10-K

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, 2011

OR

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

For the transition period from                      to                     

Commission file number:    001-14837

QUICKSILVER RESOURCES INC.

(Exact name of registrant as specified in its charter)

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

817-665-5000

(Registrant’s telephone number, including area code)

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

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

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

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

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  þ                 No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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  þ                No   ¨

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  þ                Accelerated filer  ¨                 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, 2011, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $1,747,078,839 based on the closing sale price of $14.76 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 30, 2012
Common Stock, $0.01 par value per share	172,936,914 shares

DOCUMENTS INCORPORATED BY REFERENCE

Document	Parts Into Which Incorporated
Proxy Statement for the Registrant’s May 16, 2012 Annual Meeting of Stockholders	Part III

DEFINITIONS

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

“ABR” means alternate base rate

“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

“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

“MBbl” or “MBbls” means thousand barrels

“MBoe” means thousand Bbl of oil equivalents

“MMBbls” means million barrels

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

“MMBtud” means MMBtu per day

“Mcf” means thousand cubic feet

“Mcfe” means Mcf natural gas equivalents, 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 equivalents

“MMcfed” means MMcfe per day

“NGL” or “NGLs” means natural gas liquids

“NYMEX” means New York Mercantile Exchange

“OCI” means other comprehensive income

“Oil” includes crude oil and condensate

“RSU” means restricted stock unit

“Tcfe” means trillion cubic feet of natural gas equivalents

COMMONLY USED TERMS

Other commonly used terms and abbreviations include:

“2007 Senior Secured Credit Facility” means collectively our U.S. senior secured revolving credit facility and our Canadian senior secured revolving credit facility, each dated as of February 9, 2007, which were terminated September 6, 2011 and replaced at that time by the Initial U.S. Credit Facility and the Initial Canadian Credit Facility

“Alliance Acquisition” means the 2008 purchase of natural gas leasehold, royalty interests and midstream assets in the Alliance airport area of the Barnett Shale

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

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

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

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

“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

2

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

“CMLP” means Crestwood Midstream Partners LP

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

“Crestwood” means Crestwood Holdings LLC

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

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

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

“Eni Transaction” means the 2009 conveyance of a 27.5% interest in our Alliance Asset

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

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

“Fortune Creek” means Fortune Creek Gathering and Processing Partnership, a midstream partnership formed in December 2011 with KKR dedicated to the construction and operation of natural gas midstream services within Horn River

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

“Gas Purchase Commitment” means the commitment pursuant to the Eni Transaction to purchase the Eni Production at a fixed price and which expired on December 31, 2010

“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

“Initial Canadian Credit Facility” means our initial Canadian senior secured revolving credit facility, dated as of September 6, 2011, which was amended and restated by the Amended and Restated Canadian Credit Facility on December 22, 2011

“Initial U.S. Credit Facility” means our initial U.S. senior secured revolving credit facility, dated as of September 6, 2011, which was amended and restated by the Amended and Restated U.S. Credit Facility on December 22, 2011

“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”

“KGS Credit Agreement” means the KGS senior secured revolving credit facility

“KGS Secondary Offering” means the public offering of 4,000,000 KGS common units in 2009 and the underwriters’ purchase of an additional 549,200 KGS common units in 2010

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

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

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

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

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

“OSHA” means Occupational Safety & Health Administration

“Sandwash Asset” means our operations and our assets in the Sandwash basin located in Colorado and southern Wyoming

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

“Senior Secured Second Lien Facility” means our $700 million five-year senior secured second lien facility which we entered into pursuant to the Alliance Transaction that we subsequently repaid and terminated in June 2009

“VIE” means variable interest entity

“West Texas Asset” means our operations and our assets in the Midland and Delaware basins in West Texas prospective in the Bone Springs and Wolfcamp formations, principally concentrated in four areas: Jeff Davis and Reeves Counties, Upton and Crockett Counties, Pecos County and Presidio County

3

INDEX TO ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2011

PART I
ITEM 1.	Business	6
ITEM 1A.	Risk Factors	22
ITEM 1B.	Unresolved Staff Comments	34
ITEM 2.	Properties	34
ITEM 3.	Legal Proceedings	34
ITEM 4.	Mine Safety Disclosures	34
PART II
ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
ITEM 6.	Selected Financial Data	37
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk	62
ITEM 8.	Financial Statements and Supplementary Data	64
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	116
ITEM 9A.	Controls and Procedures	116
ITEM 9B.	Other Information	119
PART III
ITEM 10.	Directors, Executive Officers and Corporate Governance	119
ITEM 11.	Executive Compensation	119
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	119
ITEM 13.	Certain Relationships and Related Transactions, and Director Independence	119
ITEM 14.	Principal Accountant Fees and Services	119
PART IV
ITEM 15.	Exhibits and Financial Statement Schedules	120
	Signatures	130

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

4

Forward-Looking Information

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

Ÿ changes in general economic conditions;

Ÿ fluctuations in natural gas, NGL and oil prices;

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

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

Ÿ effects of hedging natural gas, NGL and oil prices;

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

Ÿ competitive conditions in our industry;

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

Ÿ changes in the availability and cost of capital;

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

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

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

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

Ÿ the effects of existing or future litigation;

Ÿ failure or delays in completing Quicksilver’s proposed initial public offering of common units representing limited partner interests in a master limited partnership holding portions of our Barnett Shale Asset; and

Ÿ additional factors described elsewhere in this Annual Report.

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

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

5

PART I

ITEM 1.     Business

GENERAL

We are an independent oil and gas company engaged primarily in the acquisition, exploration, development and production of onshore oil and gas in North America based in Fort Worth, Texas. We focus primarily on unconventional reservoirs where hydrocarbons may be found in challenging geological conditions, such as fractured shales, coalbeds and tight sands. Our producing oil and gas properties in the United States are principally located in Texas, Colorado, Wyoming and Montana, and in Canada in Alberta and British Columbia. We had total proved reserves of approximately 2.8 Tcfe at December 31, 2011. Our three core areas include:

Ÿ Barnett Shale;

Ÿ Horn River; and

Ÿ Horseshoe Canyon.

In the Horn River basin, we are in transition from the exploratory phase to a developmental focus, particularly in the southern portion of our acreage. We also have significant exploration opportunities in North America, most notably in the following regions:

Ÿ Midland and Delaware basins in West Texas;

Ÿ Sandwash basin in Northwest Colorado; and

Ÿ Bakken formation in Montana and Wyoming.

In addition, our new ventures team actively studies other basins in North America which may yield future exploration opportunities.

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

FORMATION AND DEVELOPMENT OF BUSINESS

We were organized as a Delaware corporation in 1997 and became a public company in 1999. As of February 15, 2012, members of the Darden family and entities controlled by them, beneficially owned more than 30% of our outstanding common stock.

STRATEGIC TRANSACTIONS IN THE LAST FIVE YEARS

On February 10, 2012, we filed a Form S-1 with the SEC to begin the registration and sale of limited partnership interests in a master limited partnership holding certain of our mature properties in our Barnett Shale Asset. We expect this registration statement to become effective in 2012.

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 to the partnership our existing 20-mile, 20-inch gathering line and compression facilities and 10-year contracts for gas deliveries into those facilities in consideration for $125 million and a 50% interest in the partnership. The creation of this partnership is strategic to the continued development of our Horn River Asset as it is expected to reduce the cost of processing and transporting gas to sales markets.

In October 2010, we sold all of our interests in KGS to Crestwood. Crestwood paid $700 million in cash and assumed debt of $58 million and we recognized a gain of $494 million. In February 2012, we received an additional $41 million in consideration of an earn-out on these assets and will recognize an additional gain in the first quarter of 2012. We believe the sale of these midstream assets allowed us to better focus on the development of our natural gas properties while redeploying the associated capital into projects with higher expected returns.

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 portions of our BBEP Units. At December 31, 2011, we no longer held any BBEP Units.

6

In January 2010, we completed the sale of certain of our midstream assets to KGS for $95 million. KGS funded the purchase primarily with proceeds from the KGS Secondary Offering which reduced our ownership in KGS from 73% to 61%.

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

In December 2008, we sold the gathering system in our Lake Arlington Asset to KGS for $42 million.

In August 2008, we completed the $1.3 billion Alliance Acquisition that consisted of producing and non-producing leasehold, royalty and midstream assets in the Barnett Shale. Consideration in the transaction was $1 billion in cash and $262 million of our common stock.

In 2007, we sold all of our oil and gas properties in Michigan, Indiana and Kentucky to BBEP for $750 million in cash and 21.3 million BBEP Units, valued at $724 million at the closing of the transaction, resulting in total proceeds at closing of $1.474 billion.

BUSINESS STRATEGY

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

Focus on core areas of repeatable, low-risk development:  We believe that development activity in areas we have acquired a contiguous acreage position allows us to efficiently deploy our resources, manage our costs and leverage our technical expertise. Additionally, we endeavor to acquire acreage positions that are not only contiguous from a land perspectives, which is more efficient for drilling, but is also contiguous from a resource perspective, which will create a more economic asset for us.

Pursue disciplined organic growth opportunities:  We typically plan to spend 10% of our capital program on high-potential, longer cycle-time exploration projects to replenish our inventory of development projects for the future. Through our activities in multiple unconventional resource basins, we have significant expertise and a demonstrated history of identifying, developing and producing fractured shales, coal seams and tight sands. We are focused on identifying and evaluating additional opportunities that allow us to apply this expertise and experience to the development and operation of other unconventional reservoirs in North America. We believe our core strength lies in our ability to identify and acquire large resource targets at low cost per acre. When we have secured an acreage position, we then drill resource assessment wells and validation wells to determine the size and commerciality of the project. Once the project is validated, we build infrastructure to secure affordable gathering, processing, transportation, and operating costs. Finally, we move the project to the full development stage. We have historically monetized mature assets to provide financial flexibility for future projects. In 2012, we will continue to focus our development activities in the Barnett Shale. In Horn River, where we expect to convert our exploratory licenses covering more than 130,000 net prospective acres to leases with an expected 10-year term, we are in transition from the exploration phase to full development. Our exploration activities will be focused in the Sandwash basin, where we hold approximately 260,000 net acres, and in the Midland and Delaware basins of West Texas, where we hold approximately 155,000 net acres.

Enhance profitability through control and marketing of our equity natural gas and oil:  We generally seek to maximize profitability by exercising control over the delivery of our production to distribution pipelines owned by third parties. We seek to achieve this by continuing to improve upon and add to our gathering and processing infrastructure during the infrastructure’s development phase. We believe this allows us to better manage the physical movement of our production and the efficiency of our operations by decreasing dependency on third parties. We also monitor the spot markets for commodities and seek to sell our uncommitted production into the most attractive markets. Our partnership with KKR established an area of mutual interest that covers approximately 30 million potential acres in the Horn River, Cordova, and Liard basins in British Columbia and

7

Northwest Territories for potential midstream expansion. We expect this partnership will reduce our cost to process and transport our gas to sales markets by 44% as compared to other current alternatives. The backbone of the midstream infrastructure is in place for our Barnett Shale Asset and Horseshoe Canyon Asset.

