 19, 2015. The Bankruptcy Court will hold a final hearing on this request on April 15, 2015.

In general, the order applies to any person or entity that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least 4.75% of our outstanding equity securities. Substantial Equityholders are required to file with the Bankruptcy Court and serve us with notice of such status. In addition, the order provides that a person or entity that would become a Substantial Equityholder by reason of a proposed acquisition of our equity securities is also required to comply with the notice and service provisions before effecting that transaction. The order gives us the right to seek an injunction from the Bankruptcy Court to prevent certain acquisitions or sales of our common stock if the acquisition or sale would pose a material risk of adversely affecting our ability to utilize such tax attributes.

Under the order, prior to any proposed acquisition of equity securities that would result in an increase in the amount of our equity securities owned by a Substantial Equityholder, or that would result in a person or entity becoming a Substantial Equityholder, such person, entity or Substantial Equityholder is required to file with the Bankruptcy Court, and serve on the Company, a Notice of Intent to Purchase, Acquire or Otherwise Accumulate an Equity Security. In addition, prior to effecting any disposition of our equity securities that would result in a decrease in the amount of our equity securities beneficially owned by a Substantial Equityholder, such Substantial Equityholder is required to file with the Bankruptcy Court, and serve on the Company, a Notice of Intent to Sell, Trade or Otherwise Transfer Equity Securities.

Any purchase, sale or other transfer of our equity securities in violation of the restrictions of the order would be null and void ab initio as an act in violation of such order and would therefore confer no rights on a proposed transferee.

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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,
	2014 (1)			2013 (2)			2012 (3)			2011 (4)		2010 (5)
	(in thousands, except for per share data)
Operating Results Information
Total revenue	$	569,428		$	561,562		$	709,038		$	943,623	$	928,331
Operating income (loss)	85,434			464,644			(2,465,761		)	122,604		804,134
Income (loss) before income taxes	(99,500		)	176,168			(2,648,176		)	147,909		713,828
Net income (loss)	(103,100		)	161,618			(2,352,606		)	90,046		455,290
Net income (loss) attributable to Quicksilver	(103,100		)	161,618			(2,352,606		)	90,046		445,566
Diluted earnings (loss) per common share	$	(0.59	)	$	0.92		$	(13.83	)	$	0.52	$	2.50
Dividends paid per share	—			—			—			—		—
Financial Condition Information
Property, plant and equipment - net	$	728,780		$	860,805		$	1,029,058		$	3,460,519	$	3,063,245
Midstream assets held for sale - net	—			—			—			—		27,178
Total assets	1,214,302			1,369,726			1,381,788			3,995,462		3,507,734
Current portion of long-term debt	2,037,305			—			—			18		143,478
Long-term debt	—			1,988,946			2,063,206			1,903,431		1,746,716
All other long-term obligations	211,136			251,953			283,588			495,939		248,762
Total equity	(1,137,871		)	(1,005,970		)	(1,132,797		)	1,261,919		1,069,905
Cash Flow Information
Cash provided by (used in) operating activities	$	(7,629	)	$	(51,700	)	$	227,727		$	253,053	$	397,720
Capital expenditures	133,481			101,288			485,479			690,607		695,114

⁽¹⁾  Operating income for 2014 includes charges for impairment of $72.0 million related to our Fortune Creek gathering system, land and buildings in Texas and midstream assets in Texas. The entirety of our long-term debt was classified as current at December 31, 2014 based on our subsequent Chapter 11 filings.

⁽²⁾  Operating income for 2013 includes a gain of $339.3 million from the Tokyo Gas Transaction. Net income includes a charge of $12.8 million in connection with the termination of the PEA with NGTL.

⁽³⁾  Operating loss for 2012 includes charges for impairment of $2.6 billion for U.S. and Canadian oil and natural gas properties and certain midstream assets in Colorado. Net loss includes a tax valuation allowance of $595.3 million.

⁽⁴⁾  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 natural gas properties, respectively.

⁽⁵⁾  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 natural gas properties, respectively.

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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:

• Chapter 11 Filings – a description of our recent events and our Chapter 11 filings

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

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

• 2015 Capital Program – a summary of our planned capital expenditures during 2015

• 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.

CHAPTER 11 FILINGS

During the third quarter of 2014, we launched a formal marketing process, led by Houlihan Lokey, covering any and all of our operating assets. During the formal marketing process, we also received additional amendments to the financial covenants to our Combined Credit Agreements. These amendments, which included the replacement of the minimum interest coverage ratio with a minimum EBITDAX requirement, provided relief from the continued pressure on our cash flows relative to our obligations, which in turn allowed time for the formal marketing process. Bids were initially due in December 2014, but the bid deadline was subsequently extended to late January 2015. After the bid deadline passed, we evaluated the bids that were received with our advisors. Following discussions with various bidders, we concluded that the marketing process had not yet produced any viable options for asset sales or other strategic alternatives that would likely have a material impact on our capital structure or liquidity.

In February 2015, in light of (a) not yet having identified a transaction that would have a material impact on our capital structure or liquidity, (b) the potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, and (c) other potential defaults, we elected not to make the approximately $13.6 million interest payment on our Senior Notes due 2019, which was due on February 17, 2015. During the 30-day grace period provided for in the Senior Notes due 2019 Indenture, we continued discussions with our creditors. The discussions with our creditors did not produce an agreement that would enable us to effectively address, in a holistic manner, the impending issues adversely impacting our business, including (i) potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, (ii) potential near-term liquidity shortfalls due to the springing maturities, (iii) potential near-term breaches of certain financial covenants resulting from sharp declines in natural gas and NGL prices, and (iv) certain other potential defaults under our Combined Credit Agreements and the Second Lien Term Loan.

Accordingly, on March 17, 2015, the Company and our subsidiaries Barnett Shale Operating LLC, Cowtown Drilling, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline Funding, Inc., Cowtown Pipeline L.P., Cowtown Pipeline Management, Inc., Makarios Resources International Holdings LLC, Makarios Resources International Inc., QPP Holdings LLC, QPP Parent LLC, Quicksilver Production Partners GP LLC, Quicksilver Production Partners LP, and Silver Stream Pipeline Company LLC each filed a voluntary petition under Chapter

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11 of the Bankruptcy Code in the Bankruptcy Court to restructure our obligations and capital structure. The Chapter 11 cases are being jointly administered for procedural purposes only by the Bankruptcy Court under the caption In re Quicksilver Resources Inc., et. al., Case No. 15-10585 (Jointly Administered).

We are currently operating our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As part of our “first day” motions in the Chapter 11 proceedings, we obtained Bankruptcy Court approval to, among other things and subject to the applicable caps contained in the orders of the Bankruptcy Court, on an interim basis, pay employee wages, health benefits and certain other employee obligations, to pay certain lienholders and critical vendors and forward funds belonging to third parties, including royalty holders and other partners. A final hearing on the motions to satisfy our obligations to certain third parties and to forward funds held by us that belong to third parties will be held on April 15, 2015.

On March 16, 2015, we, along with QRCI, entered into the Forbearance Agreement with the administrative agents and certain of the lenders under the Combined Credit Agreements. As a result of the Chapter 11 filing, the obligations under the Combined Credit Agreements were automatically accelerated. However, pursuant to the Forbearance Agreement, the administrative agents and the lenders agreed to, among other things, (i) forbear from exercising their rights and remedies in connection with specified defaults under the Amended and Restated Canadian Credit Facility related to our Chapter 11 filing until the earlier of June 16, 2015 or certain other events specified in the Forbearance Agreement, including, among other things, the commencement by QRCI or certain specified Canadian subsidiary guarantors of insolvency proceedings and (ii) waive compliance with certain specified terms and conditions relating to the renewal of outstanding evergreen letters of credit under the Combined Credit Agreements.

For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A, “Risk Factors.” As a result of these risks and uncertainties, the number of our outstanding shares and our shareholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Annual Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

In particular, subject to certain exceptions, under the Bankruptcy Code, the U.S. Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the U.S. Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert claims against the applicable U.S. Debtor's estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the U.S. Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the U.S. Debtor in this Annual Report, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the U.S. Debtor is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the U.S. Debtors expressly preserve all of their rights with respect thereto.

There can be no assurances regarding our ability to successfully develop, confirm and consummate one or more plans of reorganization or other alternative restructuring transactions, including a sale of all or substantially all of our assets, that satisfies the conditions of the Bankruptcy Code and, is authorized by the Bankruptcy Court.

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OVERVIEW

We are an independent oil and natural 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, 2014, 82% and 18% of our proved reserves were natural gas and NGLs, respectively. We 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 approximately 75%, 19% and 6%, respectively, of our proved reserves at December 31, 2014.

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,
	2014 (2)			2013 (3)			2012 (4)
Organic reserve growth (1)	(9		)%	22		%	(42		)%
Production volume (Bcfe)	90.3			108.0			131.8
Cash flow from operating activities (in millions)	$	(7.6	)	$	(51.7	)	$	227.7
Diluted earnings (loss) per share	$	(0.59	)	$	0.92		$	(13.83	)

⁽¹⁾  This rate 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⁾  During 2014, we recognized substantial negative reserve revisions primarily due to lower projected future capital spend based on our constrained liquidity position and the uncertainty of sources of capital to fund a drilling and completions program at December 31, 2014. Our capital budget projection over the next five years was constrained by our operating cash flow and our liquidity, and thus, the number of overall PUD locations in 2014 decreased compared to 2013. This impact reduced our organic reserve growth and contributed to the negative growth during the year.

⁽³⁾  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 at December 31, 2013 was 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.

⁽⁴⁾  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,

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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.

Our reserve growth depends on our ability to fund a drilling program. However, our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Reserve growth 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 management of our operations and through relatively low-risk developmental drilling. Additionally, through a targeted, low-cost workover program, we have been able to reduce the decline rates in our existing development areas.

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.

2014 DEVELOPMENTS

In March 2014, we agreed with KKR to an amendment to extend the ending date of the remaining required capital spending to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset and to broaden allowable spending to include acquisitions of producing properties that utilize partnership assets. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by C$0.13 per Mcf until at least 2016. Additionally, as a result of this amendment, KKR is no longer required to fund the capital for construction of a proposed gas treatment facility, but at its option may provide funding for any facility to be constructed by the partnership, including the proposed gas treatment facility. The amendment provided 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 May 2014, we completed the sale of our Niobrara Asset to Southwestern. The purchase price was subject to customary purchase price adjustments, which resulted in Southwestern paying us $95.6 million. The decision to sell this acreage was largely rooted in the planned exit of our operating partner, SWEPI, from its North American shale plays, including the shared interest in our Niobrara Asset.

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

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2015 CAPITAL PROGRAM

We expect our 2015 capital program, through September 2015, to be spent in the following areas:

	(in millions)
Barnett Shale	$	18
West Texas	10
Total U.S.	28
Canada	1
Corporate (1)	15
Total Company	$	44

⁽¹⁾ Includes capitalized interest expense and capitalized internal costs related to our development and exploration areas.

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 historically sought to manage this risk by entering into derivative contracts. We historically 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 historically enhanced 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. The impacts of the Southwestern and Synergy Transactions were immaterial for further disaggregation.

Revenue

We aggregate production revenue and realized cash gains (losses) on derivatives not treated as hedges in measuring revenue from our oil and natural 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
	2014			2013		2012		2014			2013			2012		2014		2013		2012		2014			2013		2012
	(in millions)
Barnett Shale	$	195.6		$	180.4	$	200.9	$	61.6		$	80.5		$	137.5	$	4.4	$	6.6	$	10.9	$	261.6		$	267.5	$	349.3
Other U.S.	0.1			0.1		0.6		—			0.3			0.5		2.4		9.0		13.7		2.5			9.4		14.8
Hedging	28.3			55.1		151.3		—			—			23.5		—		—		—		28.3			55.1		174.8
U.S.	224.0			235.6		352.8		61.6			80.8			161.5		6.8		15.6		24.6		292.4			332.0		538.9
Horseshoe Canyon	68.4			56.6		48.2		0.1			0.2			0.1		—		—		—		68.5			56.8		48.3
Horn River	55.5			61.6		23.9		—			—			—		—		—		—		55.5			61.6		23.9
Hedging	8.8			13.1		19.8		—			—			—		—		—		—		8.8			13.1		19.8
Canada	132.7			131.3		91.9		0.1			0.2			0.1		—		—		—		132.8			131.5		92.0
Consolidated production revenue	$	356.7		$	366.9	$	444.7	$	61.7		$	81.0		$	161.6	$	6.8	$	15.6	$	24.6	$	425.2		$	463.5	$	630.9
U.S. realized cash derivative gains (losses)	$	(2.0	)	$	11.7	$	23.0	$	(2.3	)	$	(1.4	)	$	—	$	—	$	—	$	—	$	(4.3	)	$	10.3	$	23.0
Canada realized cash derivative gains	1.5			10.9		19.8		—			—			—		—		—		—		1.5			10.9		19.8
Consolidated realized cash derivative gains (losses)	(0.5		)	22.6		42.8		(2.3		)	(1.4		)	—		—		—		—		(2.8		)	21.2		42.8
Consolidated production revenue and realized cash derivative gains (1)	$	356.2		$	389.5	$	487.5	$	59.4		$	79.6		$	161.6	$	6.8	$	15.6	$	24.6	$	422.4		$	484.7	$	673.7

⁽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.

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Average Daily Production Volume by Operating Area:

	Natural Gas			NGL			Oil			Equivalent Total
	2014	2013	2012	2014	2013	2012	2014	2013	2012	2014	2013	2012
	(MMcfd)			(Bbld)			(Bbld)			(MMcfed)
Barnett Shale	126.0	139.8	206.2	5,768	7,727	11,090	138	194	333	161.4	187.3	274.8
Other U.S.	0.1	0.1	0.6	—	15	26	85	281	451	0.6	1.9	3.5
U.S.	126.1	139.9	206.8	5,768	7,742	11,116	223	475	784	162.0	189.2	278.3
Horseshoe Canyon	46.8	49.7	54.6	5	5	5	—	—	—	46.8	49.7	54.6
Horn River	38.6	56.9	27.1	—	—	—	—	—	—	38.6	56.9	27.1
Canada	85.4	106.6	81.7	5	5	5	—	—	—	85.4	106.6	81.7
Consolidated	211.5	246.5	288.5	5,773	7,747	11,121	223	475	784	247.4	295.8	360.0

Average Realized Price by Operating Area:

	Natural Gas							NGL								Oil						Equivalent Total
	2014			2013		2012		2014			2013			2012		2014		2013		2012		2014			2013		2012
	(per Mcf)							(per Bbl)								(per Bbl)						(per Mcfe)
Barnett Shale	$	4.25		$	3.54	$	2.66	$	29.23		$	28.53		$	33.87	$	88.49	$	92.48	$	89.85	$	4.44		$	3.92	$	3.47
Other U.S.	—			4.68		2.59		—			51.00			50.83		75.17		87.50		83.13		9.67			13.06		11.57
Hedging	0.62			1.08		2.00		—			—			5.77		—		—		—		0.48			0.80		1.72
U.S.	$	4.87		$	4.62	$	4.66	$	29.23		$	28.57		$	39.67	$	83.42	$	89.53	$	85.98	$	4.94		$	4.81	$	5.29
Horseshoe Canyon	$	4.01		$	3.12	$	2.41	$	42.37		$	66.15		$	61.12	$	—	$	—	$	—	$	4.01		$	3.12	$	2.41
Horn River	3.93			2.96		2.40		—			—			—		—		—		—		3.93			2.97		2.41
Hedging	0.28			0.34		0.66		—			—			—		—		—		—		0.28			0.34		0.66
Canada	$	4.26		$	3.37	$	3.07	$	42.37		$	66.15		$	67.91	$	—	$	—	$	—	$	4.26		$	3.38	$	3.07
Consolidated production revenue	$	4.62		$	4.08	$	4.21	$	29.24		$	28.60		$	39.69	$	83.42	$	89.53	$	85.98	$	4.71		$	4.29	$	4.79
U.S. realized cash derivative gains (losses)	$	(0.04	)	$	0.23	$	0.30	$	(1.07	)	$	(0.48	)	$	—	$	—	$	—	$	—	$	(0.07	)	$	0.15	$	0.23
Canada realized cash derivative gains	0.05			0.28		0.66		—			—			—		—		—		—		0.05			0.28		0.66
Consolidated realized cash derivative gains (losses)	(0.01		)	0.25		0.41		(1.07		)	(0.48		)	—		—		—		—		(0.03		)	0.20		0.32
Consolidated production revenue and realized cash derivative gains	$	4.61		$	4.33	$	4.62	$	28.17		$	28.12		$	39.69	$	83.42	$	89.53	$	85.98	$	4.68		$	4.49	$	5.11

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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 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
Volume variances	(42,510		)	(20,621		)	(8,226		)	(71,357		)
Hedge revenue variances	(31,044		)	—			—			(31,044		)
Realized cash derivative variance (1)	(23,152		)	(891		)	—			(24,043		)
Price variances	63,224			1,338			(498		)	64,064
Consolidated production revenue and realized cash derivative gains for the 2014 period	$	356,188		$	59,354		$	6,797		$	422,339

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

Our natural gas revenue, without the effects of realized cash derivative gains/losses or hedge revenue, increased for 2014 from 2013 primarily due to an increase in our realized price. Lower volumes produced in 2014 were primarily attributable to the Tokyo Gas Transaction and natural declines in our Barnett Shale and Horn River Assets partially offset by new well production reduced natural gas revenue. As the realized prices have increased, our hedge revenue and realized cash derivative gain/loss have decreased for 2014 compared to 2013 due to the expiration of a portion of our derivatives and a lower average fixed price on the remaining portfolio. Consolidated production revenue and realized cash derivative gains from NGL revenue for 2014 decreased from 2013 due to lower volumes produced primarily attributable to the Tokyo Gas Transaction and declining well production and a derivative loss in 2014, partially offset by an increase in realized prices. Our oil revenue decreased for 2014 from 2013 due to lower volumes resulting from the Synergy Transaction.