Maintain a prudent capital structure to ensure financial flexibility:  We believe that a flexible financial structure enables us to capitalize on opportunities and to limit our financial risk. We believe our internally-generated cash flows supplemented with asset monetization, joint ventures and borrowings under our Combined Credit Agreements provide us with the financial flexibility to pursue our acquisition, development and exploration programs. In order to increase the predictability of the prices we receive for our natural gas and NGL production, we hedge the commodity price of a substantial portion of our expected production with financial derivative instruments. We regularly review the credit-worthiness of our hedging counterparties, and our hedging program is spread among numerous financial institutions, all of whom participated in our credit facilities at the time of entering into the hedge. We have entered into long-term hedges to provide predictability over longer periods.

BUSINESS STRENGTHS

High-quality asset base with long reserve life:  Our proved reserves totaled approximately 2.8 Tcfe as of December 31, 2011 of which 69% were developed. Our Barnett Shale Asset has approximately 88% of our proved reserves and approximately 12% are located in our Horseshoe Canyon Asset and our Horn River Asset. These areas have a history of proven well performance and have established and emerging infrastructure to permit delivery of our production to sales markets. We believe our reserves are characterized by long lives and predictable well production profiles. Based on our annualized fourth-quarter 2011 average production from all of our properties, our implied reserve life (proved reserves divided by annualized fourth-quarter 2011 production) was 18.4 years and our implied proved developed reserve life (proved developed reserves divided by annualized fourth-quarter 2011 production) was 12.7 years. As of December 31, 2011, almost 98% of our proved reserves were attributable to properties we operate.

Multi-year inventory of developmental drilling projects:  As of December 31, 2011, we owned leases covering more than 580,000 net acres in our three core areas, of which 82% were classified as held by production. Within our Barnett Shale Asset alone, we have identified drilling locations that provide us greater than a 10-year inventory of drilling locations at the 2012 anticipated drilling rate. Our drilling success rate has averaged more than 99% during the past three years. We use 3D seismic data to enhance our ongoing drilling and development efforts as well as to identify new targets in both new and existing fields, and our seismic library covers more than 90% of our acreage in our Barnett Shale Asset.

We have also identified exploratory opportunities that provide meaningful exposure to additional oil and gas resources. As of December 31, 2011, we have successfully drilled 10 gas wells and completed four gas wells in our Horn River Asset, and 80% of our licensed acreage has been validated. After completing our planned 2012 drilling in our Horn River Asset, we expect to be in a position to convert 98% of our licenses to 10-year leases. Our total proved reserves in our Horn River Asset are 99.3 Bcfe.

Proven record of organic growth in reserves and production:  During the past three years, our proved reserves have grown 26% as we added 1.1 Tcfe of proved reserves from organic development activities. We supplemented this activity with acquisitions in the Barnett Shale and Horseshoe Canyon, which combined, total 147.3 Bcf of acquired proved reserves. We also sold 121 Bcf of proved reserves in the Eni Transaction in 2009. We have organically replaced 274% of our production during the three years ended December 31, 2011. Our growth has resulted from our ability to acquire attractive undeveloped acreage and to apply our technical expertise to find, develop and produce reserves. In recent years, we have demonstrated this ability through our accomplishments in our three core areas. We believe our current acreage position provides opportunities and flexibility to continue our organic growth of reserves and production.

Extensive technical experience and familiarity with developing and operating Barnett Shale properties and other unconventional resources.  We are one of the five largest producers in the Barnett Shale. The development of the Barnett Shale helped pioneer unconventional shale development, and the Barnett Shale currently produces over 5.0 Bcf of natural gas per day with over 15,000 wells drilled since 2003, according to the Railroad

8

Commission of Texas. Our staff of petroleum professionals, many of whom have significant engineering, geologic and other expertise which allows us to be competitive in unconventional resource plays. We intend to utilize these resources to optimize our recovery of reserves and to enhance the value of our assets.

Experienced management and technical team:  Our CEO, Glenn Darden, and our Chairman, Thomas F. Darden, are founding members of our company and have held executive positions with us since our formation. They and our experienced executive management team have successfully implemented a disciplined growth strategy with a primary focus on net asset value growth through the development of unconventional reservoirs. Messrs. Glenn and Thomas Darden have been in the oil and natural gas business their entire professional careers and each has extensive experience in the acquisition, exploration, development, and production of oil and gas properties, as well as experience in the integration and management of energy assets in a reliable and cost-effective manner. Our executive management team is supported by a core team of technical, operational and financial managers who have significant industry experience, including experience in drilling and completing horizontal wells in unconventional reservoirs and in evaluating and completing strategic transactions.

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, 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 are currently developing gathering and processing facilities in our Horn River Asset 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, 2011, we had total proved reserves of approximately 2.8 Tcfe, of which 77% is natural gas and 22% is NGLs. For 2011, we had total production of 150.5 Bcfe which averages to 413 MMcfed. In the last five years, we have grown our reserves and production at an approximate compound annual growth rate of 12% and 14%, respectively.

We believe the development of our leasehold interests in our core areas, and our exploration activities in the Sandwash basin and in West Texas will give us the flexibility over the next several years to grow reserves and production economically. We may also pursue acquisitions of additional interests where economically feasible, which could allow for further capitalization on our proven expertise in unconventional resource plays. Details of our 2012 capital program and our projected production levels can be found in Item 7 of this Annual Report.

Barnett Shale

Over 88% of our total proved reserves and over 81.6% of our total average daily production in 2011 were in our Barnett Shale Asset. In the fourth quarter of 2011, our net production from our wells in our Barnett Shale Asset was 338.0 MMcfed. We expect 74% of our 2012 production to come from our Barnett Shale Asset.

At December 31, 2011, we had approximately 140,000 net acres in the Barnett Shale of which approximately 55% is currently held by production. Much of our acreage in Hood and Somervell counties contains high-Btu natural gas. NGLs are extracted through midstream facilities that we constructed and are now owned by CMLP. In the current pricing environment, where NGLs trade at a premium to methane, we are able to increase our revenue per Mcf of natural gas production by extracting and separately selling NGLs. In 2011, sales of NGLs represented 22% of our Barnett Shale Asset production.

During 2011, we drilled 57 (49.9 net) wells and completed 128 (113.2 net) wells in our Barnett Shale Asset primarily from multi-well drilling pads. On these multi-well pads, all the wells are drilled prior to initiating completion activities. At December 31, 2011, we had drilled a total of 1,030 (859.4 net) wells in our Barnett

9

Shale Asset since we began exploration and development operations in 2003. At December 31, 2011, we had two drilling rigs operating in our Barnett Shale Asset, but expect to utilize an average of one rig in the high-liquid acreage of Hood and Somervell Counties for the remainder of 2012.

West Texas

During 2011, we continued to build an oil prospective acreage position in the Bone Springs and Wolfcamp formations in the Midland and Delaware basins in West Texas. We now hold leases totaling 155,000 acres across Reeves, Pecos, Jeff Davis, Upton, Crockett and Presidio Counties. We plan to commence drilling operations in this area late in the first quarter of 2012.

Rockies

Our Rocky Mountain assets are located in the Bakken formation in Montana and Wyoming and the Niobrara formation in the Sandwash basin in Colorado. We have approximately 175,000 net acres in the Bakken formation, 68% of which is held by production. At December 31, 2011, proved reserves from these properties were 16.7 Bcfe, of which 92% was oil or NGLs.

We also hold approximately 260,000 net acres in the Sandwash basin where we are currently conducting exploratory activities and have two producing gas wells. During 2011, we drilled seven vertical wells followed by our first horizontal well in the fourth quarter of 2011, with initial production results of up to 500 Bbld produced from a 3,000 foot lateral. We plan to drill an additional four to seven horizontal wells in 2012, and plan to move the program to the development stage in 2013, pending positive well results. Total proved reserves in our Sandwash Asset are 0.3 Bcfe at December 31, 2011.

Daily production from all our properties in the Rocky Mountain region averaged 3.3 MMcfed for 2011.

Horseshoe Canyon

At December 31, 2011, our Horseshoe Canyon Asset proved reserves were 231.4 Bcfe, all of which was natural gas. Production averaged 58.5 MMcfed in our Horseshoe Canyon Asset, representing 14.2% of our total 2011 production.

In our Horseshoe Canyon Asset, as of December 31, 2011, we had 49,458 (36,929 net) undeveloped acres. During 2011 we spent $3.0 million for drilling and completion, largely funded by cash flows from operations from our Horseshoe Canyon Asset. Similar to 2011, we expect to completely fund 2012 drilling and completion activities in this asset with operating cash flows.

Horn River

We also have exploratory licenses which we expect to convert to leases in more than 130,000 net acres in Horn River. During 2011, we spent $95.0 million for drilling and completion costs on our Horn River Asset where we drilled and cased 10 wells and completed one well. As of December 31, 2011, we had four wells producing and 10 wells drilled and awaiting completion in our Horn River Asset, of which we expect eight wells to come online in 2012. Our production requires gathering, processing and transportation, for which we believe we have ample capacity to meet our needs for the foreseeable future. Our total proved reserves in our Horn River Asset were 99.3 Bcfe as of December 31, 2011, all of which was natural gas.

Quicksilver entered into agreements with NGTL whereby NGTL has agreed to construct and own a 60-mile, 36” pipeline extension from its Alberta system to our Fortune Creek Meter Station in order to transport Horn River natural gas to sales markets. We expect this extension will provide a low-cost transportation alternative to existing infrastructure, and will deliver gas to sales hubs, some of which historically have traded at a premium to Station 2 pricing where most Horn River basin gas is currently sold. NGTL expects to begin right-of-way clearing in January 2013, with construction expected to start at the end of 2013. The pipeline is expected to be in-service by June 2014. We have entered into agreements with NGTL to deliver up to 1 Tcf of production over a 10-year period starting in 2014. Our obligation may be reduced by delivery of volumes from third-party producers. We are further required to deliver pipeline-quality gas, which we plan to treat in facilities constructed by Fortune Creek.

10

OIL AND NATURAL GAS RESERVES

Our proved reserve estimates and related disclosures for 2011, 2010 and 2009 are presented in compliance with the SEC rule. The information with respect to our proved reserves and related disclosures have been prepared by Schlumberger Data & Consulting 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 the SEC reserve guidelines is the primary responsibility of our reservoir engineering team. We require that proved reserve estimates be made by qualified 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 Chris Mundy, Vice President—Engineering, is responsible for the preparation and maintenance of our engineering data and review of our proved reserve estimates with Schlumberger and LaRoche. Mr. Mundy has over 15 years of experience in the oil and gas industry. Mr. Mundy is licensed as a Professional Engineer, registered with the Association of Professional Engineers, Geologists and Geophysicists of Alberta and is a member of the Society of Petroleum Engineers. Mr. Mundy earned a Bachelor of Applied Science degree in civil engineering from the University of Waterloo, Ontario, Canada. The reservoir engineering team reports directly to him and is otherwise independent from management for our operating areas. Throughout the year, the reservoir engineering team analyzes the performance of producing properties for each operating area, identifies proved reserve additions and revisions and prepares internal proved reserve estimates. In addition, the team is responsible for maintaining all reserve engineering data. Integrity of reserve engineering data is enhanced by restricting full access to only the members of our reservoir engineering team. Limited other personnel have read-only access with no ability to modify reserve engineering data.

The technical person at Schlumberger responsible for overseeing the preparation of our estimates of proved reserves is Charles M. Boyer II, PG, CPG. Mr. Boyer is licensed in the Commonwealth of Pennsylvania and has over 30 years of geologic and engineering experience in the oil and gas industry. Mr. Boyer earned a Bachelor of Science degree in geological sciences from The Pennsylvania State University in University Park and completed graduate studies in mining and petroleum engineering at the University of Pittsburgh and The Pennsylvania State University. The technical persons at LaRoche responsible for preparing our estimates of 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. 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 40 years of engineering experience in the oil and gas industry. Mr. Daniel earned a Bachelor of Science degree in Petroleum Engineering from University of Texas and has prepared reserves estimates for his employers throughout his career. He has prepared and overseen preparation of reports for public filings for LaRoche for the past 15 years. 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. Mundy and the other members of our executive management team.

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

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

11

repeatability. Proved developed reserves are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are expected to be recovered from new wells on undrilled acreage. Proved reserves for undrilled wells are estimated only where it can be demonstrated that there is continuity of production from the existing productive formation. To achieve reasonable certainty of our proved reserve estimates, our reservoir engineering team assumes continued use of technologies with demonstrated success of yielding expected results, including the use of drilling results, well performance, well logs, seismic data, geologic maps, well stimulation techniques, well test data, and reservoir simulation modeling.

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

The following table summarizes our proved reserves in accordance with the rule established by the SEC.

	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,
	2011		2010		2009		2011		2010		2009		2011		2010		2009
Natural gas (MMcf)
U.S.		1,244,187		1,312,777		1,044,140		584,717		628,946		511,894		1,828,904		1,941,723		1,556,034
Canada		299,371		242,941		223,300		31,260		22,947		29,753		330,631		265,888		253,053
Total		1,543,558		1,555,718		1,267,440		615,977		651,893		541,647		2,159,535		2,207,611		1,809,087
NGL (MBbl)
U.S.		60,902		64,908		60,997		41,243		47,536		37,264		102,145		112,444		98,261
Canada		11		12		13		-		-		-		11		12		13
Total		60,913		64,920		61,010		41,243		47,536		37,264		102,156		112,456		98,274
Oil (MBbl)
U.S.		2,545		2,775		2,467		490		533		392		3,035		3,308		2,859
Canada		-		-		-		-		-		-		-		-		-
Total		2,545		2,775		2,467		490		533		392		3,035		3,308		2,859
Total (MMcfe)
U.S.		1,624,866		1,718,875		1,424,924		835,118		917,357		737,830		2,459,984		2,636,232		2,162,754
Canada		299,437		243,017		223,378		31,260		22,947		29,753		330,697		265,964		253,131
Total		1,924,303		1,961,892		1,648,302		866,378		940,304		767,583		2,790,681		2,902,196		2,415,885

	Years Ended December 31,
	2011		2010		2009
Representative prices for reserve estimation purposes:
Natural gas – Henry Hub, per MMBtu	$	4.12	$	4.38	$	3.87
Natural gas – AECO, per MMBtu		3.65		4.08		3.76
NGL – Mont Belvieu, Texas, per Bbl		47.16		37.56		24.94
Oil – WTI Cushing, per Bbl		95.71		79.43		61.18
Standardized measure of discounted future net cash flows (1) (in millions)	$	1,734.9	$	1,786.4	$	1,182.7

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

12

PROVED UNDEVELOPED RESERVES

Our 2011 drilling and completion activities related to our proved undeveloped locations as of December 31, 2010 were as follows:

	For the Year Ended December 31, 2011
	Drilled				Completed				Producing
	Gross		Net		Gross		Net		Gross		Net
Barnett Shale		49.0		41.9		32.0		27.1		32.0		27.1
Horseshoe Canyon		-		-		1.0		0.1		1.0		0.1
Total		49.0		41.9		33.0		27.2		33.0		27.2

Costs incurred in 2011 relating to the drilling and completion activities related to our proved undeveloped locations as of December 31, 2010 were $112.9 million.

Our gross capital costs for a Barnett Shale Asset well from preparation of the multi-well drilling pad through the initiation of production have an estimated median of $2.8 million depending on factors such as the area, the depth and lateral length of each well, number of stages of fracture stimulation and its distance to central facilities. On each multi-well drilling pad, we drill all the wells prior to initiation of completion activities. As a result, we maintain an inventory of drilled wells awaiting completion.

In our Horseshoe Canyon Asset, the gross capital costs for a typical well from pre-drilling preparation through the initiation of production generally range from $0.25 million to $0.35 million depending upon the number of coal seams and depth and distance to a gathering system. As our drilling and completion operations are limited by the restriction of the movement of rigs and other equipment due to wet weather and spring thaw, we expect to maintain an inventory of drilled wells awaiting completion and completed wells awaiting tie-in to sales lines.

In our Horn River Asset, we are in transition from the exploratory phase to a developmental focus, particularly in the southern portion of our acreage. Costs are and have been higher than we anticipate them to be in full development. In full development, we expect gross capital costs per well, from preparation of the multi-well drilling pad through the initiation of production, will generally range from $12 million to $14 million depending on factors such as the depth and lateral length of each well, number of stages of fracture stimulation and its distance to central facilities.

As of December 31, 2011, we had total proved undeveloped reserves of 866.4 Bcfe primarily comprised of 835.1 Bcfe in our Barnett Shale Asset on 341 well locations, 8.3 Bcfe in our Horseshoe Canyon Asset on 50 well locations, and 23 Bcfe in our Horn River Asset on two well locations. All of the 393 well locations are scheduled for development before the end of 2016.

Regionally, we estimate that our proved undeveloped well locations will be developed on the following timeline:

	Barnett Shale		Horseshoe Canyon		Horn River		Total
2012		44		1		2		47
2013		44		27		-		71
2014		126		17		-		143
2015		70		2		-		72
2016		57		3		-		60
Total		341		50		2		393

During 2012, we expect to spend $224.0 million to drill, complete and tie-in wells on proved locations. Estimated future development costs on proved locations as of December 31, 2011 are projected to be $154.1 million for 2013, $363.5 million for 2014, $211.1 million for 2015, and $191.5 million for 2016.

13

At December 31, 2011, none of our inventory of proved undeveloped drilling locations has been recognized as proved reserves for five years or longer. Currently, we anticipate that our proved undeveloped reserves will be developed within five years.

Proved undeveloped reserves in our Barnett Shale Asset decreased 9% from 2010 because a large portion of the 2011 capital program was directed to developing our proved undeveloped inventory.

DEVELOPMENT AND EXPLORATION ACTIVITIES AT YEAR END

At December 31, 2011, we had two drilling rigs operating in our Barnett Shale Asset, with both rigs operating on proved undeveloped locations. Additionally, completion work was in progress on nine (nine net) proved wells in our Barnett Shale Asset, with 58 (46.3 net) wells awaiting completion or tie-in to sales lines.

Two drilling rigs were operating on unproved locations in our Horn River Asset at December 31, 2011, with 10 (10 net) wells drilled and awaiting completion. Additionally, 145 (91.7 net) wells in our Horseshoe Canyon Asset were awaiting completion or tie-in to sales lines at December 31, 2011. Eight (eight net) wells in our Horn River Asset will be completed in 2012. The remaining wells in our Horseshoe Canyon Asset were drilled on leases set to expire in the near term and have not been completed pending resolution of potential title defects.

DRILLING ACTIVITY

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

	Years Ended December 31,
	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Development:
U.S.
Productive (1)		61.0		49.6		97.0		80.5		154.0		93.2
Non-productive		-		-		2.0		1.5		-		-
Canada
Productive (2)		18.0		14.9		18.0		9.9		141.0		36.1
Non-productive		-		-		-		-		-		-
Total		79.0		64.5		117.0		91.9		295.0		129.3
Exploratory:
U.S.
Productive		8.0		6.0		-		-		4.0		4.0
Non-productive		-		-		-		-		-		-
Canada
Productive		4.0		4.0		2.0		2.0		2.0		2.0
Non-productive		-		-		-		-		-		-
Total		12.0		10.0		2.0		2.0		6.0		6.0
Total:
Productive		91.0		74.5		117.0		92.4		301.0		135.3
Non-productive		-		-		2.0		1.5		-		-
Total		91.0		74.5		119.0		93.9		301.0		135.3

⁽¹⁾ U.S. development drilling includes non-operated drilling of 4 wells (0.0 net), 3 wells (0.4 net) and 37 wells (3.0 net) for 2011, 2010 and 2009, respectively.

14

⁽²⁾  Canadian development drilling includes non-operated drilling of 2 wells (1.0 net), 7 wells (0.4 net) and 88 wells (8.1 net) for 2011, 2010 and 2009, respectively.

VOLUME, SALES PRICES AND OIL AND GAS PRODUCTION EXPENSE

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

DELIVERY COMMITMENTS AND PURCHASERS OF NATURAL GAS, NGLs AND OIL

We have contracts with third parties that require we provide minimum daily natural gas or NGL volume for gathering, fractionation and transportation, as determined on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. We will utilize production volumes from our wells plus royalty volumes we control and other third-party volumes towards meeting our commitments below. Any shortfall we will fund with cash, however this is not expected to be material in the near-term.

Our prospective obligations under existing agreements are summarized below:

	Total		2012		2013		2014		2015		2016		Thereafter
							(In Mmcf)
Gathering
Barnett Shale		38,800		9,150		9,125		9,125		9,125		2,275		-
Horn River		857,699		36,882		53,027		84,845		106,068		195,838		381,039
Processing and Fractionation
Barnett Shale		78,948		39,528		39,420		-		-		-		-
Horn River		130,014		13,400		20,400		22,227		22,227		22,227		29,533
Transportation
Barnett Shale		487,566		113,396		95,207		75,167		73,307		66,493		63,996
Horseshoe Canyon		25,889		17,005		8,728		52		52		52		-
Horn River		1,085,754		7,693		17,262		48,049		57,183		57,340		898,227

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 $0.70 to $0.83 per Mcf of gathered volume but are subject to annual inflationary increases. Processing fees are fixed at $0.67 per Mcf, but 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 2011, Targa Liquids Marketing and Trade and Lone Star NGL Product Services LLC, the largest purchasers of our production, accounted for 15% and 11%, respectively, of our cash collected for natural gas, NGL and oils sales.