Our natural gas revenue, without the effects of realized cash derivative gains/losses or hedge revenue, decreased for 2013 from 2012 due to lower volumes produced partially offset by an increase in our realized price. As the realized prices increased, 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 and a lower average fixed price on the remaining portfolio. 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.

Our production revenue for 2014 and 2013 was higher by $37.1 million and $68.2 million, respectively, because of our hedging activities.

We expect our 2015 production volumes to decline across all assets as our 2015 capital program does not include a full year of drilling. Additionally, we are actively managing our current wells in this price environment. We have shut-in wells that are not economical at current prices which will impact our variable components of our operating costs and our unit costs as fixed costs are allocated over lower production.

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In early March 2015, a third party service provider suspended service resulting in our production in our Horn River Asset being shut-in. We are exploring alternatives to gather and process our Horn River Asset production; however, we may not be able to find economic alternatives in the near-term, or at all.

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas

	Years Ended December 31,
	2014		2013		2012
			(in thousands)
Sales of purchased natural gas:
Purchases from Eni	$	67,027	$	62,103	$	58,881
Purchases from others	3,441		2,810		3,524
Total	70,468		64,913		62,405
Costs of purchased natural gas sold:
Purchases from Eni	67,000		62,126		58,915
Purchases from others	3,376		2,714		3,126
Total	70,376		64,840		62,041
Net sales and purchases of natural gas	$	92	$	73	$	364

We purchase Eni’s interest in natural gas production in our Alliance Asset and then sell the natural gas to others.

Net Derivative Gains

The following table summarizes our net derivative gains and losses:

	Years Ended December 31,
	2014			2013			2012
				(in thousands)
Unrealized mark-to-market changes in fair value of natural gas derivative gains (losses) (1)	$	66,914		$	10,299		$	(17,880	)
Realized cash settlements of natural gas derivative gains (losses)	(562		)	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 gains (losses) (1)	1,599			(1,599		)	—
Realized cash settlements of NGL derivative losses	(2,253		)	(1,362		)	—
Gain from hedge ineffectiveness	—			—			1,281
Net derivative gains	$	65,698		$	29,928		$	11,444

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

In December 2014, we terminated a portion of one long-dated derivative contract of 10 MMcfd in the U.S. for the period from 2016 to 2021 in exchange for $5.8 million in cash, which is included in realized cash settlements of natural gas derivative gains (losses) above. 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.

Certain of our derivative positions were restructured or terminated in January and March 2015 prior to our Chapter 11 filings. Additionally, our Chapter 11 filings in March 2015 represented an event of default under our derivative agreements resulting in a termination right by counterparties on the remaining derivative position at

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March 17, 2015. As a result, we have reduced our daily production volume of natural gas economically hedged to 20 MMcfd in 2015 and we no longer have any derivatives beyond 2015.

Other Revenue

	Years Ended December 31,
	2014		2013		2012
			(in thousands)
Midstream revenue from third parties:
Canada	$	2,367	$	2,388	$	2,523
Texas	5,741		842		1,687
Total midstream revenue	8,108		3,230		4,210
Other	—		—		32
Total	$	8,108	$	3,230	$	4,242

In 2014, we recognized previously deferred midstream revenue of $4.1 million related to funds received from a third party in prior years in exchange for a preferential gathering rate. We will recognize the remaining $15.1 million between 2015 and 2018. The amounts to be recognized in each period are dependent on the estimated volumes remaining to be delivered under the terms of the contract.

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Operating Expense

Lease Operating Expense

	Years Ended December 31,
	2014				2013				2012
	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe				Per Mcfe
Barnett Shale
Expense	$	37,228	$	0.63	$	43,270	$	0.63	$	53,509	$	0.53
Equity compensation expense	528		0.01		842		0.01		997		0.01
	$	37,756	$	0.64	$	44,112	$	0.64	$	54,506	$	0.54
Other U.S.
Expense	$	2,065	$	8.92	$	4,889	$	7.22	$	8,317	$	6.49
Equity compensation expense	131		0.57		323		0.48		166		0.13
	$	2,196	$	9.49	$	5,212	$	7.70	$	8,483	$	6.62
Total U.S.
Expense	$	39,293	$	0.66	$	48,159	$	0.70	$	61,826	$	0.61
Equity compensation expense	659		0.01		1,165		0.02		1,163		0.01
	$	39,952	$	0.67	$	49,324	$	0.72	$	62,989	$	0.62
Horseshoe Canyon
Expense	$	25,386	$	1.49	$	28,504	$	1.57	$	29,107	$	1.46
Equity compensation expense	1,452		0.09		290		0.02		375		0.02
	$	26,838	$	1.58	$	28,794	$	1.59	$	29,482	$	1.48
Horn River
Expense	$	10,185	$	0.72	$	4,147	$	0.20	$	2,862	$	0.29
Equity compensation expense	—		—		—		—		—		—
	$	10,185	$	0.72	$	4,147	$	0.20	$	2,862	$	0.29
Total Canada
Expense	$	35,571	$	1.14	$	32,651	$	0.84	$	31,969	$	1.07
Equity compensation expense	1,452		0.05		290		0.01		375		0.01
	$	37,023	$	1.19	$	32,941	$	0.85	$	32,344	$	1.08
Total Company
Expense	$	74,864	$	0.83	$	80,810	$	0.75	$	93,795	$	0.71
Equity compensation expense	2,111		0.02		1,455		0.01		1,538		0.01
	$	76,975	$	0.85	$	82,265	$	0.76	$	95,333	$	0.72

Lease operating expense in the U.S. decreased in 2014 compared to 2013 in total primarily due to lower non-cash inventory impairment in 2014, lower volumes due to the Tokyo Gas Transaction, lower employee costs due to the Southwestern and Synergy Transactions, and customary review of recoveries from a joint venture partner. On a unit basis, the U.S. lease operating expense decreased in 2014 primarily due to lower non-cash inventory impairments compared to 2013 and customary review of recoveries from a joint venture partner. In Canada, the decrease in 2014 lease operating expense in Horseshoe Canyon compared to 2013 is primarily due to lower cash-settled stock based compensation expense and a stronger U.S. dollar, which also lowered the per unit cost. The increase in equity compensation expense in Horseshoe Canyon in 2014 compared to 2013 is primarily due to employee compensation being issued in equity during 2014 compared to cash-settled equity in 2013. The increase in total and on a unit basis in Horn River in 2014 compared to 2013 is primarily due to non-cash inventory impairments in 2014 and lower produced volumes as the result of well decline curves.

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Lease operating expense in the Barnett Shale decreased from 2012 to 2013 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 from 2013 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.

Gathering, Processing and Transportation Expense

	Years Ended December 31,
	2014				2013				2012
	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe				Per Mcfe
Barnett Shale	$	92,979	$	1.58	$	104,462	$	1.53	$	141,269	$	1.40
Other U.S.	9		0.04		9		0.01		13		0.01
Total U.S.	$	92,988	$	1.57	$	104,471	$	1.51	$	141,282	$	1.39
Horseshoe Canyon	3,308		0.19		3,274		0.18		3,547		0.18
Horn River	39,987		2.84		40,824		1.96		21,487		2.16
Total Canada	43,295		1.39		44,098		1.13		25,034		0.84
Total	$	136,283	$	1.51	$	148,569	$	1.38	$	166,316	$	1.26

U.S. GPT decreased in total for 2014 compared to 2013 primarily due to lower production volume in our Barnett Shale Asset, with the Tokyo Gas Transaction contributing to this decline, and 2013 included a $2.5 million expense resulting from a customary audit of expenses paid by a joint venture partner. The increase on a unit basis was primarily the result of higher unused capacity expense for our natural gas and NGL transportation in 2014 compared to 2013, contractual annual rate increases, and production area mix within our Barnett Shale Asset, all of which also partially offset the decrease in total U.S. GPT described above. Canadian GPT increased on a unit basis in 2014 compared to 2013 in our Horn River Asset primarily due to fixed costs under our firm agreements with third parties being allocated over decreasing volumes. Canadian GPT includes payments for unused firm capacity of $13.9 million, $7.4 million and $6.7 million for 2014, 2013 and 2012, respectively.

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 joint venture partner 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.

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Production and Ad Valorem Taxes

	Years Ended December 31,
	2014				2013					2012
	(in thousands, except per unit amounts)
			Per Mcfe					Per Mcfe				Per Mcfe
Production taxes
Barnett Shale	$	4,347	$	0.07	$	3,620		$	0.05	$	4,982	$	0.05
Other U.S.	324		1.40		655			0.97		857		0.67
Total U.S.	4,671		0.08		4,275			0.06		5,839		0.06
Horseshoe Canyon	150		0.01		(5		)	—		167		0.01
Horn River	—		—		—			—		—		—
Total Canada	150		—		(5		)	—		167		0.01
Total production taxes	4,821		0.05		4,270			0.04		6,006		0.05
Ad valorem taxes
Barnett Shale	$	8,526	$	0.14	$	8,786		$	0.13	$	15,963	$	0.16
Other U.S.	246		1.06		569			0.84		470		0.37
Total U.S.	8,772		0.15		9,355			0.14		16,433		0.16
Horseshoe Canyon	2,994		0.18		2,813			0.15		2,696		0.13
Horn River	757		0.05		628			0.03		260		0.03
Total Canada	3,751		0.12		3,441			0.09		2,956		0.10
Total ad valorem taxes	12,523		0.14		12,796			0.12		19,389		0.15
Total	$	17,344	$	0.19	$	17,066		$	0.16	$	25,395	$	0.19

Production taxes in the U.S. increased in 2014 compared to 2013 primarily due to an increase in our average severance tax rate. Production taxes in 2013 compared to 2012 decreased primarily as a result of decreased volumes year over year.

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.

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Depletion, Depreciation and Accretion

	Years Ended December 31,
	2014				2013				2012
	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe				Per Mcfe
Depletion
U.S.	$	28,567	$	0.48	$	34,995	$	0.51	$	116,005	$	1.14
Canada	11,778		0.38		5,362		0.14		24,897		0.83
Total depletion	40,345		0.45		40,357		0.37		140,902		1.07
Depreciation of other fixed assets
U.S.	$	6,284	$	0.11	$	7,549	$	0.11	$	8,913	$	0.09
Canada	8,879		0.28		9,597		0.25		9,687		0.32
Total depreciation	15,163		0.17		17,146		0.16		18,600		0.14
Accretion	5,618		0.06		5,109		0.05		4,122		0.03
Total	$	61,126	$	0.68	$	62,612	$	0.58	$	163,624	$	1.24

U.S. depletion for 2014, when compared to 2013, reflects a decrease in production. Canadian depletion increased for 2014, when compared to 2013, due to an increase in the depletable asset base partially offset by a reduction in volume. We expect that our U.S. and Canadian depletion rates for 2015 will be approximately $0.43 and $0.87 per Mcfe, respectively. Our Canadian depletion rate in 2015 increased as we impaired our Horn River Asset unevaluated oil and natural gas property costs into the depletable asset base of our Canadian cost center at December 31, 2014.

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 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.

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.

Impairment Expense

As required under GAAP, we perform quarterly ceiling tests to assess impairment of our oil and natural gas properties. We also assess our fixed assets reported outside the country costs centers 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 7 to the consolidated financial statements in Item 8 of this Annual Report.

In Canada during 2014, we impaired the Fortune Creek gathering system as we do not have sufficient liquidity to develop our Horn River Asset. An undiscounted cash flow analysis did not support the recoverability of the carrying value of the gathering system and a discounted cash flow analysis resulted in our recording an impairment of $58.4 million at December 31, 2014. Additionally, we impaired other property and equipment assets in our Horn River Asset at December 31, 2014 by $11.0 million based on our inability to fund the development of our Horn River Asset.

In the U.S. during 2014 and 2013, we recognized other property and equipment impairment charges of $2.6 million and $1.9 million, respectively, for surface land, buildings and pipeline in Texas. During 2012 we impaired pipelines and facilities in Colorado and Texas by $7.3 million due to reduced anticipated utilization and a compressed natural gas facility in Texas by $0.6 million due to reduced use.

In 2012, we recognized non-cash charges of $2.2 billion and $465.9 million for our U.S. and Canadian oil and natural 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

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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.

General and Administrative Expense

	Years Ended December 31,
	2014				2013				2012
	(in thousands, except per unit amounts)
			Per Mcfe				Per Mcfe				Per Mcfe
Expense	$	27,851	$	0.31	$	29,876	$	0.28	$	40,306	$	0.31
Audit and accounting fees	2,357		0.03		2,301		0.02		6,179		0.05
Strategic transactions	7,581		0.08		6,885		0.06		8,503		0.06
Equity compensation	9,505		0.11		16,244		0.15		20,709		0.16
Total	$	47,294	$	0.53	$	55,306	$	0.51	$	75,697	$	0.58

General and administrative equity compensation expense for 2014 decreased compared to 2013 primarily due to the accelerated vestings for retiring executive management and a correction for retirement eligible employees in 2013.

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. 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.

We expect higher expenses in 2015 as a result of our restructuring process partially offset by a reduction in force implemented in February 2015.

Related Party Transactions

We have related party transactions which are outlined in Note 21 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.

Other Income (Expense)

In 2014, the Canadian foreign currency exchange rate resulted in a recognized loss of $3.7 million compared to 2013, which included a recognized loss of $2.4 million. In June 2014, we recognized expense of $3.0 million for an adjustment to the accounting of the Eni Transaction.

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 13 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 by surrendering property.

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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 C$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. The decrease in Fortune Creek accretion from 2013 to 2014 is primarily due to a contribution made to Fortune Creek in 2014, which reduced the partnership liability and related accretion expense.

Interest Expense

	Years Ended December 31,
	2014			2013			2012
				(in thousands)
Interest costs on debt outstanding	$	156,774		$	165,381		$	172,502
Add:
Fees paid on letters of credit outstanding	339			239			118
Cash premium on early debt extinguishment	682			67,010			—
Non-cash interest (1)	11,198			26,920			9,854
Total interest cost incurred	168,993			259,550			182,474
Less:
Interest capitalized	(5,707		)	(7,703		)	(18,423		)
Interest expense	$	163,286		$	251,847		$	164,051

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

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

Capitalized interest has decreased for the three year period as our unevaluated oil and natural gas property balances have decreased due to the movement into the respective country cost center as areas become evaluated and proved reserves established or impairment determined. Our capitalized interest will decrease further in 2015 as we impaired our Horn River Asset unevaluated oil and natural gas property costs into the Canadian cost center at December 31, 2014.

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Income Taxes

The U.S effective tax rates for the three years ended December 31, 2014 are as follows:

	Years Ended December 31,
	2014			2013			2012
				(in thousands)
Income (loss) before income taxes	$	(41,865	)	$	184,034		$	(2,142,730	)
Income tax expense (benefit)	$	2,055		$	12,076		$	(227,934	)
Effective tax rate	(4.91		)%	6.56		%	10.60		%

In 2014, our U.S. income tax expense includes an increase in the valuation allowance of $19.4 million.

The Canadian effective tax rates for the three years ended December 31, 2014 are as follows:

	Years Ended December 31,
	2014			2013			2012
				(in thousands)
Income (loss) before income taxes	$	(57,635	)	$	(7,866	)	$	(505,446	)
Income tax expense (benefit)	$	1,545		$	2,474		$	(67,636	)
Effective tax rate	(2.68		)%	(31.45		)%	13.40		%

In 2014, our Canadian income tax expense includes a decrease in the valuation allowance of $2.6 million.

The consolidated effective tax rates for the three years ended December 31, 2014 are as follows:

	Years Ended December 31,
	2014			2013			2012
				(in thousands)
Income (loss) before income taxes	$	(99,500	)	$	176,168		$	(2,648,176	)
Income tax expense (benefit)	$	3,600		$	14,550		$	(295,570	)
Effective tax rate	(3.62		)%	8.26		%	11.20		%

In 2012, we recognized a full valuation allowance against our net deferred tax assets in the U.S. and Canada. Accordingly, in 2014 and 2013, tax expense has been limited primarily to the tax effects of reclassification adjustments from other comprehensive income and the federal tax refunds received in the U.S. The valuation allowance and the impact of permanent differences are the principle reasons 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 2015 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 2014 and 2013 utilized a combined federal and provincial rate of 25.2% while 2012 utilized 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 was no longer more likely than not that we would realize the deferred tax benefits primarily related to our cumulative net operating losses because we had been in a cumulative three-year loss for both the U.S. and Canada. We continue to believe it is not more likely than not that we will not be able to realize the deferred tax benefits.

As described in Item 5 of this Annual Report, on March 19, 2015, the Bankruptcy Court issued an interim order imposing certain notice procedures and transfer restrictions on the trading of our equity securities in order to avoid limitations on the use of our tax net operating loss carryforwards and certain other tax attributes. The Bankruptcy Court will hold a final hearing on our request on April 15, 2015.

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Quicksilver Resources Inc. and its Restricted Subsidiaries

Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Notes 10 and 17 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. 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.

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

The following summarizes future production hedged with commodity derivatives as of December 31, 2014:

Production Year	Daily Production Volume
	Natural Gas
	MMcfd
2015	150
2016-2021	30

Between January and March 2015, substantially all of our derivatives were restructured or terminated. These restructured and terminated derivatives reduced our daily production volume of natural gas economically hedged to 20 MMcfd in 2015 and we no longer have any derivatives beyond 2015. The cash proceeds of the 2015 terminated derivatives were $135.7 million. We have used or expect to use cash proceeds from these terminated derivatives to pay down amounts outstanding under our Combined Credit Agreements.

Operating Cash Flows

	Years Ended December 31,
	2014			2013			2012
	(in thousands)
Net cash provided by (used in) operating activities	$	(7,629	)	$	(51,700	)	$	227,727

Net cash used in operating activities for 2014 decreased from 2013 due to lower cash interest expense as we refinanced our debt in 2013 and higher cash received from our derivative instruments, partially offset by lower production revenue from our oil and natural gas properties as volumes decreased during the year.