15

ACQUISITION, EXPLORATION AND DEVELOPMENT CAPITAL EXPENDITURES

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

	U.S.		Canada		Consolidated
	(In thousands)
2011
Proved acreage	$	-	$	-	$	-
Unproved acreage		145,099		-		145,099
Development costs		304,373		90,361		394,734
Exploration costs		37,673		41,338		79,011
Total	$	487,145	$	131,699	$	618,844
2010
Proved acreage	$	125,647	$	19,271	$	144,918
Unproved acreage		44,271		827		45,098
Development costs		378,056		14,182		392,238
Exploration costs		9,385		57,896		67,281
Total	$	557,359	$	92,176	$	649,535
2009
Proved acreage	$	118	$	-	$	118
Unproved acreage		11,300		2,658		13,958
Development costs		341,658		24,179		365,837
Exploration costs		32,798		59,402		92,200
Total	$	385,874	$	86,239	$	472,113

PRODUCTIVE OIL AND GAS WELLS

The following table summarizes productive wells:

	As of December 31, 2011
	Natural Gas				Oil
	Gross		Net		Gross		Net
U.S.		1,091.0		907.4		198.0		194.0
Canada		2,869.0		1,391.6		4.0		1.1
Total		3,960.0		2,299.0		202.0		195.1

OIL AND GAS ACREAGE

Our principal natural gas and oil properties consist of non-producing and producing oil and gas leases and mineral acreage, including reserves of natural gas and oil in place. Developed acres are defined as acreage allocated to wells that are producing or capable of producing. Undeveloped acres are acres on which wells are not to a point that would permit the production of commercial reserves or acreage which was 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.

16

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

	As of December 31, 2011
	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net
Barnett Shale		85,110		75,120		87,804		65,025
West Texas		2,432		2,233		221,456		150,882
Sandwash Basin		9,923		5,969		380,817		253,197
Southern Alberta Basin		109,783		102,583		79,401		64,492
U.S.		207,248		185,905		769,478		533,596
Horseshoe Canyon		467,380		293,879		49,458		36,929
Horn River Basin		11,634		11,016		130,146		119,453
Canada		479,014		304,895		179,604		156,382
Total		686,262		490,800		949,082		689,978

The following table summarizes information regarding the total number of net undeveloped acres as of December 31, 2011:

			2012 Expirations				2013 Expirations				2014 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		65,025		11,723		80		7,021		225		5,246		364
West Texas		150,882		6,205		-		5,914		420		52,744		30,207
Rockies		317,689		29,331		1,674		81,386		12,453		72,141		43,829
Canada		156,382		84,087		1,121		6,175		160		4,289		-
Total		689,978		131,346		2,875		100,496		13,258		134,420		74,400

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

COMPETITION

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

GOVERNMENTAL REGULATION

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

17

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 and other agencies require, among other matters, that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We are also subject to safety regulations which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.

ENVIRONMENTAL MATTERS

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

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

Environmental laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. For example, various federal, state, provincial and local initiatives have been implemented or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. In particular, the EPA has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of wastewater from certain gas production operations. In addition, certain states in which we operate, including Colorado, Montana, Texas and Wyoming, 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. In particular, in December 2011, the Railroad Commission of Texas and the Colorado Oil and Gas Conservation Commission finalized regulations requiring public disclosure of chemicals in fluids used in the hydraulic fracturing process. Similar regulations exist in British Columbia. Local ordinances or other regulations also may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular, and may require baseline water well sampling. 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 emissions and water quality concerns, which increased scrutiny could lead to heightened enforcement of existing regulations as well as the imposition of new air emission measures. In July 2011, the EPA proposed requirements for sulfur dioxide, volatile organic compound and hazardous air pollutant air emissions from oil and gas operations, including standards for wells that are hydraulically fractured. In addition, from time to time, initiatives are proposed that could further regulate certain exploration and production by-products as hazardous wastes and subject them to more stringent requirements. Any current or future air 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.

18

GHG emission regulation is also becoming more stringent. We are currently required to implement a GHG recordkeeping and reporting program due to issuance of the EPA’s subpart W regulation which will require significant effort to quantify sources at all of our production sites, and beginning in 2012, we will be required to report our GHG emissions from operations. Our operations in British Columbia are subject to similar GHG reporting requirements. In addition, regulatory authorities are considering, or have developed, energy or emission measures to reduce GHG emissions. For example, the EPA has begun regulating GHG emissions from stationary sources pursuant to the Prevention of Significant Deterioration and Title V provisions of the federal Clean Air Act, as a result of which we might be required to obtain permits to construct, modify or operate facilities on account of, and implement emission control measures for, our GHG emissions. In British Columbia, we are subject to a carbon tax on our purchase or use of virtually all carbon-based fuels (including natural gas), which is payable at the time such fuel is purchased or otherwise used. Any limitation, or further regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could restrict our operations and subject us to significant costs, including those relating to emission credits, pollution control equipment, monitoring and reporting. Although there is still significant uncertainty surrounding the scope, timing and effect of GHG regulation, any such regulation could have a material adverse impact on our business, financial condition, reputation and operating performance.

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

AVAILABILITY OF REPORTS AND CORPORATE GOVERNANCE DOCUMENTS

We make available for free on our internet website, www.qrinc.com, our 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 as soon as reasonably practicable after we electronically file or furnish such material to the SEC. Additionally, charters for the committees of our Board and our Corporate Governance Guidelines and Code of Business Conduct and Ethics can be found on our internet 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.

EMPLOYEES

As of March 30, 2012, we had 477 employees, none of whom have collective bargaining agreements.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following information is provided with respect to our executive officers as of March 30, 2012.

Name	Age		Position(s)
Thomas F. Darden		58	Director, Chairman of the Board
Glenn Darden		56	Director, President and Chief Executive Officer
Anne Darden Self		54	Director, Vice President - Human Resources
Jeff Cook		55	Executive Vice President - Operations
Philip W. Cook		50	Executive Vice President - Chief Financial Officer
John C. Cirone		62	Executive Vice President - General Counsel
Stan Page		54	Senior Vice President - U.S. Operations
John C. Regan		42	Vice President, Controller and Chief Accounting Officer
Chris M. Mundy		39	Vice President - Engineering
John D. Rushford		52	Senior Vice President and Chief Operating Officer of Quicksilver Resources Canada Inc.

19

Officers are elected by our Board of Directors and hold office at the pleasure of the Board until their successors are elected and qualified. Thomas F. Darden, Glenn Darden and Anne Darden Self are siblings. Messrs. Jeff Cook and Philip W. Cook are not related. The following biographies describe the business experience of our executive officers:

THOMAS F. DARDEN has served on our Board of Directors since December 1997 and became Chairman of the Board in March 1999. 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 July 2007 to September 2011. Mr. Darden was previously employed by Mercury Exploration Company for 22 years in various executive level positions.

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

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

JEFF COOK became our Executive Vice President – Operations in January 2006, after serving as our Senior Vice President – Operations since July 2000. From 1979 to 1981, he held the position of Operations Supervisor with Western Company of North America. In 1981, he became a District Production Superintendent for Mercury Production Company and became Vice President of Operations in 1991 and Executive Vice President in 1998 of Mercury Production Company before joining us.

PHILIP W. COOK became our Executive Vice President – Chief Financial Office in January 2012, after serving as our Senior Vice President – Chief Financial Officer since October 2005. Mr. Cook has also 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), since September 2011 and from January 2007 to October 2010. From October 2004 until October 2005, Mr. Cook served as President and Chief Financial Officer of a private chemical company. From August 2001 until September 2004, he served as Vice President and Chief Financial Officer of a private oilfield service company. From August 1993 to July 2001, he served in various executive capacities with Burlington Resources Inc. (subsequently merged with ConocoPhillips), a public independent oil and gas company engaged in exploration, development, production and marketing.

JOHN C. CIRONE was named as our Executive Vice President – General Counsel in January 2012, after serving as our Senior Vice President – General Counsel since January 2006, and serving as our Vice President and General Counsel since July 2002. Mr. Cirone served as our Secretary from July 2002 to November 2010. Mr. Cirone was employed by Union Pacific Resources (subsequently merged with Anadarko Petroleum Corporation) from 1978 to 2000. During that time, he served in various positions in the Law Department, and from 1997 to 2000 he was the Manager of Land and Negotiations. In 2000, he became Assistant General Counsel of Union Pacific Resources. After leaving Union Pacific Resources in August 2000, Mr. Cirone was engaged in the private practice of law prior to joining us in July 2002.

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

JOHN C. REGAN became our Vice President, Controller and Chief Accounting Officer in September 2007. He is a Certified Public Accountant with more than 20 years of combined public accounting, corporate finance and financial reporting experience. Mr. Regan joined us from Flowserve Corporation where he held

20

various management positions of increasing responsibility from 2002 to 2007, including Vice President of Finance for the Flow Control Division and Director of Financial Reporting. He was also a senior manager specializing in the energy industry in the audit practice of PricewaterhouseCoopers, where he was employed from 1994 to 2002.

CHRIS M. MUNDY became our Vice President – Engineering responsible for corporate reserves in August 2010, after serving as our Senior Director – Engineering from January 2010 to August 2010, Director – Engineering from May 2009 to January 2010 and Manager, Engineering from October 2008 to May 2009. Mr. Mundy previously served as Manager, Corporate Projects for Quicksilver Resources Canada Inc. where he led our Horseshoe Canyon Asset development program and was responsible for project planning and budgeting from September 2004 to September 2006. Prior to re-joining us in 2008, Mr. Mundy served as Manager, Engineering at Twin Butte Energy where he was responsible for corporate reserves and numerous acquisition and divestiture evaluations from September 2006 to October 2008. Mr. Mundy is a professional engineer with more than 15 years of oil and gas experience.

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 25 years of oil and gas experience in project development and business unit management. Mr. Rushford joined us from Cenovus Energy Inc. where he served as the Vice President of Business Services supporting Cenovus’ business unit operations from 2005 to 2010. Prior to Cenovus he had more than 15 years of increasingly senior management positions at PanCanadian Petroleum Ltd. and EnCana Corp., including Vice President of the Chinook Business Unit that commercialized coalbed methane in Canada and as Vice President of the Fort Nelson Business Unit.

21

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.