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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.

Investing Cash Flows

	Years Ended December 31,
	2014			2013			2012
	(in thousands)
Capital expenditures	$	(133,481	)	$	(101,288	)	$	(485,479	)
Proceeds from Southwestern Transaction	95,587			—			—
Proceeds from Tokyo Gas Transaction	—			463,999			—
Proceeds from Synergy Transaction	—			42,297			—
Proceeds from Crestwood earn-out	—			—			41,097
Proceeds from sales of properties & equipment	3,222			7,171			72,725
Purchases of marketable securities	(55,890		)	(213,738		)	—
Maturities and sales of marketable securities	222,025			47,603			—
Net cash provided by (used in) investing activities	$	131,463		$	246,044		$	(371,657	)

Costs incurred reflect the activity of the 2014 capital program, while capital expenditures shown in the condensed consolidated statement of cash flows also reflect the related changes in working capital. Our 2014 capital costs incurred have increased for the U.S. and Canada as a result of our overall increase in capital spend in 2014 compared to 2013.

In May 2014, we received a $95.6 million payment from the Southwestern Transaction. In 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 at closing from the Tokyo Gas Transaction was invested in interest bearing time deposits and commercial paper with maturities of less than one year. For 2012, 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 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.

Our 2014 capital costs incurred included 80% associated with direct drilling and completion activities, while 20% was spent for leasehold acquisition. The majority of our drilling and completion expenditures in 2014 were associated with our Barnett Shale and Horseshoe Canyon Assets. Leasehold expenditures reflected extensions in our Barnett Shale, West Texas and Niobrara Assets, with the expenditures made in our Niobrara Asset being included as part of the purchase price in the Southwestern Transaction.

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.

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.

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Financing Cash Flows

	Years Ended December 31,
	2014			2013			2012
	(in thousands)
Net borrowings (payments)	$	49,495		$	(71,030	)	$	157,529
Debt issuance costs	(1,705		)	(26,296		)	(3,022		)
Distribution of Fortune Creek Partnership funds	(39,993		)	(14,965		)	(14,285		)
Proceeds from exercise of stock options	—			—			11
Purchase of treasury stock	(2,388		)	(1,927		)	(3,144		)
Net cash provided by (used in) financing activities	$	5,409		$	(114,218	)	$	137,089

Net financing cash flows in 2014 include net borrowings of $68.0 million under our Combined Credit Agreements. During the quarter ended June 30, 2014, we redeemed all remaining outstanding $10.5 million Senior Notes due 2015 and $8.1 million Senior Notes due 2016. Distributions of Fortune Creek partnership funds of $40.0 million were paid in 2014 to our partner based on our partner's preferential distribution rights.

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 10 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.

Liquidity and Capital Resources

Our sources of liquidity and capital resources historically have been cash flow from operations, proceeds from sales of oil and natural gas properties, borrowings under the Combined Credit Agreements, and issuances of debt securities. Since the Chapter 11 filings, our principal sources of liquidity have been limited to cash flow from operations and cash on hand. In addition to the cash requirements necessary to fund ongoing operations, we have incurred and continue to incur significant professional fees and other costs in connection with the preparation and administration of the Chapter 11 proceedings. We anticipate that we will continue to incur significant professional fees and costs for the pendency of the Chapter 11 proceedings.

Between January and March 2015, substantially all of our derivatives were restructured or terminated. These restructured and terminated derivatives reduced our daily production volume of natural gas economically hedged to 20 MMcfd in 2015 and we no longer have any derivatives beyond 2015. The cash proceeds of the 2015 terminated derivatives were $135.7 million. We have used or expect to use cash proceeds from these terminated derivatives to pay down amounts outstanding under our Combined Credit Agreements.

Although we believe our cash flow from operations and cash on hand will be adequate to meet the operating costs of our existing business, there are no assurances that our cash flow from operations and cash on hand will be sufficient to continue to fund our operations or to allow us to continue as a going concern until a Chapter 11 plan is confirmed by the Bankruptcy Court or other alternative restructuring transaction is approved by the Bankruptcy Court and consummated. Our long-term liquidity requirements, the adequacy of our capital resources and our ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until a Chapter 11 plan has been confirmed, if at all, by the Bankruptcy Court. If our future sources of liquidity are insufficient, we could face substantial liquidity constraints and be unable to continue as a going concern and will likely be required to significantly reduce, delay or eliminate capital expenditures, implement further cost reductions, seek other financing alternatives or seek the sale of some or all of our assets. If we limit, defer or eliminate our 2015 capital expenditure plan or are unsuccessful in developing reserves and adding production

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through our capital program or our cost-cutting efforts are too overreaching, the value of our oil and natural gas properties and our financial condition and results of operations could be adversely affected.

Prior to our Chapter 11 filings, we maintained the Combined Credit Agreements. At December 31, 2014, the Combined Credit Agreements’ global borrowing base was $325 million and the global letter of credit capacity was $280 million. At December 31, 2014, there was $9.2 million available under the Combined Credit Agreements and we held cash or cash equivalents of $223.5 million. On March 17, 2015, we repaid $36.7 million of amounts outstanding under our Combined Credit Agreements from proceeds of derivative terminations. We expect to use the remaining cash proceeds from recently terminated derivatives to pay down our Combined Credit Agreements. Our Chapter 11 filings constituted an event of default under the Combined Credit Agreements and all borrowings and other fees under the Combined Credit Agreements became immediately due and payable. The ability of the lenders under the Combined Credit Agreements to seek remedies to enforce their rights under the agreements was automatically stayed as a result of the Chapter 11 filings, and the lenders’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

On March 16, 2015, we, along with QRCI, entered into the Forbearance Agreement with the administrative agents and certain of the lenders under the Combined Credit Agreements. As a result of the Chapter 11 filing, the obligations under the Combined Credit Agreements were automatically accelerated. However, pursuant to the Forbearance Agreement, the administrative agents and the lenders agreed to, among other things, (i) forbear from exercising their rights and remedies in connection with specified defaults under the Amended and Restated Canadian Credit Facility related to our Chapter 11 filing until the earlier of June 16, 2015 or certain other events specified in the Forbearance Agreement, including, among other things, the commencement by QRCI or certain specified Canadian subsidiary guarantors of insolvency proceedings and (ii) waive compliance with certain specified terms and conditions relating to the renewal of outstanding evergreen letters of credit under the Combined Credit Agreements.

Beginning on March 17, 2015, as part of the Forbearance Agreement, we agreed to pay interest monthly in the U.S. at a specified rate of ABR plus the applicable margin; and in Canada we agreed to pay interest monthly at a specified rate for Canadian dollar denominated borrowings of Canadian prime plus the default rate plus the applicable margin and for U.S. dollar denominated borrowings, U.S. prime plus the default rate plus the applicable margin.

Our Chapter 11 filings also constituted an event of default under the Second Lien Term Loan, the Second Lien Notes, the Senior Notes due 2019, the Senior Notes due 2021, and the Senior Subordinated Notes. All principal, interest and other amounts under each of these debt instruments became immediately due and payable. The ability of the lenders and noteholders to seek remedies to enforce their rights under the applicable debt instruments was automatically stayed as a result of the Chapter 11 filings, and the lenders’ and noteholders’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

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Financial Position

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

• Cash, cash equivalents and marketable securities decreased $31.9 million as we used cash on hand to fund operations and capital expenditures and make a contribution to Fortune Creek, which was distributed to KKR based on their preferential rights, partially offset by net borrowings under the Combined Credit Agreements.

• Our net property, plant and equipment balance decreased $132.0 million from December 31, 2013 to December 31, 2014. The Southwestern Transaction resulted in a decrease of $97.1 million. Additional decreases were due to DD&A incurred of $55.5 million, impairment charges recognized of $72.0 million and $32.6 million related to U.S.-Canadian exchange rate changes. Offsetting these decreases, we incurred capital costs of $129.4 million during 2014.

• The valuation of our current and non-current derivative assets and liabilities was $22.1 million higher on a net basis, which was primarily due to a decrease in the natural gas forward curve, partially offset by settlements during the year without additional derivatives being added to our portfolio.

• The $6.2 million decrease in accounts payable was due primarily to a reduction in accrued capital expenditures of $4.3 million and a decrease in trade payables of $1.8 million from December 31, 2013 as activity has decreased from year-end 2013.

• Our accrued liabilities decreased $21.7 million, primarily due to acceleration of accrued gathering payments of $9.1 million, a reduction in net revenue payable to third parties of $3.5 million and various other reductions less than $2.0 million each.

• Debt increased $48.4 million primarily from net borrowings under the Combined Credit Agreements of $68.0 million and $5.7 million of amortized discounts, partially offset by early retirement of $18.7 million of our 2015 Senior Notes and 2016 Senior Notes, recognition of $2.0 million of interest rate swaps and changes to the U.S.-Canadian exchange rate resulting in a decrease of $4.7 million. Additionally, all debt was reclassified from long-term to current at December 31, 2014.

• Partnership liability decreased $34.2 million primarily due to a $25.4 million contribution to Fortune Creek and periodic distribution of $14.6 million, both of which were distributed to KKR based on their preferential rights, and foreign exchange rate changes of $9.3 million, partially offset by accretion of $15.1 million.

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Contractual Obligations and Commercial Commitments

Contractual Obligations

Our contractual and scheduled interest obligations will likely be significantly different following the outcome of the Chapter 11 proceedings. Information regarding our contractual and scheduled interest obligations, at December 31, 2014, 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	$	2,072,514	$	—	$	624,514	$	1,123,000	$	325,000
Scheduled interest obligations	701,439		159,483		379,922		126,284		35,750
GPT contracts	408,997		72,995		196,511		80,595		58,896
Drilling rig contracts	6,577		6,577		—		—		—
Purchase obligations	220		220		—		—		—
Asset retirement obligations	105,016		967		9,357		4,724		89,968
Operating lease obligations	29,365		4,181		12,334		7,848		5,002
Total obligations	$	3,324,128	$	244,423	$	1,222,638	$	1,342,451	$	514,616

• Long-Term Debt.  As of December 31, 2014, our outstanding indebtedness included $625 million of Senior Secured Second Lien Term Loan, $200 million of Senior Secured Second Lien Notes due 2019, $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, their stated maturity dates, and interest rates as of December 31, 2014, we anticipate interest payments, including our scheduled interest obligations, would be $159.5 million in 2015. Maturities are shown at original maturity dates assuming no acceleration or springing maturity, however, we have classified all debt as current at December 31, 2014. Further information can be found in Note 10 to our consolidated financial statements found in Item 8 of this Annual Report.

• Scheduled Interest Obligations.  As of December 31, 2014, 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 Loan Note due 2019 based on current rates, $27.2 million annually on our Senior Notes due 2019, $35.8 million annually on our Senior Notes due 2021, $24.9 million annually on our $350 million of Senior Subordinated Notes, and $13.1 million annually on our Combined Credit Agreements based on the amount outstanding at year end 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. As described below, this amount includes an amount we expect the service provider will claim to be entitled to with respect to QRCI's gathering and processing contract as of December 31, 2014. As further described below, the contract was terminated in March 2015 and we expect that we and the third party will disagree regarding the remaining amounts payable under the contract.

• Drilling Rig Contracts.  We utilize drilling rigs from third parties in our development and exploration programs. The outstanding drilling rig contracts requires payment of a specified day rate ranging from $23,000 to $24,300 for the entire lease term regardless of our utilization of the drilling rig.

• Purchase Obligations.  At December 31, 2014, we were under contract to purchase goods and services.

• 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 and equipment purchases within our Horn River Asset related to the Fortune Creek gathering system. Further information can be found in Note 14 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, 2014:

	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	$	6,398	$	6,398	$	—	$	—	$	—
Standby letters of credit	41,250		41,250		—		—		—
Total	$	47,648	$	47,648	$	—	$	—	$	—

• 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.

QRCI did not pay an uneconomic Canadian gathering and processing commitment, which included significant unused firm capacity, due in late February 2015. In early March 2015, the third party service provider issued a demand letter regarding the missed payment and suspended service resulting in our production in our Horn River Asset being shut-in. Further, a termination notice was issued effective March 19, 2015. We are exploring alternatives to gather and process our Horn River Asset production; however, we may not be able to find economic alternatives in the near-term, or at all.

In connection with this Canadian gathering and processing contract, we had previously issued a letter of credit in the amount of C$33 million. Upon termination, the third party drew down the full face amount of the letter of credit. We do not believe the third party was legally entitled to draw down the entire amount of the letter of credit and we have reserved all of our rights, entitlements and remedies in that regard.

We expect that we and the third party will disagree as to what are the remaining obligations under the relevant agreement and the length of the remaining term of the agreement and as to the remedies and defenses available to the parties. While we expect to vigorously dispute the amount, we expect that the third party will claim to be entitled to up to approximately C$126 million (including the proceeds of the letter of credit) as the aggregate of the monthly tolls for firm capacity for the alleged remainder of the term of the relevant agreement.

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.

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Oil and Natural Gas Reserves

Policy Description

Proved oil and natural 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, we had four proved undeveloped well locations at December 31, 2014, none of which are more than one offset. Additional information regarding our proved oil and natural 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 9% 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 natural gas properties. Under the full cost method, all costs associated with the acquisition, exploration, and development of oil and natural 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 natural gas reserves. Excluded from amounts subject to depletion are costs associated with unevaluated properties.

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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 natural 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 natural 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.

While the estimated quantities of proved reserves requires 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, 2014, 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 natural 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 natural 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.

To the extent we enter into derivatives, these positions are 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

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under the credit facility. 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 natural 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.

Asset Retirement Obligations

Policy Description

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.

Judgments and Assumptions

The estimates of our future asset retirement obligations require substantial judgment. We estimate the future costs associated with our retirement obligations, the life of the related asset and our credit-adjusted-risk-free interest rate. As revisions to these estimates occur, we may have significant changes to the related asset and its asset retirement obligation.

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.

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 and 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

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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.

OFF-BALANCE SHEET ARRANGEMENTS

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.

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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, 2014.

Production Year	Daily Production Volume
	Natural Gas
	MMcfd
2015	150
2016-2021	30

Between January and March 2015, substantially all of our derivatives were restructured or terminated. These restructured and terminated derivatives reduced our daily production volume of natural gas economically hedged to 20 MMcfd in 2015 and we no longer have any derivatives beyond 2015. The cash proceeds of the 2015 terminated derivatives were $135.7 million. We have used or expect to use cash proceeds from these terminated derivatives to pay down amounts outstanding under our Combined Credit Agreements.

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 $37.1 million, $68.2 million and $194.6 million for 2014, 2013 and 2012, respectively, and a loss of $2.8 million and gain of $21.2 million was recognized in net derivative gains for 2014 and 2013, respectively. Unrealized gains of $68.5 million and $8.7 million and a loss of $17.9 million were recognized for 2014, 2013 and 2012, 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.

69

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

				Remaining Contract Period	Volume	Weighted Average Price Per Mcf	Fair Value
Segment	Product	Type					Total		2015		2016		2017		2018		2019		Thereafter
							(in thousands)
Canada	Gas	Swap	(1)	Jan 2015 - Dec 2015	10 MMcfd	6.42	12,327		12,327		—		—		—		—		—
Canada	Gas	Swap	(2)	Jan 2015 - Dec 2015	10 MMcfd	6.45	12,441		12,441		—		—		—		—		—
Canada	Gas	Swap	(3)	Jan 2015 - Dec 2015	10 MMcfd	4.04	3,674		3,674		—		—		—		—		—
Canada	Gas	Swap	(4)	Jan 2015 - Dec 2021	10 MMcfd	4.625	19,122		5,815		4,226		3,073		2,326		1,720		1,962
U.S.	Gas	Swap	(5)	Jan 2015 - Dec 2015	5 MMcfd	6.23	5,820		5,820		—		—		—		—		—
U.S.	Gas	Swap	(6)	Jan 2015 - Dec 2015	5 MMcfd	6.20	5,766		5,766		—		—		—		—		—
U.S.	Gas	Swap	(7)	Jan 2015 - Dec 2015	20 MMcfd	6.00	21,589		21,589		—		—		—		—		—
U.S.	Gas	Swap	(8)	Jan 2015 - Dec 2015	10 MMcfd	6.00	10,803		10,803		—		—		—		—		—
U.S.	Gas	Swap	(9)	Jan 2015 - Dec 2015	5 MMcfd	5.68	4,820		4,820		—		—		—		—		—
U.S.	Gas	Swap	(10)	Jan 2015 - Dec 2015	7.5 MMcfd	5.475	6,730		6,730		—		—		—		—		—
U.S.	Gas	Swap	(11)	Jan 2015 - Dec 2015	7.5 MMcfd	5.50	6,661		6,661		—		—		—		—		—
U.S.	Gas	Swap	(12)	Jan 2015 - Dec 2015	5 MMcfd	4.15	2,038		2,038		—		—		—		—		—
U.S.	Gas	Swap	(13)	Jan 2015 - Dec 2015	5 MMcfd	4.13	2,000		2,000		—		—		—		—		—
U.S.	Gas	Swap		Jan 2015 - Dec 2015	5 MMcfd	4.255	2,228		2,228		—		—		—		—		—
U.S.	Gas	Swap		Jan 2015 - Dec 2015	5 MMcfd	4.25	2,219		2,219		—		—		—		—		—
U.S.	Gas	Swap	(14)	Jan 2015 - Dec 2015	10 MMcfd	4.54	5,492		5,492		—		—		—		—		—
U.S.	Gas	Swap	(15)	Jan 2015 - Dec 2021	5 MMcfd	4.38	6,614		2,461		1,668		1,099		735		443		208
U.S.	Gas	Swap	(16)	Jan 2015 - Dec 2021	10 MMcfd	4.37	12,975		4,886		3,300		2,163		1,436		852		338
U.S.	Gas	Swap	(17)	Jan 2015 - Dec 2021	5 MMcfd	4.35	6,248		2,406		1,614		1,046		683		392		107
				Grand Total			$	149,567	$	120,176	$	10,808	$	7,381	$	5,180	$	3,407	$	2,615

70

⁽¹⁾  In March 2015, this gas swap was terminated by the counterparty. We received funds of $9.7 million which will be recognized as realized derivative gain in 2015.

⁽²⁾  In March 2015, we terminated this gas swap and received funds of $9.3 million and will be recognized as realized derivative gain in 2015.

⁽³⁾  This derivative was allocated to Canada upon inception; however, the legal counterparty is Quicksilver Resources Inc.

⁽⁴⁾  In January 2015, we restructured this gas swap by increasing our February 2015 through December 2015 fixed price to $10.365 and terminating the 2016 through 2021 portion of this gas swap. In March 2015, this gas swap was terminated by the counterparty. We received funds of $20.5 million which will be recognized as realized derivative gain in 2015.

⁽⁵⁾  In March 2015, we terminated this gas swap and received funds of $4.3 million and will be recognized as realized derivative gain in 2015.

⁽⁶⁾  In March 2015, we terminated this gas swap and received funds of $4.3 million and will be recognized as realized derivative gain in 2015.

⁽⁷⁾  In March 2015, we terminated this gas swap and received funds of $17.0 million and will be recognized as realized derivative gain in 2015.

⁽⁸⁾  In March 2015, we terminated this gas swap and received funds of $8.0 million and will be recognized as realized derivative gain in 2015.

⁽⁹⁾  In March 2015, we terminated this gas swap and received funds of $3.6 million and will be recognized as realized derivative gain in 2015.

⁽¹⁰⁾  In March 2015, this gas swap was terminated by the counterparty. We received funds of $5.1 million which will be recognized as realized derivative gain in 2015.

⁽¹¹⁾  In March 2015, this gas swap was terminated by the counterparty. We received funds of $5.1 million which will be recognized as realized derivative gain in 2015.

⁽¹²⁾  In March 2015, this gas swap was terminated by the counterparty. We received funds of $1.8 million which will be recognized as realized derivative gain in 2015.

⁽¹³⁾  In March 2015, this gas swap was terminated by the counterparty. We received funds of $1.7 million which will be recognized as realized derivative gain in 2015.

⁽¹⁴⁾  In March 2015, this gas swap was terminated by the counterparty. We received funds of $4.5 million which will be recognized as realized derivative gain in 2015.

⁽¹⁵⁾  In March 2015, this gas swap was terminated by the counterparty. We expect to receive funds of $10.9 million which will be recognized as realized derivative gain in 2015.

⁽¹⁶⁾  In March 2015, we terminated this gas swap and received funds of $19.8 million and will be recognized as realized derivative gain in 2015.

⁽¹⁷⁾  In March 2015, this gas swap was terminated by the counterparty. We received funds of $10.1 million which will be recognized as realized derivative gain in 2015.

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.

71

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 2014, 2013 and 2012, we recognized $2.0 million, $12.0 million and $5.1 million, respectively, of those deferred gains as a reduction of interest expense.

At December 31, 2014, we had availability under our Combined Credit Agreements of $9.2 million, if we utilized this balance by year-end 2015 at interest rates as of December 31, 2014, we estimate that annual interest payments would increase by $0.4 million. If interest rates change by 1% on our December 31, 2014 variable debt balances of $274.5 million, our annual pre-tax income would decrease or increase by $2.7 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, 2014, would have an impact of increasing our applicable interest rate on this debt by only 0.01% or an estimated annual interest payment increase of $0.1 million.

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

Foreign Currency Risk

Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. Non-functional currency transactions resulted in a $3.7 million loss, $2.4 million loss and $0.1 million gain for 2014, 2013 and 2012, 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.

72

ITEM 8. Financial Statements and Supplementary Data

QUICKSILVER RESOURCES INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	74
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) for the Years Ended December 31, 2014, 2013 and 2012	75
Consolidated Balance Sheets as of December 31, 2014 and 2013	76
Consolidated Statements of Equity for the Years ended December 31, 2014, 2013 and 2012	77
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012	78
Notes to Consolidated Financial Statements for the Years Ended December 31, 2014, 2013 and 2012	79
Supplemental Selected Quarterly Financial Data (Unaudited)	121
Supplemental Oil and Gas Information (Unaudited)	124
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	130

73

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Quicksilver Resources Inc.

We have audited the accompanying consolidated balance sheets of Quicksilver Resources Inc. as of December 31, 2014 and 2013, and the related consolidated statements of income (loss) and comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2014. 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 audits 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, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code on March 17, 2015, which raises substantial doubt about the Company’s ability to continue as a going concern. Management's plans in regard to this matter are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 31, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Fort Worth, Texas

March 31, 2015

74

QUICKSILVER RESOURCES INC.

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

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

In thousands, except for per share data

	2014			2013			2012
Revenue
Production	$	425,154		$	463,491		$	630,947
Sales of purchased natural gas	70,468			64,913			62,405
Net derivative gains	65,698			29,928			11,444
Other	8,108			3,230			4,242
Total revenue	569,428			561,562			709,038
Operating expense
Lease operating	76,975			82,265			95,333
Gathering, processing and transportation	136,283			148,569			166,316
Production and ad valorem taxes	17,344			17,066			25,395
Cost of purchased natural gas	70,376			64,840			62,041
Depletion, depreciation and accretion	61,126			62,612			163,624
Impairment	71,988			1,863			2,625,928
General and administrative	47,294			55,306			75,697
Other operating	2,608			3,725			1,562
Total expense	483,994			436,246			3,215,896
Gain on Tokyo Gas Transaction	—			339,328			—
Crestwood earn-out	—			—			41,097
Operating income (loss)	85,434			464,644			(2,465,761		)
Other income (expense) - net	(6,581		)	(17,384		)	1,108
Fortune Creek accretion	(15,067		)	(19,245		)	(19,472		)
Interest expense	(163,286		)	(251,847		)	(164,051		)
Income (loss) before income taxes	(99,500		)	176,168			(2,648,176		)
Income tax (expense) benefit	(3,600		)	(14,550		)	295,570
Net income (loss)	(103,100		)	161,618			(2,352,606		)
Reclassification adjustments related to settlements of derivative contracts into production revenue- net of income tax	(24,702		)	(46,931		)	(128,161		)
Net change in derivative fair value - net of income tax	—			—			74,384
Foreign currency translation adjustment	(13,326		)	(4,681		)	412
Other comprehensive income (loss)	$	(38,028	)	$	(51,612	)	$	(53,365	)
Comprehensive income (loss)	$	(141,128	)	$	110,006		$	(2,405,971	)
Earnings (loss) per common share - basic	$	(0.59	)	$	0.92		$	(13.83	)
Earnings (loss) per common share - diluted	$	(0.59	)	$	0.92		$	(13.83	)

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

75

QUICKSILVER RESOURCES INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2014 AND 2013

In thousands, except for share data

	2014			2013
ASSETS
Current assets
Cash and cash equivalents	$	223,529		$	89,103
Marketable securities	—			166,343
Total cash, cash equivalents and marketable securities	223,529			255,446
Accounts receivable - net of allowance for doubtful accounts	65,158			58,645
Derivative assets at fair value	120,176			57,523
Other current assets	14,414			22,346
Total current assets	423,277			393,960
Property, plant and equipment - net
Oil and natural gas properties, full cost method (including unevaluated costs of $18,803 and $221,605, respectively)	614,668			640,443
Other property and equipment	114,112			220,362
Property, plant and equipment - net	728,780			860,805
Derivative assets at fair value	29,391			73,357
Other assets	32,854			41,604
	$	1,214,302		$	1,369,726
LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt	$	2,037,305		$	—
Accounts payable	22,586			28,822
Accrued liabilities	81,146			102,850
Derivative liabilities at fair value	—			3,125
Total current liabilities	2,141,037			134,797
Long-term debt	—			1,988,946
Partnership liability	91,956			126,132
Asset retirement obligations	104,049			106,256
Derivative liabilities at fair value	—			323
Other liabilities	15,131			19,242
Commitments and contingencies (Note 13)
Stockholders' equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding	—			—
Common stock, $0.01 par value, 400,000,000 shares authorized, and 187,802,994 and 183,994,879 shares issued, respectively	1,878			1,840
Additional paid in capital	781,669			770,092
Treasury stock of 7,444,372 and 6,698,640 shares, respectively	(53,810		)	(51,422		)
Accumulated other comprehensive income	71,853			109,881
Retained deficit	(1,939,461		)	(1,836,361		)
Total stockholders' equity	(1,137,871		)	(1,005,970		)
	$	1,214,302		$	1,369,726

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

76

QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

In thousands

	Common Stock		Additional Paid-in Capital		Treasury Stock			Accumulated Other Comprehensive Income			Retained Earnings (Deficit)			Total
Balances at December 31, 2011	$	1,770	$	737,015	$	(46,351	)	$	214,858		$	354,627		$	1,261,919
Net loss	—		—		—			—			(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	)
Net loss	—		—		—			—			(103,100		)	(103,100		)
Hedge derivative contract settlements reclassified into production revenue from AOCI, net of income tax of $11,318	—		—		—			(24,702		)	—			(24,702		)
Foreign currency translation adjustment	—		—		—			(13,326		)	—			(13,326		)
Issuance & vesting of stock compensation	38		11,577		(2,388		)	—			—			9,227
Balances at December 31, 2014	$	1,878	$	781,669	$	(53,810	)	$	71,853		$	(1,939,461	)	$	(1,137,871	)

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

77

QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS END DECEMBER 31, 2014, 2013 AND 2012

In thousands

	2014			2013			2012
Operating activities:
Net income (loss)	$	(103,100	)	$	161,618		$	(2,352,606	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion	61,126			62,612			163,624
Impairment expense	71,988			1,863			2,625,928
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)	11,318			21,581			(289,981		)
Non-cash (gain) loss from hedging and derivative activities	(61,654		)	3,904			57,826
Stock-based compensation	11,616			17,979			22,246
Non-cash interest expense	11,198			26,920			9,854
Fortune Creek accretion	15,067			19,245			19,472
Other	7,533			6,783			1,037
Changes in assets and liabilities
Accounts receivable	(7,141		)	(3,994		)	30,950
Other assets	43			322			(4,435		)
Accounts payable	(358		)	(7,133		)	(8,895		)
Income taxes	(668		)	7,828			1,183
Accrued and other liabilities	(24,597		)	(31,900		)	(14,884		)
Net cash provided by (used in) operating activities	(7,629		)	(51,700		)	227,727
Investing activities:
Capital expenditures	(133,481		)	(101,288		)	(485,479		)
Proceeds from Southwestern Transaction	95,587			—			—
Proceeds from Tokyo Gas Transaction	—			463,999			—
Proceeds from Synergy Transaction	—			42,297			—
Proceeds from Crestwood earn-out	—			—			41,097
Proceeds from sale of properties and equipment	3,222			7,171			72,725
Purchases of marketable securities	(55,890		)	(213,738		)	—
Maturities and sales of marketable securities	222,025			47,603			—
Net cash provided by (used in) investing activities	131,463			246,044			(371,657		)
Financing activities:
Issuance of debt	243,184			1,237,352			467,959
Repayments of debt	(193,689		)	(1,308,382		)	(310,430		)
Debt issuance costs paid	(1,705		)	(26,296		)	(3,022		)
Distribution of Fortune Creek Partnership funds	(39,993		)	(14,965		)	(14,285		)
Proceeds from exercise of stock options	—			—			11
Purchase of treasury stock	(2,388		)	(1,927		)	(3,144		)
Net cash provided by (used in) financing activities	5,409			(114,218		)	137,089
Effect of exchange rate changes in cash	5,183			4,026			(1,354		)
Net change in cash and cash equivalents	134,426			84,152			(8,195		)
Cash and cash equivalents at beginning of period	89,103			4,951			13,146
Cash and cash equivalents at end of period	$	223,529		$	89,103		$	4,951

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

78

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012

1. NATURE OF OPERATIONS

We are an independent oil and natural 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, 2014, our significant oil and natural 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 oil and natural gas, the price of foreign imports, the level of consumer demand and the price of available alternative fuels.

During the third quarter of 2014, we launched a formal marketing process, led by Houlihan Lokey, covering any and all of our operating assets. During the formal marketing process, we also received additional amendments to the financial covenants to our Combined Credit Agreements. These amendments, which included the replacement of the minimum interest coverage ratio with a minimum EBITDAX requirement, provided relief from the continued pressure on our cash flows relative to our obligations, which in turn allowed time for the formal marketing process. Bids were initially due in December 2014, but the bid deadline was subsequently extended to late January 2015. After the bid deadline passed, we evaluated the bids that were received with our advisors. Following discussions with various bidders, we concluded that the marketing process had not yet produced any viable options for asset sales or other strategic alternatives that would likely have a material impact on our capital structure or liquidity.

In February 2015, in light of (a) not yet having identified a transaction that would have a material impact on our capital structure or liquidity, (b) the potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, and (c) other potential defaults, we elected not to make the approximately $13.6 million interest payment on our Senior Notes due 2019, which was due on February 17, 2015. During the 30-day grace period provided for in the Senior Notes due 2019 Indenture, we continued discussions with our creditors. The discussions with our creditors did not produce an agreement that would enable us to effectively address, in a holistic manner, the impending issues adversely impacting our business, including (i) potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, (ii) potential near-term liquidity shortfalls due to the springing maturities, (iii) potential near-term breaches of certain financial covenants resulting from sharp declines in natural gas and NGL prices, and (iv) certain other potential defaults under our Combined Credit Agreements and the Second Lien Term Loan.

Accordingly, on March 17, 2015, the Company and our subsidiaries Barnett Shale Operating LLC, Cowtown Drilling, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline Funding, Inc., Cowtown Pipeline L.P., Cowtown Pipeline Management, Inc., Makarios Resources International Holdings LLC, Makarios Resources International Inc., QPP Holdings LLC, QPP Parent LLC, Quicksilver Production Partners GP LLC, Quicksilver Production Partners LP, and Silver Stream Pipeline Company LLC each filed a voluntary petition under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court to restructure our obligations and capital structure. The Chapter 11 cases are being jointly administered for procedural purposes only by the Bankruptcy Court under the caption In re Quicksilver Resources Inc., et. al., Case No. 15-10585 (Jointly Administered).

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We are currently operating our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As part of our “first day” motions in the Chapter 11 proceedings, we obtained Bankruptcy Court approval to, among other things and subject to the applicable caps contained in the orders of the Bankruptcy Court, on an interim basis, pay employee wages, health benefits and certain other employee obligations, to pay certain lienholders and critical vendors and forward funds belonging to third parties, including royalty holders and other partners. A final hearing on the motions to satisfy our obligations to certain third parties and to forward funds held by us that belong to third parties will be held on April 15, 2015.

On March 16, 2015, we, along with QRCI, entered into the Forbearance Agreement with the administrative agents and certain of the lenders under the Combined Credit Agreements. As a result of the Chapter 11 filing, the obligations under the Combined Credit Agreements were automatically accelerated. However, pursuant to the Forbearance Agreement, the administrative agents and the lenders agreed to, among other things, (i) forbear from exercising their rights and remedies in connection with specified defaults under the Amended and Restated Canadian Credit Facility related to our Chapter 11 filing until the earlier of June 16, 2015 or certain other events specified in the Forbearance Agreement, including, among other things, the commencement by QRCI or certain specified Canadian subsidiary guarantors of insolvency proceedings and (ii) waive compliance with certain specified terms and conditions relating to the renewal of outstanding evergreen letters of credit under the Combined Credit Agreements.

For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A, “Risk Factors.” As a result of these risks and uncertainties, the number of our outstanding shares and our shareholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Annual Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

In particular, subject to certain exceptions, under the Bankruptcy Code, the U.S. Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the U.S. Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert claims against the applicable U.S. Debtor's estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the U.S. Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the U.S. Debtor in this Annual Report, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the U.S. Debtor is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the U.S. Debtors expressly preserve all of their rights with respect thereto.

There can be no assurances regarding our ability to successfully develop, confirm and consummate one or more plans of reorganization or other alternative restructuring transactions, including a sale of all or substantially all of our assets, that satisfies the conditions of the Bankruptcy Code and, is authorized by the Bankruptcy Court.

The above conditions represent an event of default under our long-term debt and give rise to substantial doubt as to our ability to continue as a going concern. We have classified all debt as current at December 31, 2014. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported income and expenses could be required and could be material.

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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. Our Chapter 11 filing in 2015 will require us to evaluate whether we continue to control our subsidiaries and VIEs through our equity ownership. If we determine that we do not control any or all of these subsidiaries or VIEs, we will no longer consolidate those subsidiaries.

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 2014, two purchasers individually accounted for 17% and 13% of cash collected for our production revenue. During 2013, one purchaser individually accounted for 18% of cash collected for our production revenue. During 2012, two purchasers accounted for 21% and 15% 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.

To the extent we enter into derivatives, these positions are 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 internal credit policies require that any counterparties, including facility lenders, with whom

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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.

Property, Plant, and Equipment

We follow the full cost method in accounting for our oil and natural gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and natural 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, which costs are assessed annually for impairment and inclusion as depletable costs in the respective cost center.

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 natural 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 oil and natural gas 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 7 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, included in Other Current Assets, were comprised of $7.6 million and $15.8 million of materials and parts and $0.7 million and $2.5 million of NGLs as of December 31, 2014 and 2013, respectively. Inventories are primarily comprised of materials and parts including oil and natural 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 of $7.0 million and $3.0 million for 2014 and 2013, respectively, are recorded as lease operating expense in the accompanying consolidated statements of operations.

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.

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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, 2014 and 2013, 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 within debt. 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 12 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.

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. Losses from foreign currency transactions of $3.7 million and $2.4 million in 2014 and 2013, respectively, are included in the consolidated results of operations.

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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.

We consolidate the financial position of Fortune Creek and the results of operations in our consolidated financial statements. Note 14 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 16 includes the calculation of earnings per share.