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

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

Prices for our production fluctuate widely, particularly as evidenced by price movements between 2008 and 2011. Among the factors that can cause these fluctuations are:

Ÿ domestic and foreign demand for oil and natural gas;

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

Ÿ the quality, price and availability of alternative fuels;

Ÿ the quantity of natural gas in storage;

Ÿ weather conditions;

Ÿ domestic and foreign governmental regulations, including environmental and climate change requirements;

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

Ÿ political conditions in oil and natural gas producing regions;

Ÿ localized supply and demand fundamentals and transportation availability;

Ÿ technological advances affecting energy consumption;

Ÿ speculation by investors in oil and natural gas; and

Ÿ 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.

If the prices we receive for our production decrease, our exploration and development efforts are unsuccessful or our costs increase substantially, we may be required to recognize non-cash impairment of our oil and gas properties, which could have a material adverse effect on our results of operations.

We employ the full cost method of accounting for our oil and gas properties which, among other things, imposes limits to the capitalized cost of our assets. The capitalized cost pool cannot exceed the net present value of the underlying oil and gas reserves. We recognized impairment to the carrying value of our oil and gas properties in 2011, 2010 and 2009 of $49.1 million, $19.4 million and $979.5 million, respectively, and could recognize future impairments if the commodity prices utilized in determining proved reserve value cause the value of our proved reserves to decrease. Increased operating and capitalized costs without incremental increases in proved reserve value could also trigger impairment based upon decreased value of our proved reserves. The impairment of our oil and gas properties will cause us to reduce their carrying value and recognize non-cash expense, which could have a material adverse effect on our results of operations.

22

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, including assumptions relating to economic factors. Any inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of proved reserves presented in our filings with the SEC.

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 petroleum prices and other factors that may be beyond our control.

At December 31, 2011, 31% of our proved reserves were undeveloped. Recovery of 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 reserves. Although we have prepared estimates of our proved reserves using SEC specifications, actual prices and costs may vary from these estimates, the development 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 2011 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 estimate. Any changes in consumption by natural gas, NGL and oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the costs from the development and production of our oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is specified by the SEC, is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will 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 Barnett Shale Asset and Horseshoe Canyon Asset account for 82% and 14% of our 2011 production, respectively. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or gas produced from the wells in these areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our business, financial condition and results of operations.

23

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

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

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

If we are unable to obtain needed capital or financing on satisfactory terms, our ability to replace our reserves or to maintain current production levels may be limited.

Historically, we have used our cash flow from operations, borrowings under our credit facilities and issuances of debt to fund our capital program, working capital needs and acquisitions. Our capital program may require additional financing above the level of cash generated by our operations to fund our growth. If our cash flow from operations decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our reserves or to maintain current production may be limited, resulting in decreased production over time. If our cash flow from operations is insufficient to satisfy our financing needs, we cannot be certain that additional financing will be available to us on acceptable terms or at all. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings, including the sale of equity interests in a master limited partnership, may be limited by our financial condition or general economic conditions at the time of any such financing or offering. Even if we are successful in obtaining the necessary funds, the terms of such financings could have a material adverse effect on our business, results of operations and financial condition. If additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis.

Our business involves many hazards and operational risks.

Our operations are subject to many risks inherent in the oil and gas industry, including operating hazards such as well blowouts, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, 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

24

damages that might occur, and pollution and environmental risks generally are not fully insurable. Any significant accident or event that is not adequately insured could 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 insurance if we believe that the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for 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 production and cash flows.

Producing oil and gas reservoirs 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. Our proved reserves will generally decline as proved reserves are produced, except to the extent that we conduct successful exploration or development activities or acquire additional proved reserves. In order to maintain or increase proved reserves and production, we must continue our development drilling or undertake other replacement activities. Our planned exploration and development projects or any acquisition activities that we may undertake might not result in meaningful additional proved reserves, and we might not have continuing success drilling productive wells. Even in the event that our exploration and development projects do result in meaningful additional commercially viable proved reserves, midstream infrastructure for these proved reserves may not exist or may not be constructed, either of which could adversely impact our ability to benefit from those proved reserves. If our exploration and development efforts are unsuccessful, our leases covering acreage that is not already held by production could expire. If they do expire and if we are unable to renew the leases on acceptable terms, we will lose the right to conduct drilling activities and the resulting economic benefits associated therewith. If we are unable to develop or acquire additional proved reserves to replace our current and future production at economically acceptable terms, our business, financial condition, results of operations would be adversely affected.

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

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

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

We compete with major and independent oil and gas companies for property acquisitions and for the equipment and labor required to develop and operate our properties. Many of our competitors have substantially greater financial and other resources than we do, and they may be better able to absorb the burden of drilling and infrastructure costs and any changes in federal, state, provincial and local laws and regulations than we can, which would adversely affect our competitive position. In addition, there is substantial competition for investment capital in the oil and gas industry. These competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than we can. Our ability to

25

explore for oil and gas prospects and to acquire additional properties in the future will depend upon our ability to conduct operations, to evaluate and select suitable properties and to complete transactions in this highly competitive environment. Furthermore, the oil and gas industry competes with other industries in supplying the energy and fuel needs of industrial, commercial and other consumers. Our inability to compete effectively with other oil and gas companies could have a material adverse impact on our business activities, financial condition and results of operations.

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

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

Ÿ our production could be materially less than expected; or

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

If our actual production and sales for any period are less than the production covered by commodity derivatives (including reduced production due to operational delays) or if we are unable to perform our exploration and development activities as planned, we might be required to satisfy a portion of our obligations under those commodity derivatives without the benefit of the cash flow from the sale of that production, which may materially impact our liquidity. Additionally, if market prices for our production exceed collar ceilings or swap prices, we would be required to make monthly cash payments, which could materially adversely affect our liquidity. If we choose not to enter into such commodity derivatives in the future, we could be more affected by changes in commodity prices than our competitors who engage in hedging arrangements.

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, demand and costs for drilling equipment, crews and associated supplies, equipment and services can increase significantly. We cannot be certain that in a higher petroleum 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 material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services. In addition, drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, including urban drilling, and possible title issues. As a result of increased activity levels, we have seen increases and supply limitations for the services we procure. Any such shortages or delays and price increases could adversely affect our ability to execute our drilling program.

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

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

Ÿ discharge permits for drilling operations;

Ÿ water obtained for drilling purposes;

Ÿ drilling permits and bonds;

Ÿ reports concerning operations;

Ÿ spacing of wells;

Ÿ disposal wells;

Ÿ unitization and pooling of properties; and

Ÿ taxation.

26

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

We 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 other 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 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. 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. Failure to comply with these laws, regulations and permits may result in our being subject to litigation, fines or other sanctions, including the revocation of permits and suspension of operations, and could otherwise delay or impede the issuance or renewal of permits. We expect to continue to incur significant capital and other compliance costs related to such requirements.

We could be subject to joint and several strict liability for any environmental contamination at our 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, federal and state regulators are becoming increasingly focused on air emissions from our industry, including volatile organic compound emissions, which increased scrutiny could lead to heightened enforcement of existing regulations as well as the imposition of new air emission measures. With respect to GHG emissions, we are currently required to report annual GHG emissions from certain of our operations, and additional GHG emission related requirements have been implemented or are in various stages of development. Any current or future GHG or other air emission requirements could curtail our operations or otherwise result in operational delays, liabilities and increased compliance costs. In addition, to the 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. Various federal, state, provincial and local initiatives have been implemented or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing. In particular, the EPA has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of wastewater from certain gas production operations. In July 2011, the EPA also proposed new air standards that would require measures to reduce volatile organic compound emissions at new hydraulically fractured natural gas wells and existing wells that are re-fractured. In addition, certain municipalities and states in which we operate, including Colorado, Montana, Texas and Wyoming, have adopted, or are considering adopting, regulations that have imposed, or could impose, more stringent permitting, transparency, disposal and well construction requirements on hydraulic fracturing operations. For example, in December 2011, the Railroad

27

Commission of Texas and the Colorado Oil and Gas Conservation Commission finalized regulations requiring public disclosure of chemicals in fluids used in the hydraulic fracturing process. Similar regulations exist in British Columbia. Local ordinances or other regulations also may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. 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 requires significant quantities of water. Recently, Texas has been experiencing a drought. Any diminished access to water for use in hydraulic fracturing in Texas 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 operations 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.

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

Subject to the limits contained in our various debt agreements, we may incur additional debt. Our ability to incur additional debt and to comply with the terms of our debt agreements is affected by a variety of factors, including commodity prices and their effects on our proved reserves, financial condition, results of operations and cash flows. In addition, we expect our ability to borrow under our Combined Credit Agreements will depend on our borrowing base, which will be redetermined at least twice each year based on our reserve reports and such other information deemed appropriate by the administrative agent in a manner consistent with its normal oil and gas lending criteria as it exists at the time of the redetermination. If we incur additional debt or fail to increase the quantity and value of our proved reserves, the risks that we expect to face as a result of our indebtedness could intensify.

We have demands on our cash resources, including operating expense, funding of our capital expenditures and the interest expense we expect to have on our outstanding debt. Our level of debt, the value of our oil and gas properties and other assets, the demands on our cash resources, and the provisions of our outstanding debt could have important effects on our business and on the value of our securities. For example, the provisions of our outstanding debt could:

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

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

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

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

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

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

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

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

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

Ÿ increase our vulnerability to general adverse economic and industry conditions; and

Ÿ result in a default or event of default under our outstanding debt, which, if not cured or waived, could adversely affect our financial condition, results of operations and cash flows.

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

Ÿ reducing or delaying capital expenditures;

Ÿ seeking additional debt financing or equity capital;

Ÿ selling assets;

Ÿ restructuring or refinancing debt; or

Ÿ reorganizing our capital structure.

28

We cannot assure you that we would be able to implement any of these strategies on satisfactory terms, if at all, and our inability to do so could cause our securityholders to experience a partial or total loss of their investment in us.

The provisions of our debt agreements and the risks associated with our debt could adversely affect our business, financial condition and results of operations.

Our debt agreements restrict our ability to, among other things:

Ÿ incur additional debt;

Ÿ pay dividends on, or redeem or repurchase capital stock;

Ÿ make certain investments;

Ÿ incur or permit certain liens to exist;

Ÿ enter into certain types of transactions with affiliates;

Ÿ merge, consolidate or amalgamate with another company;

Ÿ transfer or otherwise dispose of assets, including capital stock of subsidiaries; and

Ÿ redeem subordinated debt.

Our debt agreements, among other things, require the maintenance of financial covenants that are more fully described in Note 11 to our consolidated financial statements found in Item 8 of this Annual Report. Our ability to comply with the covenants and other provisions of our debt agreements may be affected by events beyond our control, and we may be unable to comply with all aspects of our debt agreements in the future. In addition, our ability to borrow under our Combined Credit Agreements is dependent upon the quantity and value of our proved reserves and other assets.