Recently Issued Accounting Standards

In February 2015, the FASB issued accounting guidance, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” requiring reporting entities to evaluate whether they should consolidate certain legal entities. The standard is effective for periods beginning after December 15, 2015 with early adoption permitted. We are currently evaluating the new guidance and have not determined the impact this standard may have on our financial statements.

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

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

3. DIVESTITURES

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

In October 2013, we executed an agreement with Eni involving our West Texas Asset 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 is responsible for 100% of the cost for drilling, completion and production facilities up to a total of $52.0 million, thereby earning a 50% interest in our acreage. Upon Eni’s fulfillment of the $52.0 million carry, which was substantially met as of the first quarter of 2015, we participate equally in the future revenue, operating costs and capital expenditures on the wells drilled and completed pursuant to the joint exploration agreement. Per the joint exploration agreement with Eni, we have the ability to decline participation in any well after the Eni carry is fulfilled, subject to non-consent payout penalties.

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

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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 under GAAP, therefore our U.S. oil and natural gas properties were reduced by these proceeds and we did not recognize a gain or loss.

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 the Tokyo Gas Transaction represented a significant disposal of reserves under GAAP. Our U.S. oil and natural 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 natural 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 was the operator of the majority of the jointly owned lands. Subsequently, these assets were 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,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
Level 2 inputs	$	104,608	$	107,395	$	—	$	3,448
Level 3 inputs	44,959		23,485		—		—
Total	$	149,567	$	130,880	$	—	$	3,448

The fair value of “Level 2” derivative instruments included in these disclosures was estimated using inputs quoted in active markets for the periods covered by the derivatives. The fair value of derivative instruments designated as “Level 3” was estimated using prices quoted in markets where there is insufficient market activity for consideration as “Level 2” instruments. Currently, only our natural gas derivatives with an original tenure of 10 years utilize “Level 3” inputs, primarily due to comparatively less market data available for the later portion of their term compared with our other shorter term derivatives. The fair value of both the “Level 2” and the “Level 3” assets and liabilities are determined using a discounted cash flow model using the terms of the derivative instrument, market prices for the periods covered by the derivatives, and the credit adjusted risk-free interest rates. The “Level 3” unobservable input is the market prices for natural gas for the period from 2019 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 $2.88 to $4.60 and are based upon prices quoted in active markets for the period of time available. A decrease of these unobservable inputs would increase the fair value, while an increase would decrease the fair value.

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

	As of December 31,
	2014			2013
	(in thousands)
Balance at beginning of period	$	23,485		$	(4,931	)
Total gains (losses) for the period:
Unrealized gain on derivatives	31,824			40,398
Transfers out of Level 3	(3,559		)	—
Settlements in net derivative losses	(6,791		)	(11,982		)
Balance at end of period	$	44,959		$	23,485
Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date	$	32,074		$	41,909

In 2014, transfers from Level 3 to Level 2 represent our ten-year derivative instruments that were exchanged in December 2014 for derivative instruments with shorter durations and which were valued on the date of the transfer.

Commodity Price Derivatives

As of December 31, 2014, we had natural gas swaps as follows:

Production Year	Daily Production Volume
	Natural Gas
	MMcfd
2015	150
2016-2021	30

Between January and March 2015, substantially all of our derivatives were restructured or terminated. These restructured and terminated derivatives reduced our daily production volume of natural gas economically hedged to 20 MMcfd in 2015 and we no longer have any derivatives beyond 2015. The cash proceeds of the 2015 terminated derivatives were $135.7 million.

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)
2015	$	33,191
2016	13,476
2017	12,531
2018	11,664
2019 and thereafter	29,779
	$	100,641

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 $22.4 million net of income taxes.

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Interest Rate Derivatives

In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges 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 2014 and 2013, we recognized $2.0 million and $12.0 million, respectively, of those deferred gains as a reduction of interest expense. The remaining $2.8 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)
2015	$	2,194
2016	569
	$	2,763

Fair Value Disclosures

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

	Asset Derivatives				Liability Derivatives
	As of December 31,				As of December 31,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
Derivatives not designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	120,176	$	60,063	$	—	$	2,540
Noncurrent derivative assets	81,187		105,315		51,796		31,958
Current derivative liabilities	—		—		—		3,125
Noncurrent derivative liabilities	—		—		—		323
Total derivatives not designated as hedges	$	201,363	$	165,378	$	51,796	$	37,946

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

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Investments

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

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

Nonrecurring Fair Value Measurements

At December 31, 2014, we impaired inventory in Canada, specifically in our Horn River Asset, to the fair value of current market prices in areas where the inventory could be used less shipping costs (“Level 3” input). As drilling activity has declined in the general area where this inventory is located, shipping costs were included in the net realizable value adjustment. For our Fortune Creek gathering system impairment, a discounted cash flow analysis considering the contractual rate under the gathering agreement and QRCI’s proved reserves (“Level 3” input) was performed to determine the net realizable value. Additionally, impairments were incurred in 2014 on buildings and surface land in the U.S. as current market prices, as indicated by broker quotes and recent sales activity (“Level 3” input), did not support our historical book value on these assets.

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, 2014 and December 31, 2013 are included in Note 10.

5. ACCOUNTS RECEIVABLE

Accounts receivable consisted of the following:

	As of December 31,
	2014			2013
	(in thousands)
Accrued production revenue	$	32,130		$	34,785
Joint interest billings	22,621			15,630
Income taxes	7,574			7,931
Canadian value added taxes	173			60
Other	2,937			328
Allowance for doubtful accounts	(277		)	(89		)
	$	65,158		$	58,645

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6. OTHER CURRENT ASSETS

Other current assets consisted of the following:

	As of December 31,
	2014		2013
	(in thousands)
Inventories	$	8,269	$	18,334
Deposits	1,284		1,044
Other prepaid expense	4,861		2,968
	$	14,414	$	22,346

7. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	As of December 31,
	2014			2013
	(in thousands)
Oil and natural gas properties
Subject to depletion	$	5,821,167		$	5,687,557
Unevaluated costs	18,803			221,605
Accumulated depletion	(5,225,302		)	(5,268,719		)
Net oil and natural gas properties	614,668			640,443
Other property and equipment
Pipelines and processing facilities	316,013			347,093
General properties	66,455			72,125
Accumulated depreciation	(268,356		)	(198,856		)
Net other property and equipment	114,112			220,362
Property, plant and equipment, net of accumulated depletion and depreciation	$	728,780		$	860,805

Ceiling Test Analysis and Impairment

The charges for impairment are summarized below:

		Pre-tax Charges for Impairment
	Segment	2014		2013		2012
		(in thousands)
U.S.
Oil and natural gas properties	Exploration and production	$	—	$	—	$	2,152,128
Other property and equipment	Midstream	135		54		7,328
Other property and equipment	Exploration and production	2,450		1,809		537
Canada
Oil and natural gas properties	Exploration and production	—		—		465,935
Other property and equipment	Midstream	58,360		—		—
Other property and equipment	Exploration and production	11,043		—		—
		$	71,988	$	1,863	$	2,625,928

In Canada during 2014, we impaired the Fortune Creek gathering system as we do not have sufficient liquidity to develop our Horn River Asset. An undiscounted cash flow analysis did not support the recoverability of the carrying value of the gathering system and a discounted cash flow analysis resulted in our recording an

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impairment of $58.4 million at December 31, 2014. Additionally, we impaired other property and equipment assets in our Horn River Asset at December 31, 2014 based on our inability to fund the development of our Horn River Asset.

In the U.S., we recognized other property and equipment impairment charges in 2014 and 2013 for surface land, buildings and pipeline in Texas. During 2012 we impaired pipelines and facilities in Colorado and Texas due to reduced anticipated utilization and a compressed natural gas facility in Texas due to reduced use.

As described in Note 2, we are required to perform a quarterly ceiling test for impairment of our oil and natural gas properties in each of our cost centers. We did not recognize impairment in 2014 and 2013 during our quarterly ceiling tests. 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 natural 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 natural gas properties, the AECO price declined 36% from the price used at December 31, 2011. In 2012, the impairment on our oil and natural 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.

Unevaluated Oil and Natural Gas Properties Not Subject to Depletion

Under full cost accounting, we may exclude certain unevaluated oil and natural gas property costs from the amortization base pending determination of whether proved reserves have been established or impairment has occurred. A summary of the unevaluated properties not subject to depletion at December 31, 2014 and 2013 and the year in which they were incurred follows:

	December 31, 2014 Costs Incurred During										December 31, 2013 Costs Incurred During
	2014		2013		2012		Prior		Total		2013		2012		2011		Prior		Total
	(in thousands)										(in thousands)
U.S.
Acquisition costs	$	5,637	$	—	$	1,574	$	9,029	$	16,240	$	—	$	3,013	$	13,484	$	—	$	16,497
Exploration costs	—		—		—		—		—		14		364		—		—		378
Capitalized interest	395		961		1,207		—		2,563		1,093		1,374		—		—		2,467
Total U.S.	$	6,032	$	961	$	2,781	$	9,029	$	18,803	$	1,107	$	4,751	$	13,484	$	—	$	19,342
Canada
Acquisition costs	$	—	$	—	$	—	$	—	$	—	$	—	$	2,956	$	1,300	$	68,586	$	72,842
Exploration costs	—		—		—		—		—		7,044		31,746		41,092		30,413		110,295
Capitalized interest	—		—		—		—		—		3,947		2,724		3,522		8,933		19,126
Total Canada	$	—	$	—	$	—	$	—	$	—	$	10,991	$	37,426	$	45,914	$	107,932	$	202,263
Total	$	6,032	$	961	$	2,781	$	9,029	$	18,803	$	12,098	$	42,177	$	59,398	$	107,932	$	221,605

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

	As of December 31,
	2014		2013
	(in thousands)
West Texas	$	18,803	$	19,343
Horn River Basin	—		202,262
Total	$	18,803	$	221,605

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 West Texas Asset will require up to an estimated three more years of exploration and development activity before

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evaluation is complete, which is covered by the remaining primary terms and the renewal term of the underlying leases, which were extended in 2014.

We continued to pursue a transaction involving our Horn River Asset in 2014, but after not reaching an agreement, we began to consider parallel marketing strategies and other strategic alternatives and, during the third quarter of 2014, we launched a formal marketing process, led by Houlihan Lokey, covering any and all of our operating assets. Bids were initially due in December 2014, but the bid deadline was subsequently extended to late January 2015. After the bid deadline passed, we evaluated the bids that were received with our advisors. Following discussions with various bidders, we concluded that the marketing process had not yet produced any viable options for asset sales or other strategic alternatives that would likely have a material impact on our capital structure or liquidity. In light of the results of our marketing efforts and our liquidity outlook, we do not have sufficient liquidity to develop the Horn River Asset. Therefore, and notwithstanding that a number of years remain under the primary lease terms, we determined to fully impair our Horn River Asset unevaluated oil and natural gas property costs to the Canadian cost center at December 31, 2014.

Other Matters

Capitalized overhead costs that directly relate to exploration and development activities were $11.2 million, $13.6 million and $16.8 million for 2014, 2013 and 2012, respectively. For 2014, depletion per Mcfe was $0.48 and $0.38 for the U.S. and Canada, 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. Depreciation expense was $15.2 million, $17.1 million and $18.6 million for 2014, 2013 and 2012, respectively.

8. OTHER ASSETS

Other assets consisted of the following:

	As of December 31,
	2014			2013
	(in thousands)
Deferred financing costs	$	62,319		$	84,951
Less accumulated amortization	(33,472		)	(50,171		)
Net deferred financing costs	28,847			34,780
Governmental and notes receivable	3,888			6,464
Other	119			360
	$	32,854		$	41,604

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

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9. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:

	As of December 31,
	2014		2013
	(in thousands)
Interest payable	$	36,288	$	38,260
Accrued operating expense	21,833		37,747
Prepayments from partners	—		425
Revenue payable	19,121		22,589
Accrued state income and franchise taxes	55		1,080
Accrued production and property taxes	677		870
Environmental liabilities	18		36
Accrued product purchases	310		270
Current asset retirement obligations	967		433
Other	1,877		1,140
	$	81,146	$	102,850

10. LONG-TERM DEBT

Long-term debt consisted of the following:

	As of December 31,
	2014			2013
	(in thousands)
Combined Credit Agreements	$	274,514		$	211,200
Second Lien Term Loan, net of unamortized discount of $14,758 and $17,428	610,242			607,572
Second Lien Notes due 2019, net of unamortized discount of $4,723 and $5,577	195,277			194,423
Senior Notes due 2015, net of unamortized discount of $0 and $2,149	—			10,472
Senior Notes due 2016, net of unamortized discount of $0 and $10,825	—			8,044
Senior Notes due 2019, net of unamortized discount of $4,081 and $5,378	293,919			293,243
Senior Notes due 2021, net of unamortized discount of $14,410 and $15,810	310,590			309,190
Senior Subordinated Notes due 2016	350,000			350,000
Total debt	2,034,542			1,984,144
Unamortized deferred gain—terminated interest rate swaps	2,763			4,802
Current portion of long-term debt	(2,037,305		)	—
Long-term debt	$	—		$	1,988,946

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Original maturities assuming no acceleration or springing maturity as of December 31, 2014 are as follows:

	2015		2016		2017		2018		2019		Thereafter
	(in thousands)
Combined Credit Agreements	$	—	$	274,514	$	—	$	—	$	—	$	—
Second Lien Term Loan	—		—		—		—		625,000		—
Second Lien Notes due 2019	—		—		—		—		200,000		—
Senior Notes due 2019	—		—		—		—		298,000		—
Senior Notes due 2021	—		—		—		—		—		325,000
Senior Subordinated Notes due 2016	—		350,000		—		—		—		—
Total Indebtedness	$	—	$	624,514	$	—	$	—	$	1,123,000	$	325,000

In February 2015, in light of (a) not yet having identified a transaction that would have a material impact on our capital structure or liquidity, (b) the potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, and (c) other potential defaults, we elected not to make the approximately $13.6 million interest payment on our Senior Notes due 2019, which was due on February 17, 2015. During the 30-day grace period provided for in the Senior Notes due 2019 Indenture, we continued discussions with our creditors. The discussions with our creditors did not produce an agreement that would enable us to effectively address, in a holistic manner, the impending issues adversely impacting our business, including (i) potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, (ii) potential near-term liquidity shortfalls due to the springing maturities, (iii) potential near-term breaches of certain financial covenants resulting from sharp declines in natural gas and NGL prices, and (iv) certain other potential defaults under our Combined Credit Agreements and the Second Lien Term Loan.

Accordingly, on March 17, 2015, the Company and our subsidiaries Barnett Shale Operating LLC, Cowtown Drilling, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline Funding, Inc., Cowtown Pipeline L.P., Cowtown Pipeline Management, Inc., Makarios Resources International Holdings LLC, Makarios Resources International Inc., QPP Holdings LLC, QPP Parent LLC, Quicksilver Production Partners GP LLC, Quicksilver Production Partners LP, and Silver Stream Pipeline Company LLC each filed a voluntary petition under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court to restructure our obligations and capital structure. Based on this subsequent event, we have classified all debt as current at December 31, 2014.

Our Chapter 11 filings constituted an event of default under the Combined Credit Agreements and all borrowings and other fees under the Combined Credit Agreements became immediately due and payable. The ability of the lenders under the Combined Credit Agreements to seek remedies to enforce their rights under the agreements was automatically stayed as a result of the Chapter 11 filings, and the lenders’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

On March 16, 2015, we, along with QRCI, entered into the Forbearance Agreement with the administrative agents and certain of the lenders under the Combined Credit Agreements. As a result of the Chapter 11 filing, the obligations under the Combined Credit Agreements were automatically accelerated. However, pursuant to the Forbearance Agreement, the administrative agents and the lenders agreed to, among other things, (i) forbear from exercising their rights and remedies in connection with specified defaults under the Amended and Restated Canadian Credit Facility related to our Chapter 11 filing until the earlier of June 16, 2015 or certain other events specified in the Forbearance Agreement, including, among other things, the commencement by QRCI or certain specified Canadian subsidiary guarantors of insolvency proceedings and (ii) waive compliance with certain specified terms and conditions relating to the renewal of outstanding evergreen letters of credit under the Combined Credit Agreements.

Our Chapter 11 filings also constituted an event of default under the Second Lien Term Loan, the Second Lien Notes, the Senior Notes due 2019, the Senior Notes due 2021, and the Senior Subordinated Notes. All principal, interest and other amounts under each of these debt instruments became immediately due and payable. The ability of the lenders and noteholders to seek remedies to enforce their rights under the applicable debt instruments was automatically stayed as a result of the Chapter 11 filings, and the lenders’ and noteholders’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

Our failure to make the interest payment on our Senior Notes due 2019 within the 30-day grace period described above would have resulted in an event of default, permitting the trustee or holders of at least 25% of the

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aggregate principal amount outstanding of the Senior Notes due 2019 to declare the principal and accrued interest for all the Senior Notes due 2019 due and payable immediately, which in turn would have resulted in defaults under the terms of our other indebtedness.

Combined Credit Agreements

The Combined Credit Agreements’ global borrowing base was $325 million and the global letter of credit capacity was $280 million as of December 31, 2014. At December 31, 2014, we had $9.2 million available under the Combined Credit Agreements, all of which could be used for letters of credit. On March 17, 2015, we repaid $36.7 million of amounts outstanding under our Combined Credit Agreements from proceeds of derivative terminations. We expect to use the remaining cash proceeds from recently terminated derivatives to pay down our Combined Credit Agreements.

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

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

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

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%.

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

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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.

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

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.

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

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, 2014, we did not meet this test and, as a result, we are limited in our ability to, among other things, incur additional debt, except for specific baskets.

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

Springing Maturities

As of December 31, 2014, as then structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would have been due on October 2, 2015 and the Second Lien Term Loan and Second Lien Notes due 2019 would have been due on January 1, 2016.

Interest Expense

Interest expense was $163.3 million and $251.8 million, net of capitalized interest of $5.7 million and $7.7 million, for the years ended December 31, 2014 and 2013, 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, 2014:

	Priority on Collateral and Structural Seniority (1)
	Highest priority							Lowest priority
	First Lien	Second Lien			Senior Unsecured		Senior Subordinated
	Combined Credit Agreements		Second Lien Term Loan	Second Lien Notes due 2019	2019 Senior Notes	2021 Senior Notes		Senior Subordinated Notes
Principal amount (1)(2)	$325 million		$625 million	$200 million	$298 million	$325 million		$350 million
Scheduled maturity date (3)	September 6, 2016		June 21, 2019	June 21, 2019	August 15, 2019	July 1, 2021		April 1, 2016
Springing maturity date (3)	October 2, 2015		January 1, 2016	January 1, 2016	N/A	N/A		N/A
Interest rate on outstanding borrowings at December 31, 2014 (4)	4.10%		7.00%	7.00%	9.125%	11.00%		7.125%
Base interest rate options (5)(6)	LIBOR, ABR, CDOR		LIBOR floor of 1.25%; ABR floor of 2.25%	LIBOR floor of 1.25%	N/A	N/A		N/A
Financial covenants (7)(9)	- Minimum current ratio of 1.0 - Minimum EBITDAX or EBITDA to cash interest expense - Maximum senior secured debt leverage ratio of 2.0		N/A	N/A	N/A	N/A		N/A
Significant restrictive covenants (8)(9)	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions - Limitations on derivatives and investments		- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions		- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions
Optional redemption (9)	Any time		Any time, subject to re-pricing event June 21, 2015: 101	Any time, subject to re-pricing event June 21, 2015: 101	August 15, 2014: 104.563 2015: 103.042 2016: 101.521 2017: par	July 1, 2019: 102.000 2020: par		Any time
Make-whole redemption (9)	N/A		N/A	N/A	N/A	Callable prior to July 1, 2019 at make-whole call price of Treasury +50 bps		N/A
Change of control (9)	Event of default		Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest	Put at 101% of principal plus accrued interest		Put at 101% of principal plus accrued interest
Equity clawback (9)	N/A		N/A	N/A	N/A	Redeemable until July 1, 2016 at 111.00%, plus accrued interest for up to 35%		N/A
Estimated fair value (10)	$274.5 million		$465.6 million	$149.0 million	$74.8 million	$87.9 million		$26.5 million

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⁽¹⁾ Borrowings under the Amended and Restated U.S. Credit Facility, Second Lien Term Loan and Second Lien Notes due 2019 are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured (on a first priority basis with respect to the Amended and Restated U.S. Credit Facility and on a second priority basis with respect to the Second Lien Term Loan and the Second Lien Notes due 2019) by 100% of the equity interests of each of Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Barnett Shale Operating LLC, Silver Stream Pipeline Company LLC, QPP Parent LLC and QPP Holdings LLC (collectively, the “Domestic Pledged Equity”), 65% of the equity interests of Quicksilver Resources Canada Inc. (“Quicksilver Canada”) and Quicksilver Production Partners Operating Ltd. (with respect to the Amended and Restated U.S. Credit Facility, on a ratable basis with borrowings under the Amended and Restated Canadian Credit Facility) and the majority of Quicksilver's domestic proved oil and natural 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 natural 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, 2014.

⁽³⁾ The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the Senior Subordinated Notes, the Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Second Lien Term Loan and Second Lien Notes due 2019 are required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remain outstanding and (2) 91 days prior to the maturity of the Senior Subordinated Notes if on the applicable date the amount remaining outstanding is greater than $100 million. As of December 31, 2014, as then structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would have been due on October 2, 2015 and the Second Lien Term Loan and Second Lien Notes due 2019 would have been due on January 1, 2016.

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

⁽⁵⁾ Amounts outstanding under the Amended and Restated U.S. Credit Facility bear interest, at our election, at (i) adjusted LIBOR (as defined in the Amended and Restated U.S. Credit Facility) plus an applicable margin between 2.75% and 3.75%, (ii) ABR (as defined in the Amended and Restated U.S. Credit Facility), which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) adjusted LIBOR for an interest period of one month plus 1.00%, plus, in each case under scenario, (ii) an applicable margin between 1.75% and 2.75%. We also pay a per annum fee on the LC Exposure (as defined in the Amended and Restated U.S. Credit Facility) of all letters of credit issued under the Amended and Restated U.S. Credit Facility equal to the applicable margin, with respect to Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.50%. Beginning on March 17, 2015, as part of the Forbearance Agreement, we agreed to pay interest monthly at a specified rate of ABR plus the applicable margin.

⁽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

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0.50%. Beginning on March 17, 2015, as part of the Forbearance Agreement, we agreed to pay interest monthly at a specified rate for Canadian dollar denominated borrowings of Canadian prime plus the default rate plus the applicable margin and for U.S. dollar denominated borrowings, U.S. prime plus the default rate plus the applicable margin.

⁽⁷⁾ As of December 31, 2014, the minimum EBITDAX covenant for the Combined Credit Agreements is as follows:

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

The minimum required interest coverage ratio for the Combined Credit Agreements for first quarter of 2016 and second quarter of 2016 is 1.50 and 2.00, respectively.

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

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

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

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Quicksilver Resources Inc. and its Restricted Subsidiaries

The following tables, required under our indentures, provide information about Quicksilver Resources Inc. and the entities designated as restricted subsidiaries under the indentures for our Second Lien Notes, Senior Notes and Senior Subordinated Notes. Eliminations between Quicksilver Resources Inc., the related restricted guarantor subsidiaries and restricted non-guarantor subsidiaries are included in the tables below as necessary.

Condensed Consolidating Balance Sheets

	December 31,
	2014			2013
	(in thousands)
ASSETS
Current assets	$	421,533		$	393,713
Property and equipment	715,931			779,173
Investment in subsidiaries (equity method)	(82,360		)	(33,840		)
Other assets	62,245			114,961
Total assets	$	1,117,349		$	1,254,007
LIABILITIES AND EQUITY
Current liabilities	2,137,532			134,010
Long-term liabilities	117,688			2,113,221
Stockholders’ equity	(1,137,871		)	(993,224		)
Total liabilities and equity	$	1,117,349		$	1,254,007

Condensed Consolidating Statements of Income

	For the Year Ended
	2014			2013			2012
	(in thousands)
Revenue	$	569,428		$	561,562		$	709,038
Operating expenses	434,998			448,802			3,222,595
Tokyo Gas Transaction gain	—			339,328			—
Crestwood earn-out	—			—			41,097
Equity in net earnings of subsidiaries	(64,056		)	(6,682		)	(12,747		)
Operating income (loss)	70,374			445,406			(2,485,207		)
Interest expense and other	(169,874		)	(269,238		)	(162,991		)
Income tax (expense) benefit	(3,600		)	(14,550		)	295,592
Net income (loss)	$	(103,100	)	$	161,618		$	(2,352,606	)
Other comprehensive loss	(38,028		)	(51,612		)	(53,365		)
Comprehensive income (loss)	$	(141,128	)	$	110,006		$	(2,405,971	)

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Condensed Consolidating Statements of Cash Flow

	For the Year Ended
	2014			2013			2012
	(in thousands)
Net cash flow provided by (used in) operating activities	$	(13,614	)	$	(62,131	)	$	213,280
Capital expenditures	(133,481		)	(100,783		)	(474,748		)
Investment in subsidiary	(26,395		)	—			—
Proceeds from Southwestern Transaction	95,587			—			—
Proceeds from Tokyo Gas Transaction	—			463,999			—
Proceeds from Synergy Transaction	—			42,297			—
Proceeds from Crestwood earn-out	—			—			41,097
Proceeds from sale of properties and equipment	3,222			7,171			72,725
Purchases of marketable securities	(55,890		)	(213,738		)	—
Maturities and sales of marketable securities	222,025			47,603			—
Net cash flow provided by (used in) investing activities	105,068			246,549			(360,926		)
Issuance of debt	243,184			1,237,352			467,959
Repayments of debt	(193,689		)	(1,308,382		)	(310,430		)
Debt issuance costs paid	(1,705		)	(26,296		)	(3,022		)
Proceeds from exercise of stock options	—			—			11
Purchase of treasury stock	(2,388		)	(1,927		)	(3,144		)
Net cash flow provided by (used in) financing activities	45,402			(99,253		)	151,374
Effect of exchange rates on cash	(3,046		)	(1,755		)	527
Net increase in cash and equivalents	133,810			83,410			4,255
Cash and equivalents at beginning of period	88,028			4,618			363
Cash and equivalents at end of period	$	221,838		$	88,028		$	4,618

11. ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated asset retirement obligation from January 1, 2013 through December 31, 2014.

	As of December 31,
	2014			2013
	(in thousands)
Beginning asset retirement obligations	$	106,689		$	116,526
Additional liability incurred	269			3,922
Change in estimates	(229		)	7,582
Accretion expense	5,618			5,109
Asset retirement costs incurred	(388		)	(1,560		)
Settlement of liability in excess of obligation recorded	146			742
Disposition	(1,778		)	(21,935		)
Currency translation adjustment	(5,311		)	(3,697		)
Ending asset retirement obligations	105,016			106,689
Less current portion	(967		)	(433		)
Long-term asset retirement obligation	$	104,049		$	106,256

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12. INCOME TAXES

Significant components of our deferred tax assets and liabilities as of December 31, 2014 and 2013 are as follows:

	As of December 31,
	2014			2013
	(in thousands)
Deferred tax assets:
Property, plant and equipment	$	148,360		$	209,134
Net operating loss carry-forwards	289,261			183,982
Investment in Fortune Creek	3,763			3,763
AMT tax credit	40,309			47,883
Settlements of interest rate swaps	967			1,681
Deferred compensation expense	11,087			11,711
State	2,048			3,680
Other	421			791
Deferred tax assets	496,216			462,625
Deferred tax liabilities:
Net derivative gains	(61,638		)	(44,039		)
Other	(470		)	(991		)
Deferred tax liabilities	(62,108		)	(45,030		)
Net deferred tax asset (liability)	434,108			417,595
Valuation allowance	(434,108		)	(417,595		)
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 2014, 2013 and 2012 are as follows:

	2014			2013			2012
				(in thousands)
U.S.	$	(41,865	)	$	184,034		$	(2,142,730	)
Canada	(57,635		)	(7,866		)	(505,446		)
Total	$	(99,500	)	$	176,168		$	(2,648,176	)

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. In 2012, we utilized a rate of 25.0% in Canada, while our U.S. federal and state rates were consistent with our 2013 and beyond rates.

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The components of income tax expense for 2014, 2013 and 2012 are as follows:

	2014			2013			2012
				(in thousands)
Current state income tax expense (benefit)	$	(144	)	$	900		$	1,752
Current U.S. federal income tax benefit	(7,574		)	(7,931		)	—
Current Canadian income tax expense	559			—			—
Total current income tax expense (benefit)	(7,159		)	(7,031		)	1,752
Deferred U.S. federal income tax expense (benefit)	(11,238		)	205,820			(763,639		)
U.S. federal valuation allowance expense	21,011			(186,713		)	533,974
Deferred state income tax expense (benefit)	1,632			(3,680		)	—
State valuation allowance expense	(1,632		)	3,680			—
Deferred Canadian income tax expense (benefit)	3,620			827			(128,982		)
Canadian valuation allowance expense	(2,634		)	1,647			61,325
Total deferred income tax expense (benefit)	10,759			21,581			(297,322		)
Total income tax expense (benefit)	$	3,600		$	14,550		$	(295,570	)

The following table reconciles the statutory federal income tax rate to the effective tax rate for 2014, 2013 and 2012:

	2014		2013		2012
U.S. federal statutory tax rate	35.00	%	35.00	%	35.00	%
Permanent differences	(27.05	)%	4.80	%	(0.06	)%
State income taxes net of federal deduction	0.09	%	0.31	%	(0.04	)%
Canadian income taxes	1.40	%	(0.26	)%	(1.93	)%
Other	(0.30	)%	(0.15	)%	0.67	%
Derivatives deferred in OCI	(11.07	)%	12.43	%	—	%
AMT NOL refund	7.61	%	—	%	—	%
Valuation allowance	(9.30	)%	(43.87	)%	(22.48	)%
Effective income tax rate	(3.62	)%	8.26	%	11.16	%

As of December 31, 2013, we had net operating tax loss carry-forwards for federal tax purposes of $529 million. During the year ended December 31, 2014, we generated additional net operating losses of $283 million. The total $812 million is included in deferred tax assets, and will expire between 2029 and 2034. The net operating loss carry-forwards can be used to offset future taxable income. As of December 31, 2014, we have $40 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 2014 is principally composed of the reversal in 2014 of deferred tax liabilities related to hedging in other comprehensive income that had previously reduced the valuation allowance necessary. During 2014, we increased the U.S. federal deferred tax asset and corresponding valuation allowance by $21.0 million. The U.S. state valuation allowance decreased by $1.6 million. The Canadian valuation allowance decreased by $2.6 million. Additionally, our tax 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. We have a full valuation allowance of $3.7 million for all periods shown 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 open audits for tax years 2010 and 2012. Tax years after December 31, 2009 remain subject to audit by the IRS.

We have no unrecognized tax benefits for 2013 or 2014.

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13. COMMITMENTS AND CONTINGENCIES

Contractual Obligations

Information regarding our contractual obligations, at December 31, 2014, is set forth in the following table:

	GPT     Contracts (1)		Drilling Rig     Contracts (2)		Operating     Leases (3)		Purchase     Obligations (4)
	(in thousands)
2015	$	72,995	$	6,577	$	4,181	$	220
2016	69,566		—		4,275		—
2017	66,492		—		4,098		—
2018	60,453		—		3,961		—
2019	44,241		—		4,001		—
Thereafter	95,250		—		8,849		—
Total	$	408,997	$	6,577	$	29,365	$	220

⁽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 unused firm capacity rate. Our gathering and transportation contracts with CMLP have no minimum volume requirement and, therefore, are not reported in the above amounts. As described below, this amount includes an amount we expect the service provider will claim to be entitled to with respect to QRCI's gathering and processing contract as of December 31, 2014. As further described below, the contract was terminated in March 2015 and we expect that we and the third party will disagree regarding the remaining amounts payable under the contract.

⁽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 ranging from $23,000 to $24,300 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 $3.5 million in 2014, $3.6 million in 2013 and $4.2 million in 2012. Minimum payments have not been reduced by minimum sublease rentals of $1.6 million due in the future under noncancelable subleases.

⁽⁴⁾  At December 31, 2014, we were under contract to purchase goods and services.

Commitments and Contingencies

At December 31, 2014, we had $6.4 million in surety bonds issued to fulfill contractual, legal or regulatory requirements and $41.3 million in letters of credit outstanding against the credit facility. Surety bonds and letters of credit generally have an annual renewal option.

QRCI did not pay an uneconomic Canadian gathering and processing commitment, which included significant unused firm capacity, due in late February 2015. In early March 2015, the third party service provider issued a demand letter regarding the missed payment and suspended service resulting in our production in our Horn River Asset being shut-in. Further, a termination notice was issued effective March 19, 2015. We are exploring alternatives to gather and process our Horn River Asset production; however, we may not be able to find economic alternatives in the near-term, or at all.

In connection with this Canadian gathering and processing contract, we had previously issued a letter of credit in the amount of C$33 million. Upon termination, the third party drew down the full face amount of the letter of credit. We do not believe the third party was legally entitled to draw down the entire amount of the letter of credit and we have reserved all of our rights, entitlements and remedies in that regard.

We expect that we and the third party will disagree as to what are the remaining obligations under the relevant agreement and the length of the remaining term of the agreement and as to the remedies and defenses available to the parties. While we expect to vigorously dispute the amount, we expect that the third party will

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claim to be entitled to up to approximately C$126 million (including the proceeds of the letter of credit) as the aggregate of the monthly tolls for firm capacity for the alleged remainder of the term of the relevant agreement.

As a result of our partial working interest sale to Eni in 2009, we entered into a joint development agreement with Eni in our Barnett Shale Asset. 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 each of July 2011 and June 2012, we received a subpoena duces tecum from the SEC requesting certain documents. In July 2014, the SEC notified us that the staff has completed its investigation and does not intend to recommend an enforcement action by the SEC against us.

We are subject to various proceedings and claims that arise in the ordinary course of business, including in certain cases limited guarantees of QRCI's performance by us. 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, 2014, we had recorded less than $0.1 million for liabilities for environmental matters.

14. 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 C$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 C$180 million as of December 31, 2014. The costs to be incurred under the spending requirement generally reflect the capital expenditures of all working interests in the well for wells in which we have a working interest regardless of our working interest percentage. To the extent these minimum capital expenditure commitments are not met, we will incur a cash penalty in an amount equal to the shortfall, which would reduce, by an equal amount, our cash payments under the gathering agreement in the final months of its initial term and would also reduce the balance of the Partnership Liability as presented on the consolidated balance sheet. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by C$0.13 per Mcf until at least 2016. We are required to purchase equipment used by Fortune Creek, at our election, in either January 2016 or May 2018 at a price of C$33 million. We do not expect to be able to satisfy these capital expenditure

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requirements or equipment purchases with our cash on hand, committed financing or cash flow from operations and will need to obtain additional debt or equity financing or sell assets, which we may not be able to do on satisfactory terms, or at all.

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

The firm gathering agreement with Fortune Creek is guaranteed by us. 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 or the cash penalty under the minimum capital expenditure, KKR has the right to liquidate the partnership and could assert a guarantee claim against us. 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 17 contains financial information for Fortune Creek in our condensed consolidating financial statements. Note 7 contains information about our impairment of the Fortune Creek gathering system.

15. 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, 2014, we had 180.4 million shares of common stock outstanding.

The following table shows common share and treasury share activity since January 1, 2012:

	Common     Shares Issued	Treasury     Shares Held
Balance at January 1, 2012	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
Stock options exercised	—	—
Restricted stock activity	3,808,115	745,732
Balance at December 31, 2014	187,802,994	7,444,372

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

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“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 25% of our common stock at March 17, 2015, 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.