The provisions of our debt agreements may affect the manner in which we obtain future financing, pursue attractive business opportunities and plan for and react to changes in business conditions. In addition, failure to comply with the provisions of our debt agreements could result in an event of default which could enable the applicable creditors to declare the outstanding principal and accrued interest to be immediately due and payable. Moreover, any of our debt agreements that contain a cross-default or cross-acceleration provision could also be subject to acceleration. If we were unable to repay the accelerated amounts, the creditors could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, we may have insufficient assets to repay such debt in full, and the holders of our securities could experience a partial or total loss of their investment.

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 and counterparties to hedging arrangements, under which such third parties incur performance or payment obligations to us. Any delay or failure on the part of one or more of such third parties to perform their obligations to us could, depending upon the nature and magnitude of such failure or failures, have a material adverse effect on our business, financial condition and results of operations.

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

We have substantial financial and other commitments related to our development of a gathering, processing and transportation system for Horn River.

We have agreed to provide NOVA Gas Transmission Ltd. (“NGTL”) with letters of credit to cover its costs to construct a pipeline and meter station (the “project”) that will connect the gas produced from our Horn River

29

Asset, to NGTL’s Alberta System (the “Horn River Mainline”). Our financial exposure is staged in increments as the project is built and ultimately, the costs for the project are estimated to be C$257 million including taxes of approximately C$28 million. Upon completion of the project, the requirement to provide the letters of credit will terminate.

We have also committed to deliver gas from our Horn River Asset for gathering and transport and must pay fees related to those services whether or not we deliver gas. These commitments are presented in Delivery Commitments and Purchases of Natural Gas, NGLs and Oil in Item 1. Our ability to fund these commitments may be affected by economic and capital markets conditions and other factors that may be beyond our control. In addition, we only have 99.3 MMcf of proved reserves our Horn River Asset as of December 31, 2011. Accordingly, our ability to deliver up to 1 Tcf of gas depends upon our ability to drill additional successful wells in our Horn River Asset, find third-party sources to supplement or satisfy our obligation or to pay a demand charge. Failure to satisfy our financial or other commitments could have a material adverse effect on our business, results of operations and financial condition.

If we do not make acquisitions on economically acceptable terms, our future growth will be limited.

In addition to expanding production from our current reserves, we may pursue acquisitions. If we are unable to make these acquisitions because we are: (1) unable to identify attractive acquisition candidates, to analyze acquisition opportunities successfully from an operational and financial point of view or to negotiate acceptable purchase contracts with them; (2) unable to obtain financing for these acquisitions on economically acceptable terms; or (3) outbid by competitors, then our future growth could be limited. Furthermore, even if we do make acquisitions, these acquisitions may not result in an increase in the cash generated by operations.

Any acquisition involves potential risks, including, among other things:

Ÿ mistaken assumptions about volume, revenue and costs, including synergies;

Ÿ an inability to integrate successfully the assets we acquire;

Ÿ the assumption of unknown liabilities;

Ÿ limitations on rights to indemnity from the seller;

Ÿ mistaken assumptions about the overall costs of equity or debt;

Ÿ the diversion of management’s and employees’ attention from other business matters;

Ÿ unforeseen difficulties operating in new product areas, with new customers, or new geographic areas; and

Ÿ customer or key employee losses at the acquired businesses.

Drilling locations 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.

As of December 31, 2011, we had 393 proved undeveloped locations with proved undeveloped reserves. These identified drilling locations represent an important part of our strategy. Our ability to execute our drilling program 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 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 drilling locations to yield oil or natural gas in commercially viable quantities could cause a decline in our proved reserves and adversely affect our results of operations.

30

Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of 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. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells, which 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, operations conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time for completion operations and other activities conducted on those properties, could result in increased lease operating expense and could adversely affect the production from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.

Horn River is in an early stage of development and has limited infrastructure.

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

Aboriginal peoples hold certain constitutionally protected rights in Canada that could materially affect our business, financial condition and results of operations.

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 covered by overlapping aboriginal rights claims. 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.

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, any increase in these differentials, if significant, could adversely affect our financial condition.

The recent adoption of 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. The U.S. Congress recently adopted comprehensive financial reform legislation that, among other things, establishes comprehensive federal oversight and regulation of over-the-counter derivatives and many of the entities that participate in that market. Although the Dodd-Frank Act was enacted on July 21, 2010, the Commodity Futures Trading Commission (the “CFTC”)

31

and the SEC, along with certain other regulators, must promulgate final rules and regulations to implement many of its provisions relating to over-the-counter derivatives. While some of these rules have been finalized, many have not and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.

In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain, energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of a contract that a trader may own or control separately or in combination, net long or short. The final rules also contain limited exemptions from position limits for certain bona fide hedging transactions and positions that were established in good faith before the initial limits become effective. The final rules became effective on January 17, 2012, but position limits will be phased in over time according to a specified schedule and the implementation of certain position limits is dependent on finalization of certain other rules to be jointly promulgated by the CFTC and the SEC. In addition, on December 2, 2011, the International Swaps and Derivatives Association, Inc. and the Securities Industry and Financial Markets Association filed a legal challenge to the final rules, claiming, among other things, that the rules may adversely impact commodities markets and market participants, including end-users, by reducing liquidity and increasing price volatility.

While the timing of implementation of the final rules on position limits, their applicability to, and impact on, us and the success of any legal challenge to their validity remain uncertain, there can be no assurance that they 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 will also impose a number of other new requirements on certain over-the-counter derivatives that may have a material adverse effect on us. The Dodd-Frank Act will also subject certain swap dealers and major swap participants to significant new regulatory requirements which in certain cases may cause them to conduct their activities through new entities that may not be as creditworthy as our current counterparties. The 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 a materially adverse effect on our ability to hedge our exposure to commodity prices.

In addition, under Dodd-Frank swap dealers and major swap participants will be required to collect initial and variation margin from certain end-users of over-the-counter derivatives. While rules implementing many of these requirements have been proposed by relevant regulators, not all have 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 might in the future be required to post collateral for some or all of our derivative transactions. Posting of collateral 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 could therefore reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus 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.

Lastly, the Dodd-Frank Act requires, no later than 270 days after the enactment of the Act, the SEC to promulgate rules requiring SEC reporting companies that engage in the commercial development of oil, natural gas or minerals, to include in their annual reports filed with the SEC disclosure about all payments (including taxes, royalties, fees and other amounts) made by the issuer or an entity controlled by the issuer to the United States or to any non-U.S. government for the purpose of commercial development of oil, natural gas or minerals. As these rules are not yet effective, we are unable to predict what form these rules may take and whether we will be able to comply with them without adversely impacting our business, or at all. Any of these consequences could have a material adverse effect on our business, financial condition and results of operations.

32

The loss of key personnel could adversely affect our ability to operate.

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

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

As of February 15, 2012, members of the Darden family, together with entities controlled by them, beneficially owned approximately 30% of our outstanding common stock. As a result, they are generally able to significantly affect the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our charter or bylaws and the approval of mergers and other significant corporate transactions.

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

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

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

Ÿ our board of directors is classified; and

Ÿ 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 adopted 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.

If our plan to separate certain of our Barnett Shale assets into a new publicly-traded master limited partnership is delayed or not completed, our stock price may decline and our growth potential may not be enhanced.

On October 19, 2011, we announced a plan to separate certain of our mature onshore oil and gas properties in our Barnett Shale Asset into a new publicly-traded master limited partnership (“MLP”). On February 10, 2012, MLP filed an initial registration statement on Form S-1 in connection with this planned initial public offering. Completion of this plan is subject to market conditions and numerous other risks beyond our control, including, but not limited to, the general economy, credit markets, equity markets and energy prices. Therefore, it is possible that MLP will not complete an offering of securities, will not raise the planned amount of capital even if an offering of securities is completed and will not be able to complete its proposed actions on the desired timetable. Furthermore, the structure, nature, purpose, and proposed manner of offering of MLP may change materially from those anticipated. If the transaction is not completed or delayed, our stock price may decline and our growth potential may not be enhanced.

If completed, our plan to separate portions of our Barnett Shale Asset may not achieve its intended results and could have an adverse effect on us due to a number of factors. Following the completion of the planned initial public offering, we will initially be the largest unitholder of MLP, holding common units, subordinated units and incentive distribution rights. We cannot assure you that the trading price of our common stock, which will include our retained investment in MLP, as adjusted for any changes in the combined capitalization of these companies, will be equal to or greater than the trading price of our common stock prior to the planned initial public offering of MLP.

33

In addition, MLP, and therefore our retained investment in MLP, will be subject to the risks normally attendant to businesses in the oil and natural gas industry, including most of the same risks to which we are subject.

Our announcement of this plan did not, and this risk factor does not, constitute an offer to sell or the solicitation of an offer to buy any securities. Any offers, solicitations of offers to buy, or any sales of securities of MLP will be made only in accordance with the registration requirements of the Securities Act of 1933 or an exemption therefrom.

We have identified a material weakness in our internal controls that, if not properly corrected, could result in material misstatements in our financial statements.

We have identified a material weakness in our system of internal control over financial reporting as of December 31, 2011. A material weakness is a deficiency, or combination of deficiencies in internal controls over financial reporting that results in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

The material weakness was related to the design and operating effectiveness of the computation of impairment of our non-oil and gas assets. Specifically, the weakness relates to design deficiencies regarding the assessment of triggering events and the consideration of asset groupings, as well as other deficiencies related to the performance and documentation of a recovery test and other fair value computational matters. In response to the identification of the material weakness, management has enhanced its process for documenting identification of impairment indicators, and the preparation and review of undiscounted recovery tests and discounted cash flow analyses. Significant deficiencies as of December 31, 2011 related to the Company’s calculation of its asset retirement obligation and exclusion of certain future development costs from the depletion calculation. In response to the identification of the significant deficiencies, management has enhanced the process for preparation and review of the inputs to the asset retirement obligation and the depletion calculation. Management believes that these enhancements and improvements, when repeated as applicable in future periods, remediate the material weakness and significant deficiencies described above.

Although there can be no assurances, we believe these enhancements and improvements, when repeated in future periods, will remediate the control deficiencies described above. If we are not able to remedy the control deficiencies in a timely manner, we may be unable to provide holders of our securities with the required financial information in a timely and reliable manner and we may incorrectly report financial information, either of which could subject us to litigation and regulatory enforcement actions.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties

A detailed description of our significant properties and associated 2011 developments can be found in Item 1 of this Annual Report, which is incorporated herein by reference.

ITEM 3. Legal Proceedings

We are a defendant in lawsuits from time to time in the normal course of business. We are not party to any legal proceedings that, based on facts currently available, management believes will, individually or in the aggregate, have a material adverse effect on Quicksilver’s business, operating results, financial condition or cash flows. In addition, allegations against our Executive Vice President – Operations in the District Court of Cleveland County, Oklahoma were dismissed on January 17, 2012.