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, 2014 and 2013, 11.6 million shares and 15.4 million shares, respectively, were available for issuance under the 2006 Equity Plan.

Stock Options

No options were granted during 2014. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during 2013 and 2012:

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

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The following table summarizes our stock option activity for 2014:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
					(in years)	(in thousands)
Outstanding at January 1, 2014	6,771,578		$	7.82
Forfeited	(60,939	)	3.04
Expired	(119,866	)	9.80
Outstanding at December 31, 2014	6,590,773		$	7.83	5.1	$	—
Exercisable at December 31, 2014	5,224,531		$	9.18	4.3	$	—

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 $8.07 and a weighted average remaining contractual life of 5.0 years.

As of December 31, 2014 the unrecognized compensation cost related to outstanding unvested options was $0.5 million, which is expected to be recognized in expense through August 2016. Compensation expense related to stock options of $1.4 million, $3.9 million and $7.4 million was recognized for 2014, 2013 and 2012, respectively. The income tax benefit recognized in income, prior to any tax valuation allowance consideration, related to this compensation expense during 2014 and 2013 was $0.4 million and $1.3 million, respectively. The total intrinsic value of options exercised during 2012 was $0.1 million. No options were exercised in 2014 and 2013.

Restricted Stock and Stock Units

The following table summarizes our restricted stock and stock unit activity for 2014:

	Payable in shares				Payable in cash
	Shares		Weighted Average Grant Date Fair Value		Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2014	5,668,090		$	3.90	1,572,341		$	3.69
Granted	6,070,563		2.19		—		—
Vested	(2,559,959	)	4.86		(636,146	)	4.27
Forfeited	(1,122,429	)	2.26		(72,220	)	3.28
Outstanding at December 31, 2014	8,056,265		$	2.54	863,975		$	3.33

As of December 31, 2014, the unrecognized compensation cost related to outstanding unvested restricted stock and RSUs was $11.7 million, which is expected to be recognized through December 2016. Grants of restricted stock and RSUs during 2014 had an estimated grant date fair value of $13.3 million. The fair value of RSUs to be settled in cash was $0.2 million and $4.8 million during 2014 and 2013, respectively. For 2014, 2013 and 2012, compensation expense related to restricted stock and RSUs of $10.5 million, $16.8 million and $15.7 million, respectively, was recognized. The income tax benefit recognized in income, prior to any tax valuation allowance consideration, related to this compensation expense during 2014 and 2013 was $3.2 million and $5.2 million, respectively. The total fair value of shares vested during 2014, 2013 and 2012 was $10.2 million, $7.1 million and $16.3 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.

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Accumulated Other Comprehensive Income

At December 31, 2014, AOCI included $69.8 million, net of tax, and $2.1 million for derivatives and foreign currency translation, respectively. At December 31, 2013, AOCI included $94.5 million, net of tax, and $15.4 million for derivatives and foreign currency translation, respectively.

16. 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,
	2014			2013			2012
	(in thousands, except per share data)
Net income (loss) attributable to Quicksilver	$	(103,100	)	$	161,618		$	(2,352,606	)
Basic income allocable to participating securities (1)	—			(4,252		)	—
Income (loss) available to shareholders	$	(103,100	)	$	157,366		$	(2,352,606	)
Weighted average common shares – basic	173,822			171,518			170,106
Effect of dilutive securities (2)
Share-based compensation awards	—			141			—
Weighted average common shares — diluted	173,822			171,659			170,106
Earnings (loss) per common share — basic	$	(0.59	)	$	0.92		$	(13.83	)
Earnings (loss) per common share — diluted	$	(0.59	)	$	0.92		$	(13.83	)

⁽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 2014, 6.6 million shares associated with our stock options and 1.0 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. 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.

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17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The following tables provide information about the entities that guarantee our Second Lien Notes, 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 our Second Lien Notes, Senior Notes and our Senior Subordinated Notes distinguish between “restricted” subsidiaries and “unrestricted” subsidiaries. The following table illustrates our subsidiaries and their status pursuant to the Second Lien Notes, 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
Cowtown Pipeline Management, Inc.	Cowtown Drilling Inc. (1)	1622834 Alberta Inc.
Cowtown Pipeline L.P.	Quicksilver Resources Partners Operating Ltd. (2)	Makarios Midstream Inc.
Cowtown Gas Processing L.P.	0942065 B.C. Ltd. (2)	Makarios Resources International Inc.
Barnett Shale Operating LLC	0942069 B.C Ltd. (2)	Quicksilver Production Partners GP LLC
QPP Parent LLC (2)		Quicksilver Production Partners LP
QPP Holdings LLC (2)
Silver Stream Pipeline Company LLC (2)

⁽¹⁾ This entity was inactive for the three-year period ended December 31, 2014.

⁽²⁾  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 Second Lien Notes, 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 terms of the indentures include customary release provisions providing that a subsidiary guarantor will be released from its obligations under a subsidiary guarantee automatically:

• upon the sale, disposition or other transfer (other than by lease) of (i) the capital stock of such subsidiary following which such subsidiary guarantor is no longer a subsidiary of us or (ii) all or substantially all the assets of the applicable subsidiary guarantor, in each case, to a person that is not us or a restricted subsidiary of us, provided that such sale, disposition or other transfer is made in compliance with the applicable provisions of the indentures and all of the obligations of the subsidiary guarantor under any credit facility and related documentation or other agreement relating to other indebtedness of us or our restricted subsidiaries terminates upon the consummation of such transaction; or

110

• if we designate any restricted subsidiary that is a subsidiary guarantor as an unrestricted subsidiary in accordance with the applicable provisions of the indentures.

In addition, the obligations of each subsidiary guarantor under its subsidiary guarantee are designed to be limited as necessary to prevent that subsidiary guarantee from constituting a fraudulent conveyance under applicable bankruptcy, insolvency, reorganization or similar laws and, therefore, such subsidiary guarantee is specifically limited to an amount that such subsidiary guarantor could guarantee without such subsidiary guarantee constituting a fraudulent conveyance.

Under the terms of the indentures, restricted guarantor subsidiaries, which fully and unconditionally and jointly and severally guarantee our obligations under the Second Lien Notes, Senior Notes or the Senior Subordinated Notes, do not include restricted subsidiaries that are (i) foreign subsidiaries, or those subsidiaries that are not organized under the laws of the United States of America or any state thereof or the District of Columbia (and any subsidiary of such a subsidiary) and (ii) any subsidiary that is not a wholly-owned subsidiary that (1) is classified as a pass-through entity for U.S. federal, state, local and foreign income tax purposes and (2) has no indebtedness.

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

111

Condensed Consolidating Balance Sheets

	December 31, 2014
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek		Consolidating Eliminations			Quicksilver Resources  Inc. Consolidated
	(in thousands)
ASSETS
Current assets	$	774,287		$	13,909		$	68,513		$	82		$	1,742	$	(435,256	)	$	423,277
Property and equipment	420,744			14,357			280,830			—			12,849		—			728,780
Investment in subsidiaries (equity method)	(293,312		)	—			(82,360		)	(82,379		)	—		458,051			—
Other assets	43,533			—			18,712			—			—		—			62,245
Total assets	$	945,252		$	28,266		$	285,695		$	(82,297	)	$	14,591	$	22,795		$	1,214,302
LIABILITIES AND EQUITY
Current liabilities	$	2,038,575		$	13,837		$	520,296		$	63		$	3,522	$	(435,256	)	$	2,141,037
Long-term liabilities	44,548			15,131			58,009			—			1,492		91,956			211,136
Stockholders’ equity	(1,137,871		)	(702		)	(292,610		)	(82,360		)	9,577		366,095			(1,137,871		)
Total liabilities and equity	$	945,252		$	28,266		$	285,695		$	(82,297	)	$	14,591	$	22,795		$	1,214,302

	December 31, 2013
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor  Subsidiaries			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek		Consolidating Eliminations			Quicksilver Resources  Inc. Consolidated
	(in thousands)
ASSETS
Current assets	$	349,586		$	10,735		$	53,034		$	909		$	1,110	$	(21,414	)	$	393,960
Property and equipment	455,822			15,486			307,865			—			81,632		—			860,805
Investment in subsidiaries (equity method)	(217,852		)	—			(33,840		)	(33,840		)	—		285,532			—
Other assets	472,792			—			32,892			—			—		(390,723		)	114,961
Total assets	$	1,060,348		$	26,221		$	359,951		$	(32,931	)	$	82,742	$	(126,605	)	$	1,369,726
LIABILITIES AND EQUITY
Current liabilities	$	124,275		$	12,210		$	17,167		$	888		$	1,671	$	(21,414	)	$	134,797
Long-term liabilities	1,942,043			19,242			542,659			—			1,546		(264,591		)	2,240,899
Stockholders’ equity	(1,005,970		)	(5,231		)	(199,875		)	(33,819		)	79,525		159,400			(1,005,970		)
Total liabilities and equity	$	1,060,348		$	26,221		$	359,951		$	(32,931	)	$	82,742	$	(126,605	)	$	1,369,726

112

Condensed Consolidating Statements of Income

	For the Year Ended December 31, 2014
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek			Consolidating Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
Revenue	$	410,455		$	5,730		$	153,243		$	—		$	17,585		$	(17,585	)	$	569,428
Operating expenses	299,499			1,286			134,213			—			66,581			(17,585		)	483,994
Equity in net earnings of subsidiaries	(55,678		)	—			(64,056		)	(48,989		)	—			168,723			—
Operating income (loss)	55,278			4,444			(45,026		)	(48,989		)	(48,996		)	168,723			85,434
Fortune Creek accretion	—			—			—			—			—			(15,067		)	(15,067		)
Interest expense and other	(157,350		)	86			(12,610		)	—			7			—			(169,867		)
Income tax (expense) benefit	(2,614		)	(1,586		)	(986		)	—			—			1,586			(3,600		)
Net income (loss)	$	(104,686	)	$	2,944		$	(58,622	)	$	(48,989	)	$	(48,989	)	$	155,242		$	(103,100	)
Other comprehensive income (loss)	(31,476		)	—			(6,552		)	—			—			—			(38,028		)
Equity in OCI of subsidiaries	(6,552		)	—			—			—			—			6,552			—
Comprehensive income (loss)	$	(142,714	)	$	2,944		$	(65,174	)	$	(48,989	)	$	(48,989	)	$	161,794		$	(141,128	)

	For the Year Ended December 31, 2013
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries		Restricted Non-Guarantor Subsidiaries			Unrestricted Non-Guarantor Subsidiaries		Fortune Creek		Consolidating Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
Revenue	$	416,516		$	788	$	144,258		$	—	$	22,364	$	(22,364	)	$	561,562
Operating expenses	329,975			346		118,481			—		9,808		(22,364		)	436,246
Tokyo Gas Transaction gain	339,328			—		—			—		—		—			339,328
Equity in net earnings of subsidiaries	(9,896		)	—		(6,682		)	12,563		—		4,015			—
Operating income (loss)	415,973			442		19,095			12,563		12,556		4,015			464,644
Fortune Creek accretion	—			—		—			—		—		(19,245		)	(19,245		)
Interest expense and other	(242,279		)	—		(26,959		)	—		7		—			(269,231		)
Income tax expense	(12,076		)	—		(2,474		)	—		—		—			(14,550		)
Net income (loss)	$	161,618		$	442	$	(10,338	)	$	12,563	$	12,563	$	(15,230	)	$	161,618
Other comprehensive loss	(40,166		)	—		(11,446		)	—		—		—			(51,612		)
Equity in OCI of subsidiaries	(11,446		)	—		—			—		—		11,446			—
Comprehensive income (loss)	$	110,006		$	442	$	(21,784	)	$	12,563	$	12,563	$	(3,784	)	$	110,006

113

	For the Year Ended December 31, 2012
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Unrestricted Non-Guarantor Subsidiaries		Fortune Creek		Consolidating Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
Revenue	$	611,477		$	4,574		$	95,887		$	—	$	14,639	$	(17,539	)	$	709,038
Operating expenses	2,643,690			4,109			577,696			—		7,940		(17,539		)	3,215,896
Crestwood earn-out	41,097			—			—			—		—		—			41,097
Equity in net earnings of subsidiaries	(437,510		)	—			(12,747		)	6,726		—		443,531			—
Operating income (loss)	(2,428,626		)	465			(494,556		)	6,726		6,699		443,531			(2,465,761		)
Fortune Creek accretion	—			—			—			—		—		(19,472		)	(19,472		)
Interest expense and other	(152,077		)	—			(10,914		)	21		27		—			(162,943		)
Income tax (expense) benefit	228,097			(163		)	67,658			—		—		(22		)	295,570
Net income (loss)	$	(2,352,606	)	$	302		$	(437,812	)	$	6,747	$	6,726	$	424,037		$	(2,352,606	)
Other comprehensive income (loss)	(57,273		)	—			3,908			—		—		—			(53,365		)
Equity in OCI of subsidiaries	3,908			—			—			—		—		(3,908		)	—
Comprehensive income (loss)	$	(2,405,971	)	$	302		$	(433,904	)	$	6,747	$	6,726	$	420,129		$	(2,405,971	)

114

Condensed Consolidating Statements of Cash Flow

	For the Year Ended December 31, 2014
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries			Restricted Non-Guarantor Subsidiaries			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek			Consolidating Eliminations			Quicksilver Resources Inc. Consolidated
	(in thousands)
Net cash flow provided by (used in) operating activities	$	(43,824	)	$	(1,349	)	$	31,559		$	(2	)	$	5,987		$	—		$	(7,629	)
Capital expenditures	(102,898		)	(60		)	(30,523		)	—			—			—			(133,481		)
Investment in subsidiary	881			—			(26,395		)	(26,395		)	—			51,909			—
Proceeds from Southwestern Transaction	95,587			—			—			—			—			—			95,587
Proceeds from sale of properties and equipment	2,549			—			673			—			—			—			3,222
Purchases of marketable securities	(55,890		)	—			—			—			—			—			(55,890		)
Maturities and sales of marketable securities	222,025			—			—			—			—			—			222,025
Net cash flow provided by (used in) investing activities	162,254			(60		)	(56,245		)	(26,395		)	—			51,909			131,463
Issuance of debt	174,000			—			69,184			—			—			—			243,184
Repayments of debt	(138,651		)	—			(55,038		)	—			—			—			(193,689		)
Debt issuance costs	(1,069		)	—			(636		)	—			—			—			(1,705		)
Intercompany note	(22,559		)	—			22,559			—			—			—			—
Intercompany financing	—			1,409			(2,290		)	—			—			881			—
Contribution received	—			—			—			26,395			26,395			(52,790		)	—
Distribution of Fortune Creek Partnership funds	—			—			—			—			(39,993		)	—			(39,993		)
Purchase of treasury stock	(2,388		)	—			—			—			—			—			(2,388		)
Net cash flow provided by (used in) financing activities	9,333			1,409			33,779			26,395			(13,598		)	(51,909		)	5,409
Effect of exchange rates on cash	—			—			(3,046		)	—			8,229			—			5,183
Net increase in cash and equivalents	127,763			—			6,047			(2		)	618			—			134,426
Cash and equivalents at beginning of period	83,893			—			4,135			22			1,053			—			89,103
Cash and equivalents at end of period	$	211,656		$	—		$	10,182		$	20		$	1,671		$	—		$	223,529

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	For the Year Ended December 31, 2013
	Quicksilver Resources Inc.			Restricted Guarantor Subsidiaries		Restricted Non-Guarantor Subsidiaries			Unrestricted Non-Guarantor Subsidiaries		Fortune Creek			Quicksilver Resources Inc. Consolidated
	(in thousands)
Net cash flow provided by (used in) operating activities	$	(82,722	)	$	—	$	20,591		$	22	$	10,409		$	(51,700	)
Capital expenditures	(67,263		)	—		(33,520		)	—		(505		)	(101,288		)
Proceeds from Tokyo Gas Transaction	463,999			—		—			—		—			463,999
Proceeds from Synergy Transaction	42,297			—		—			—		—			42,297
Proceeds from sale of properties and equipment	7,128			—		43			—		—			7,171
Purchases of marketable securities	(213,738		)	—		—			—		—			(213,738		)
Maturities and sales of marketable securities	47,603			—		—			—		—			47,603
Net cash flow provided by (used in) investing activities	280,026			—		(33,477		)	—		(505		)	246,044
Issuance of debt	1,215,266			—		22,086			—		—			1,237,352
Repayments of debt	(1,157,969		)	—		(150,413		)	—		—			(1,308,382		)
Debt issuance costs	(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		)
Net cash flow provided by (used in) financing activities	(118,029		)	—		18,776			—		(14,965		)	(114,218		)
Effect of exchange rates on cash	—			—		(1,755		)	—		5,781			4,026
Net increase in cash and equivalents	79,275			—		4,135			22		720			84,152
Cash and equivalents at beginning of period	4,618			—		—			—		333			4,951
Cash and equivalents at end of period	$	83,893		$	—	$	4,135		$	22	$	1,053		$	89,103

116

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

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18. 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 natural 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. 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)
2014
Revenue	$	410,444		$	150,876		$	25,693		$	—		$	(17,585	)	$	569,428
DD&A	30,411			23,902			4,970			1,843			—			61,126
Impairment expense	2,450			11,043			58,495			—			—			71,988
Operating income (loss)	156,382			22,601			(44,412		)	(49,137		)	—			85,434
Property and equipment costs incurred	100,592			27,585			86			1,127			—			129,390
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
Property, plant and equipment—net
December 31, 2014	$	416,901		$	280,830		$	27,205		$	3,844		$	—		$	728,780
December 31, 2013	451,840			306,423			97,118			5,424			—			860,805
Total assets
December 31, 2014	$	881,906		$	285,695		$	42,857		$	3,844		$	—		$	1,214,302
December 31, 2013	895,388			359,951			108,963			5,424			—			1,369,726

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19. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Years Ended December 31,
	2014			2013		2012
	(in thousands)
Interest, net of capitalized interest	$	152,983		$	254,901	$	154,663
Income taxes, net	(7,051		)	833		(20,682		)

Other significant non-cash transactions are as follows:

	Years Ended December 31,
	2014		2013		2012
	(in thousands)
Working capital related to capital expenditures	$	4,666	$	10,324	$	10,939

20. 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 $1.6 million, $1.8 million and $2.3 million for 2014, 2013 and 2012, 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 2014, 2013 and 2012 was $0.6 million, $0.7 million and $0.7 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 2014, 2013 and 2012 we recognized expense of $3.9 million, $4.0 million and $5.0 million, respectively, for this plan.