ITEM 4. Mine Safety Disclosures

Not applicable.

34

PART II.

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

Market Information

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

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

	HIGH		LOW
2011
Fourth Quarter	$	8.87	$	6.17
Third Quarter		14.90		7.41
Second Quarter		15.41		13.00
First Quarter		15.98		13.63
2010
Fourth Quarter	$	15.88	$	12.12
Third Quarter		14.47		10.65
Second Quarter		15.45		10.53
First Quarter		16.59		12.82

As of March 30, 2012, there were approximately 742 common stockholders of record.

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

Performance Graph

The following performance graph compares the cumulative total stockholder return on Quicksilver common stock (KWK) with the Standard & Poor’s 500 Stock Index (the “S&P 500 Index”), the Standard & Poor’s 500 Exploration and Production Index (the “S&P 500 E&P Index”, also commonly referred to as the “S&P Midcap Oil, Gas, and Consumable Fuels Index”), and the Standard & Poor’s 400 Oil and Gas Index (the “S&P 400 Oil and Gas Index”) for the period from December 31, 2006 to December 31, 2011, assuming an initial investment of $100 and the reinvestment of all dividends, if any. In 2011, we changed from using the published index, the S&P Midcap Oil, Gas, and Consumable Fuels Index, to the S&P 400 Oil and Gas Index because we believe the S&P 400 Oil and Gas Index is a closer representation of our peer group and thus will depict a more reasonable correlation of KWK returns to the peer average.

Comparison of Cumulative Five Year Total Return

35

Issuer Purchases of Equity Securities

The following table summarizes our repurchases of Quicksilver common stock during the quarter ended December 31, 2011.

Period	Total Number  of Shares Purchased (1)		Average Price Paid per  Share		Total Number of Shares  Purchased as Part of Publicly Announced Plan (2)		Maximum Number of Shares that May Yet Be Purchased Under the Plan (2)
October 2011		2,646	$	7.58		-		-
November 2011		441	$	8.14		-		-
December 2011		-		-		-		-
Total		3,087	$	7.66		-		-

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

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

36

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,
	2011 (2)		2010 (3) (7)		2009 (4)			2008 (5)			2007 (6)
	(In thousands, except for per share data)
Operating Results Information
Total revenue	$	943,623	$	928,331	$	832,735		$	800,641		$	561,258
Operating income (loss)		122,604		804,134		(613,873	)		(249,697	)		803,581
Income (loss) before income taxes		147,909		713,828		(836,856	)		(585,077	)		730,806
Net income (loss)		90,046		455,290		(545,239	)		(373,622	)		476,445
Net income (loss) attributable to Quicksilver		90,046		445,566		(557,473	)		(378,276	)		475,390
Diluted earnings (loss) per common share (1)	$	0.52	$	2.50	$	(3.30	)	$	(2.33	)	$	2.87
Dividends paid per share		-		-		-			-			-
Financial Condition Information
Property, plant and equipment - net	$	3,460,519	$	3,063,245	$	2,542,845		$	3,298,830		$	1,866,540
Midstream assets held for sale - net		-		27,178		548,508			492,733			280,768
Total assets		3,995,462		3,507,734		3,612,882			4,498,208			2,773,751
Long-term debt		1,903,431		1,746,716		2,427,523			2,586,045			788,518
All other long-term obligations		495,939		248,762		121,877			282,101			434,190
Total equity		1,261,919		1,069,905		696,822			1,211,563			1,192,468
Cash Flow Information
Cash provided by operating activities	$	253,053	$	397,720	$	612,240		$	456,566		$	319,104
Capital expenditures		690,607		695,114		693,838			1,286,715			1,020,684

⁽¹⁾ Per share amounts have been adjusted to reflect a two-for-one stock split effected in the form of a stock dividend in January 2008.

⁽²⁾ 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 HCDS and certain midstream assets in Texas, and Canadian oil and gas properties, respectively.

⁽³⁾ Operating income for 2010 includes gains of $494.0 million and $57.6 million from the sales of KGS and BBEP Units, respectively. Operating income also includes charges for impairment of $28.6 million and $19.4 million for our HCDS and Canadian oil and gas properties, respectively.

⁽⁴⁾ Operating loss for 2009 includes charges of $786.9 million and $192.7 million for impairments associated with our U.S. and Canadian oil and gas properties, respectively. Net loss also includes $75.4 million of income attributable to our proportionate ownership of BBEP and a charge of $102.1 million for impairment of that investment.

⁽⁵⁾ Operating loss for 2008 includes a charge of $633.5 million for impairment associated with our U.S. oil and gas properties. Net loss also includes $93.3 million for pre-tax income attributable to our proportionate ownership of BBEP and a pre-tax charge of $320.4 million for impairment of that investment.

⁽⁶⁾ Operating income for 2007 include a gain of $628.7 million recognized from the divestiture of our Michigan, Indiana and Kentucky oil and gas properties and other assets and a charge of $63.5 million associated with a natural gas fixed-price sales contract that expired in March 2009 under which we no longer delivered natural gas produced from properties owned or operated by us.

⁽⁷⁾ Note 2 to the consolidated financial statements in Item 8 contains additional information regarding the immaterial restatement to the 2010 results of operation primarily for the revised gain on sale of our interests in KGS and to a lesser extent additional depletion expense.

37

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. Until the sale of all of our interests in KGS, we conducted 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.

Note 2 to the consolidated financial statements in Item 8 contains additional information regarding the immaterial restatement to the 2010 results of operations primarily for the restated gain on sale of our interests in KGS and to a lesser extent additional depletion expense. Accordingly, Management’s Discussion and Analysis of Financial Condition and Results of Operations has been revised for the effects of the immaterial restatement.

Our MD&A includes the following sections:

Ÿ Overview – a general description of our business; the value drivers of our business; measurements; and opportunities, challenges and risks

Ÿ 2011 Highlights – a summary of significant activities and events affecting Quicksilver

Ÿ 2012 Capital Program – a summary of our planned capital expenditures during 2012

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

Ÿ Results of Operations – an analysis of our consolidated results of operations for the three years presented in our financial statements

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

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

OVERVIEW

We are an independent oil and gas company engaged primarily in the acquisition, exploration, development, and production of onshore oil and 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, coalbeds and tight sands. 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.

At December 31, 2011, 77% and 22% of our proved reserves were natural gas and NGLs, respectively. Consistent with one of our business strategies, we continue to develop our unconventional resources by applying our expertise to our development projects in our Barnett Shale Asset, Horseshoe Canyon Asset and Horn River Asset, which had 88%, 8% and 4%, respectively, of our proved reserves at December 31, 2011. During 2011, based on the success of our exploration in our Horn River Asset, we began to consider this a development area, particularly in the southern portion of our acreage. Our acreage in our Horn River Asset provides us the most immediate additional opportunity for further application of our unconventional resources expertise.

We focus on three key value drivers:

Ÿ reserve growth;

Ÿ production growth; and

Ÿ maximizing our operating margin.

Our reserve growth relies on our ability to apply our technical and operational expertise to explore and develop unconventional reservoirs. We strive to increase reserves and production through aggressive

38

management of our operations and through relatively low-risk developmental drilling. We will also continue to identify high-potential exploratory projects with comparatively higher levels of financial risk. All of our development and exploratory programs are aimed at providing us with opportunities to develop unconventional reservoirs.

We believe the acreage we hold in our core operating areas is well suited for production increases through developmental drilling. We perform workover and infrastructure projects to reduce ongoing operating costs and enhance current and future production rates. We regularly review the properties we operate to determine if steps can be taken to efficiently increase reserves and production.

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

	Years Ended December 31,
	2011			2010			2009
Organic reserve growth (1)		1	%		19	%		20	%
Production volume (Bcfe)		150.6			129.6			118.5
Cash flow from operating activities (in millions)	$	253.1		$	397.7		$	612.3
Diluted earnings (loss) per share	$	0.52		$	2.50		$	(3.30	)

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

2011 HIGHLIGHTS

Master Limited Partnership

In October 2011, we announced our intention to file a registration statement on Form S-1 with the SEC in connection with the initial issuance of common units representing limited partner interest in a proposed master limited partnership (the “MLP”). We expect the MLP will use the proceeds from the sale of common units and borrowings under a planned new bank credit facility as consideration of certain of our Barnett Shale assets. We will retain a significant ownership position in the MLP and will own 100% of the general partner.

Fortune Creek

In December 2011, we announced the formation of Fortune Creek, a midstream partnership with KKR, dedicated to the construction and operation of midstream services to support us and potential producer customers primarily in British Columbia, Canada. The highlights of the transaction include:

Ÿ Our contribution of our existing 20-mile, 20-inch gathering line and compression facilities and 10-year contracts for gas deliveries into those facilities to the partnership;

Ÿ KKR’s payment of $125 million to us in exchange for a 50% interest in the partnership;

Ÿ KKR will pay our portion of future development costs for the initial processing facility in exchange for preferential cash flow distributions to KKR;

Ÿ We will be the operator of the partnership;

Ÿ The partnership building and operating natural gas gathering, transportation and processing infrastructure to maximize the value of the production stream from our development in our Horn River Asset;

Ÿ Our dedication of current and future production from our Horn River Asset to the partnership;

Ÿ Our minimum capital commitment of $100 million for drilling and completion activities in our Horn River Asset for 2012, 2013 and 2014; and

Ÿ The formation of an area of mutual interest for the midstream business covering approximately 30 million potential acres in Horn River, Liard and Cordova basins in British Columbia and the Northwest Territories, which is expected to include third-party transportation and processing infrastructure and agreements.

39

New Credit Facilities

In September 2011, we terminated and replaced our $1.0 billion global 2007 Senior Secured Credit Facility with new separate five-year syndicated senior secured revolving credit facilities for our U.S. and Canadian operations. The $1.25 billion Initial U.S. Credit Facility had a borrowing base of $850 million, including a letter of credit capacity of $75 million, as of September 30, 2011. The C$500 million Initial Canadian Credit Facility had a borrowing base of C$225 million, including a letter of credit capacity of C$100 million, as of September 30, 2011.

During December 2011, the Initial U.S. Credit Facility and the Initial Canadian Credit Facility were amended and restated by the Combined Credit Agreements. The $1.75 billion Combined Credit Agreements have a global borrowing base of $1.075 billion, including a global letter of credit capacity of $175 million, as of December 31, 2011.

We are currently working with our lending group of banks to establish a revolving credit facility for the MLP. When it becomes effective, we expect the borrowing base on the Combined Credit Facility to be reduced by $200 million. We expect the MLP credit facility to have an initial borrowing base of $275 million at the closing of the facility.

Convertible Debentures

On November 1, 2011, we repurchased substantially all of our outstanding convertible debentures for $150.0 million, after they were presented to us for repurchase by debenture holders. The repurchase transaction was completed utilizing borrowings from the Initial U.S. Credit Facility. During the first quarter of 2012, we repurchased the remaining debentures.