21. TRANSACTIONS WITH RELATED PARTIES

As of March 17, 2015, members of the Darden family and entities controlled by them beneficially owned approximately 25% of our outstanding common stock. Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.

During 2013 and 2012, we paid $0.3 million and $0.5 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.

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 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.

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 2014, 2013 and 2012.

Thomas Darden, brother of Glenn Darden and Anne Darden Self, retired as an employee on December 31, 2013, and resigned from the board of directors effective September 1, 2014. During 2014, consulting fee payments of $540,000, office allowance payments of $150,000 and COBRA payments of $39,000 were made to Mr. Darden. Additionally, in accordance with the agreement related to his retirement signed in May 2013 and following the execution and non-revocation of a release agreement satisfactory to us, we paid Mr. Darden a cash bonus of $286,650 and an equity bonus in the form of 72,662 fully vested shares having a grant date fair value equal to $191,100 in March 2014.

119

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. 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.

120

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)
2014 (1)
Operating revenue	$	91,786		$	118,032		$	163,498	$	196,112
Operating income (loss)	(11,054		)	13,536			64,784		18,168
Net income (loss)	(58,833		)	(36,095		)	23,757		(31,929		)
Basic net earnings per share	$	(0.34	)	$	(0.21	)	$	0.13	$	(0.18	)
Diluted net earnings per share	(0.34		)	(0.21		)	0.13		(0.18		)
2013(2) (3) (4)
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		)

⁽¹⁾  Operating income for the fourth quarter of 2014 includes a non-cash property impairment loss of $71.9 million, primarily due to our Fortune Creek gathering system impairment.

⁽²⁾  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.

⁽³⁾  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 $8.0 million arising from a change to the amount of unevaluated properties allocated to TGBR.

⁽⁴⁾  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.

121

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Proved oil and natural 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 2014, 2013 and 2012 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.

122

The changes in our proved reserves for the three years ended December 31, 2014 were as follows:

	Natural Gas (MMcf)						NGL (MBbl)						Oil (MBbl)					Total (MMcfe)
	U.S.		Canada		Total		U.S.		Canada		Total		U.S.		Canada	Total		U.S.		Canada		Total
December 31, 2011	1,828,904		330,631		2,159,535		102,145		11		102,156		3,035		—	3,035		2,459,984		330,697		2,790,681
Revisions (3)	(910,386	)	(33,945	)	(944,331	)	(45,379	)	1		(45,378	)	(479	)	—	(479	)	(1,185,534	)	(33,939	)	(1,219,473	)
Extensions and discoveries (2)	25,858		9		25,867		3,518		—		3,518		345		—	345		49,036		9		49,045
Sales in place (1)	(20,616	)	—		(20,616	)	(42	)	—		(42	)	(85	)	—	(85	)	(21,378	)	—		(21,378	)
Production	(75,712	)	(29,912	)	(105,624	)	(4,069	)	(2	)	(4,071	)	(287	)	—	(287	)	(101,848	)	(29,924	)	(131,772	)
December 31, 2012	848,048		266,783		1,114,831		56,173		10		56,183		2,529		—	2,529		1,200,260		266,843		1,467,103
Revisions (3)	234,835		28,948		263,783		750		—		750		62		—	62		239,707		28,948		268,655
Extensions and discoveries (2)	50,992		9,697		60,689		—		—		—		—		—	—		50,992		9,697		60,689
Sales in place (4)	(257,741	)	—		(257,741	)	(14,333	)	—		(14,333	)	(2,207	)	—	(2,207	)	(356,981	)	—		(356,981	)
Production	(51,684	)	(39,372	)	(91,056	)	(2,856	)	(1	)	(2,857	)	(185	)	—	(185	)	(69,930	)	(39,378	)	(109,308	)
December 31, 2013	824,450		266,056		1,090,506		39,734		9		39,743		199		—	199		1,064,048		266,110		1,330,158
Revisions (3)	(148,359	)	42,941		(105,418	)	(3,675	)	3		(3,672	)	(14	)	—	(14	)	(170,493	)	42,959		(127,534	)
Extensions and discoveries (2)	413		—		413		—		—		—		188		—	188		1,541		—		1,541
Sales in place	—		—		—		—		—		—		(5	)	—	(5	)	(30	)	—		(30	)
Production	(46,027	)	(31,169	)	(77,196	)	(2,105	)	(2	)	(2,107	)	(81	)	—	(81	)	(59,143	)	(31,181	)	(90,324	)
December 31, 2014	630,477		277,828		908,305		33,954		10		33,964		287		—	287		835,923		277,888		1,113,811
Proved developed reserves
December 31, 2012	725,361		266,783		992,144		47,284		10		47,294		2,416		—	2,416		1,023,561		266,843		1,290,404
December 31, 2013	702,147		260,159		962,306		34,603		9		34,612		139		—	139		910,599		260,213		1,170,812
December 31, 2014	619,751		277,828		897,579		33,954		11		33,965		287		—	287		825,197		277,894		1,103,091
Proved undeveloped reserves
December 31, 2012	122,687		—		122,687		8,890		—		8,890		113		—	113		176,705		—		176,705
December 31, 2013	122,303		5,896		128,199		5,131		—		5,131		60		—	60		153,449		5,896		159,345
December 31, 2014	10,726		—		10,726		—		—		—		—		—	—		10,726		—		10,726

123

⁽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.

⁽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:

• 2014 are attributable to our West Texas Asset as we drilled in areas not previously explored;

• 2013 are attributable to our Barnett Shale Asset; and

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

Canadian extensions and discoveries for 2013 and 2012 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 49,712 MMcfe, 419,972 MMcfe and (590,064) MMcfe in 2014, 2013 and 2012, respectively, and changes in non-economic factors of (177,246) MMcfe, (151,615) MMcfe and (629,407) MMcfe in 2014, 2013 and 2012, respectively, including:

• In 2014, we removed proved reserves of (143) Bcfe that we were unable to develop due to constrained liquidity

• 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: (34) Bcfe, (74) Bcfe and (291) Bcfe in 2014, 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 natural gas assets as of December 31, 2014, 2013 and 2012 were as follows:

	U.S.			Canada			Consolidated
	(in thousands)
2014
Proved properties	$	4,650,428		$	1,170,739		$	5,821,167
Unevaluated properties	18,803			—			18,803
Accumulated DD&A	(4,296,953		)	(928,349		)	(5,225,302		)
Net capitalized costs	$	372,278		$	242,390		$	614,668
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

124

Our consolidated capital costs incurred for acquisition, exploration and development activities during each of the three years in the period ended December 31, 2014, were as follows:

	U.S.		Canada		Consolidated
	(in thousands)
2014
Proved acreage	$	—	$	—	$	—
Unproved acreage	21,722		5,519		27,241
Development costs	78,894		22,065		100,959
Exploration costs	63		—		63
Total	$	100,679	$	27,584	$	128,263
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

125

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, 2014, are set forth below:

	U.S.			Canada			Consolidated
	(in thousands)
2014
Natural gas, NGL and oil revenue	$	292,388		$	132,766		$	425,154
Operating expense	146,383			84,219			230,602
Depletion expense	28,567			11,778			40,345
	117,438			36,769			154,207
Income tax expense	41,103			9,266			50,369
Results from producing activities	$	76,335		$	27,503		$	103,838
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	)

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 oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, 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 2014 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:

	At December 31,
	2014		2013		2012
Natural gas – Henry Hub, per MMBtu	$	4.35	$	3.67	$	2.76
Natural gas – AECO, per MMBtu	4.22		2.90		2.35
Oil – WTI Cushing, per Bbl	94.99		97.18		94.71

126

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, including future abandonment 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 oil and natural gas 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, 2014, 2013 and 2012 was as follows:

	U.S.			Canada			Total
				(in thousands)
December 31, 2014
Future revenue	$	3,476,515		$	1,053,509		$	4,530,024
Future production costs	(1,785,208		)	(483,380		)	(2,268,588		)
Future development costs	(71,143		)	(65,703		)	(136,846		)
Future income taxes	(113,119		)	(11,017		)	(124,136		)
Future net cash flows	1,507,045			493,409			2,000,454
10% discount	(817,744		)	(194,640		)	(1,012,384		)
Standardized measure of discounted future cash flows relating to proved reserves	$	689,301		$	298,769		$	988,070
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

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

127

The primary changes in the Standardized Measure for 2014, 2013 and 2012 were as follows:

	Years Ended December 31,
	2014			2013			2012
				(in thousands)
Sales of oil and natural gas net of production costs	$	(164,436	)	$	(147,402	)	$	(149,326	)
Net changes in economic factors	304,602			326,698			(1,362,793		)
Extensions and discoveries	1,455			43,328			27,003
Development costs incurred	60,169			2,302			172,563
Changes in estimated future development costs	91,635			20,766			620,127
Purchase and sale of reserves, net	(24		)	(237,409		)	(20,529		)
Revision of estimates	(103,478		)	121,916			(1,219,609		)
Accretion of discount	75,925			50,821			196,315
Net change in income taxes	(73,637		)	(86,667		)	560,485
Change in timing and other differences	(27,189		)	13,575			156,031
Net increase (decrease)	$	165,022		$	107,928		$	(1,019,733	)

128

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, 2014.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2014.

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, 2014, based on the criteria established in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) (2013 Framework). Based on this assessment, our management has concluded that, as of December 31, 2014, our internal control over financial reporting was effective.

The effectiveness of our internal control over financial reporting as of December 31, 2014, 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.

Changes in Internal Control Over Financial Reporting

We identified 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 as of December 31, 2012 and which continued into December 31, 2013. As of December 31, 2014 this material weakness was sufficiently addressed as we added additional staffing in our tax department and completed a detailed reconciliation of the property, plant and equipment account balances.

Except for the change discussed above, there has been no change in our internal control over financial reporting during the quarter ended December 31, 2014, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

129

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, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 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.

In our opinion, Quicksilver Resources Inc.maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.

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, 2014 and 2013 and the related consolidated statements of income (loss) and comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2014 of Quicksilver Resources Inc. and our report dated March 31, 2015 expressed an unqualified opinion that included an explanatory paragraph regarding Quicksilver Resources Inc.’s ability to continue as a going concern.

/s/ Ernst & Young LLP

Fort Worth, Texas

March 31, 2015

130

ITEM 9B. Other Information

None

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated herein by reference to the descriptions set forth under “Corporate Governance Matters,” “Corporate Governance Matters - Committees of the Board,” “Section 16(a) Beneficial Ownership Reporting Compliance,” and “Corporate Governance Matters - Corporate Governance Principles, Processes and Code of Business Conduct and Ethics” in the proxy statement for our 2015 annual meeting of stockholders (“2015 Proxy Statement”) or will be provided in an amendment on Form 10-K/A. 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.

ITEM 11. Executive Compensation

The information required by this item is incorporated herein by reference to the descriptions set forth under “Executive Compensation,” “Corporate Governance Matters - Compensation Committee Interlocks and Insider Participation,” “Corporate Governance Matters - Director Compensation for 2014” and “Certain Relationships and Related Transactions” in the 2015 Proxy Statement or will be provided in an amendment on Form 10-K/A.

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

The information required by this item is incorporated herein by reference to the descriptions set forth under “Security Ownership of Management and Certain Beneficial Holders” and “Equity Compensation Plan Information” in the 2015 Proxy Statement or will be provided in an amendment on Form 10-K/A.

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

The information required by this item is incorporated herein by reference to the descriptions set forth under “Certain Relationships and Related Transactions” and “Corporate Governance Matters - Independent Directors” in the 2015 Proxy Statement or will be provided in an amendment on Form 10-K/A.

ITEM 14. Principal Accountant Fees and Services

The information required by this item is incorporated herein by reference to the description set forth under “Independent Registered Public Accountants” in the 2015 Proxy Statement or will be provided in an amendment on Form 10-K/A.

131

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.

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.	10-K	001-14837	4.1	3/17/2014
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

132

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
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
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

133

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
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
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

134

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
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
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. Exempt Employee Discretionary Bonus Plan	10-Q	001-14837	10.4	5/12/2014
10.16**	Quicksilver Resources Inc. Amended and Restated Change in Control Retention Incentive Plan	8-K	001-14837	10.9	11/24/2008
10.17**	Quicksilver Resources Inc. Second Amended and Restated Key Employee Change in Control Retention Incentive Plan	8-K	001-14837	10.8	11/24/2008
10.18**	Quicksilver Resources Inc. Amended and Restated Executive Change in Control Retention Incentive Plan	8-K	001-14837	10.7	11/24/2008
10.19**	Form of Director and Officer Indemnification Agreement	10-Q	001-14837	10.2	11/8/2010
10.20**	Letter to Jeff Cook dated July 20, 2012	10-Q	001-14837	10.1	11/8/2012
10.21**	Employment Separation Settlement Agreement, dated August 9, 2012, between Quicksilver Resources Inc. and Jeff Cook	10-K	001-14837	10.24	3/22/2013
10.22**	Agreement, dated as of May 15, 2013 between Quicksilver Resources Inc. and Thomas F. Darden	10-Q	001-14837	10.2	8/8/2013
10.23**	Mutual Release Agreement, dated January 21, 2014, between Quicksilver Resources Inc. and Thomas F. Darden	10-Q	001-14837	10.2	5/12/2014
10.24**	Letter to John C. Regan dated July 15, 2013	10-Q	001-14837	10.1	11/6/2013
10.25**	Letter to Stan G. Page dated July 15, 2013	10-Q	001-14837	10.2	11/6/2013
10.26**	Letters to J. David Rushford dated July 15, 2013	10-Q	001-14837	10.1	5/12/2014
10.27**	Letter to Stan G. Page dated November 18, 2014					†
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/A	001-14837	10.1	9/8/2014

135

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
10.30	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/A	001-14837	10.2	9/8/2014
10.31	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
10.32	Omnibus Amendment No. 2 to Combined Credit Agreements, dated as of August 6, 2012, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein	10-Q	001-14837	10.4	8/9/2012
10.33	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
10.34	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
10.35	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	9/8/2014
10.36	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
10.37	Omnibus Amendment No. 7 to Combined Credit Agreements, dated as of April 25, 2014, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein	10-Q	001-14837	10.5	5/12/2014
10.38	Omnibus Amendment No. 8 to Combined Credit Agreements, dated as of November 7, 2014, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and lenders identified therein	10-Q	001-14837	10.7	11/10/2014
10.39	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	9/8/2014
10.40	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
10.41***	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
10.42***	First Amending Agreement, dated March 13, 2014, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc., Makarios Midstream Inc., Fortune Creek Gathering and Processing Partnership and 0927530 B.C. Unlimited Liability Company	10-Q	001-14837	10.3	5/12/2014
10.43	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
10.44	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

136

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
10.45	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	10.18	2/25/2011
10.46	Second Amendment to Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.	10-Q	001-14837	10.1	11/10/2014
10.47	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
10.48	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	10.15	3/15/2010
10.49	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	10.16	2/25/2011
10.50	Third Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP, Cowtown Gas Processing Partners L.P. and Cowtown Pipeline Partners L.P.	10-Q	001-14837	10.2	11/10/2014
10.51	Fourth Amendment to Sixth Amended and Restated Gas Gathering and Processing Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP, Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P.	10-Q	001-14837	10.3	11/10/2014
10.52	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
10.53	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
10.54	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
10.55	Third Amendment to Amended and Restated Gas Gathering Agreement, dated August 13, 2012, between Quicksilver Resources Inc. and Cowtown Pipeline Partners L.P.	10-Q	001-14837	10.4	11/10/2014
10.56	Fourth Amendment to Amended and Restated Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.	10-Q	001-14837	10.5	11/10/2014
10.57	Fifth Amendment to Amended and Restated Gas Gathering Agreement, dated July 9, 2014, among Quicksilver Resources Inc., TG Barnett Resources LP and Cowtown Pipeline Partners L.P.	10-Q	001-14837	10.6	11/10/2014
21.1	List of subsidiaries of Quicksilver Resources Inc.					†
23.1	Consent of Ernst & Young LLP					†
23.2	Consent of Schlumberger Technology Corporation					†
23.3	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					†

137

		Incorporated by Reference				Filed (†) or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
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.

138

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/    Glenn Darden
			Glenn Darden
Dated:	March 31, 2015		President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on behalf of the registrant and in the capacities and on the dates indicated have signed this report below.

Signature	Title	Date
/s/    W. Yandell Rogers, III	Chairman of the Board; Director	March 31, 2015
W. Yandell Rogers, III
/s/    Glenn Darden	President and Chief Executive Officer	March 31, 2015
Glenn Darden	(Principal Executive Officer); Director
	Senior Vice President - Chief Financial Officer
/s/    Vanessa Gomez LaGatta	and Treasurer	March 31, 2015
Vanessa Gomez LaGatta	(Principal Financial Officer)
/s/    Romy Massey	Chief Accounting Officer	March 31, 2015
Romy Massey	(Principal Accounting Officer)
/s/    Anne Darden Self	Director	March 31, 2015
Anne Darden Self
/s/    W. Byron Dunn	Director	March 31, 2015
W. Byron Dunn
/s/    Michael Y. McGovern	Director	March 31, 2015
Michael Y. McGovern
/s/    Steven M. Morris	Director	March 31, 2015
Steven M. Morris
/s/    Scott M. Pinsonnault	Director	March 31, 2015
Scott M. Pinsonnault
/s/    Mark J. Warner	Director	March 31, 2015
Mark J. Warner

139