Emerging Basins

We have built an acreage position of 260,000 acres in the Sandwash basin of northwestern Colorado in a 900- square mile fairway prospective for the Niobara and Lower Mancos Shales. We drilled and completed seven vertical wells through December 2011, and drilled our first horizontal well in the fourth quarter of 2011 with initial production results of 500 bbld and completed approximately 3,000 lateral feet, which is half of the length of the lateral we plan to ultimately drill. We expect to drill and complete four to seven horizontal wells in 2012.

We have also built a 155,000 acre position in the Midland and Delaware basins of West Texas prospective in the Bone Springs and Wolfcamp formations and principally concentrated in four core areas: Jeff Davis and Reeves Counties, Upton and Crockett Counties, Pecos County and Presidio County. In early 2012, we retained an investment bank to help evaluate the opportunities for a joint venture partner to help exploit our West Texas acreage.

Sale of BBEP Units

During 2011, we sold 15.7 million BBEP Units for aggregate proceeds of $273.0 million, recognizing total gains of $217.9 million in our income statement as other income. At December 31, 2011, we no longer owned any BBEP Units.

2012 CAPITAL PROGRAM

We expect our 2012 capital program to be spent in the following areas:

	Barnett Shale		Sandwash Basin		West Texas		Total U.S.		Horn River		Horseshoe Canyon		Total Canada		Total Company
	(In millions)
Drilling and completion	$	94	$	31	$	25	$	150	$	146	$	6	$	152	$	302
Midstream		2		17		-		19		25		2		27		46
Leasehold evaluation and acquisition		12		4		5		21		-		1		1		22
Total budgeted capital	$	108	$	52	$	30	$	190	$	171	$	9	$	180	$	370

40

The chart above does not include approximately $40 million of overhead and interest expense that may be ordinarily capitalized and corporate and administrative capital.

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 natural gas, NGL and oil production is among the several risks that we face. We seek to manage this risk by entering into derivative contracts which we strive to account for as hedges. We have mitigated the downside risk of adverse price movements through the use of these derivatives but, in doing so, have also limited our ability to benefit from favorable price movements. Our commodity price strategy enhances our ability to execute our development and exploration programs, meet debt service requirements and pursue acquisition opportunities even in periods of price volatility or depression. Item 7A of this Annual Report contains details of our commodity price and interest rate risk management.

RESULTS OF OPERATIONS

“Other U.S.” refers to the combined amounts for our operations in our Sandwash Asset and our Bakken Asset.

Our audited net income is less than that reported in our press release of March 15, 2012. The difference is attributable to the following non-cash adjustments recorded after March 15, 2012: $3.0 million reduction in Other Revenue and long-term derivative assets due to recognition of additional credit risk associated with our counterparties; $3.0 million additional impairment charge for HCDS based on downward revisions to fair value; and the related tax impact for these adjustments.

Revenue

Production Revenue by operating area:

	Natural Gas						NGL						Oil						Total
	2011		2010		2009		2011		2010		2009		2011		2010		2009		2011		2010		2009
	(In millions)
Barnett Shale	$	376.5	$	321.2	$	236.6	$	216.6	$	160.6	$	135.5	$	11.8	$	11.8	$	14.0	$	604.9	$	493.6	$	386.1
Other U.S.		1.1		2.3		0.5		0.6		0.5		0.3		12.3		10.0		8.0		14.0		12.8		8.8
Hedging		100.2		250.2		213.1		(46.1)		(24.1)		-		-		-		-		54.1		226.1		213.1
U.S.		477.8		573.7		450.2		171.1		137.0		135.8		24.1		21.8		22.0		673.0		732.5		608.0
Horseshoe Canyon		79.2		90.4		88.0		0.1		0.2		0.1		-		-		0.1		79.3		90.6		88.2
Horn River		17.4		10.6		2.5		-		-		-		-		-		-		17.4		10.6		2.5
Hedging		30.8		22.7		98.0		-		-		-		-		-		-		30.8		22.7		98.0
Canada		127.4		123.7		188.5		0.1		0.2		0.1		-		-		0.1		127.5		123.9		188.7
Consolidated	$	605.2	$	697.4	$	638.7	$	171.2	$	137.2	$	135.9	$	24.1	$	21.8	$	22.1	$	800.5	$	856.4	$	796.7

Average Daily Production Volume by operating area:

	Natural Gas						NGL						Oil						Equivalent Total
	2011		2010		2009		2011		2010		2009		2011		2010		2009		2011		2010		2009
			(MMcfd)						(Bbld)						(Bbld)						(MMcfed)
Barnett Shale		261.8		207.9		168.3		12,117		11,913		13,598		352		433		729		336.6		281.9		254.2
Other U.S.		0.8		1.5		0.6		24		25		34		396		397		434		3.3		4.0		3 .4
U.S.		262.6		209.4		168.9		12,141		11,938		13,632		748		830		1,163		339.9		285.9		257.6
Horseshoe Canyon		58.4		61.2		64.9		6		8		5		-		-		2		58.5		61.2		64.9
Horn River		14.1		8.0		2.0		-		-		-		-		-		-		14.1		8.0		2.0
Canada		72.5		69.2		66.9		6		8		5		-		-		2		72.6		69.2		66.9
Consolidated		335.1		278.6		235.8		12,147		11,946		13,637		748		830		1,165		412.5		355.1		324.5

41

Average Realized Price by operating area:

	Natural Gas						NGL								Oil						Equivalent Total
	2011		2010		2009		2011			2010			2009		2011		2010		2009		2011		2010		2009
	(per Mcf)						(per Bbl)								(per Bbl)						(per Mcfe)
Barnett Shale	$	3.94	$	4.23	$	3.85	$	48.98		$	36.93		$	27.31	$	91.83	$	74.71	$	52.62	$	4.92	$	4.80	$	4.16
Other U.S.		4.06		4.16		3.62		72.92			56.04			27.02		84.87		68.77		50.53		11.65		8.68		7.41
Hedging		1.05		3.28		3.45		(10.41	)		(5.53	)		-		-		-		-		0.44		2.17		2.26
U.S.	$	4.99	$	7.51	$	7.31	$	38.61		$	31.44		$	27.30	$	88.15	$	71.87	$	51.84	$	5.42	$	7.02	$	6.47
Horseshoe Canyon	$	3.71	$	5.06	$	3.71	$	64.64		$	66.03		$	54.66	$	-	$	-	$	54.80	$	3.72	$	5.07	$	3.71
Horn River		3.39		3.64		3.43		-			-			-		-		-		-		3.39		3.64		3.43
Hedging		1.16		0.90		4.01		-			-			-		-		-		-		1.16		0.90		4.01
Canada	$	4.81	$	4.90	$	7.72	$	64.64		$	66.03		$	54.66	$	-	$	-	$	54.80	$	4.82	$	4.90	$	7.72
Consolidated	$	4.95	$	6.86	$	7.42	$	38.63		$	31.46		$	27.32	$	88.15	$	71.90	$	51.85	$	5.32	$	6.61	$	6.73

The following table summarizes the changes in our natural gas, NGL and oil revenue:

	Natural     Gas		NGL		Oil		Total
	(In thousands)
Revenue for 2009	$	638,705	$	135,940	$	22,053	$	796,698
Volume variances		59,534		(16,840)		(6,352)		36,342
Hedge settlement variances		(37,904)		(24,113)		-		(62,017)
Price variances		37,078		42,174		6,074		85,326
Revenue for 2010	$	697,413	$	137,161	$	21,775	$	856,349
Volume variances		86,142		2,727		(2,140)		86,729
Hedge settlement variances		(142,014)		(22,033)		-		(164,047)
Price variances		(36,336)		53,410		4,438		21,512
Revenue for 2011	$	605,205	$	171,265	$	24,073	$	800,543

Natural gas revenue for 2011 decreased from 2010 despite a 20% increase in production. Realized prices, before hedge settlements, were lower for 2011 as compared to 2010, which more than offset production increases. The 2011 increase in natural gas volume from our Barnett Shale Asset was primarily the result of additional producing wells in our Alliance Asset to meet our Eni commitment as well as production throughout the basin up-lift from well work over activity. The Canadian natural gas production increase was primarily the result of two additional producing wells in our Horn River Asset that were brought on line in December 2010. The decrease in our Horseshoe Canyon Asset production was the result of reduced capital spending and the aging of the field.

The increase in NGL revenue for 2011 resulted from an increase in both realized prices and in production primarily from our Barnett Shale Asset compared to 2010. The increase in production resulted from additional producing wells and work over activity in the southern portion of the basin.

Natural gas revenue for 2010 increased from 2009 as a result of increases in production in our Barnett Shale Asset, which was primarily the result of wells brought online during 2010. Higher market prices for natural gas in 2010 also caused increased revenue, but were offset by a decrease from hedge contributions.

The small increase in NGL revenue for 2010 was due to increased market prices whose effect was reduced by payments made to settle hedges in 2010 and a decrease in production from our Barnett Shale Asset compared to 2009.

42

Sales of Purchased Natural Gas and Costs of Purchased Natural Gas

	Years Ended December 31,
	2011		2010		2009
			(In thousands)
Sales of purchased natural gas:
Purchases from Eni	$	71,921	$	53,340	$	11,195
Purchases from others		14,724		10,749		12,459
Total		86,645		64,089		23,654
Costs of purchased natural gas sold:
Purchases from Eni		71,746		61,121		12,268
Purchases from others		13,652		10,825		11,265
Unrealized valuation (gain) loss on Gas Purchase Commitment		-		(6,625)		6,625
Total		85,398		65,321		30,158
Net sales and purchases of natural gas	$	1,247	$	(1,232)	$	(6,504)

Our purchase and sale of Eni’s natural gas production for 2011 and 2010 reflected a full year’s activity as compared to six months’ activity in 2009. Additionally, production has increased in our Alliance Asset, where Eni’s working interests are located, because of new wells brought online throughout 2011 and 2010. As the Gas Purchase Commitment with Eni expired on December 31, 2010, no unrealized valuation gain or loss was recognized for the 2011 period. The Gas Purchase Commitment is more fully described in Note 3 to the consolidated financial statements in Item 8 of this Annual Report.

Other Revenue

	Years Ended December 31,
	2011		2010			2009
			(In thousands)
Midstream revenue:
KGS	$	-	$	6,512		$	7,153
Canada		3,139		2,373			2,678
Other U.S.		1,018		1,352			2,683
Total midstream revenue		4,157		10,237			12,514
Unrealized gains on commodity derivatives		45,852		-			-
Gain (loss) from hedge ineffectiveness		5,928		(2,629	)		(131	)
Other		498		285			-
Total	$	56,435	$	7,893		$	12,383

Other revenue increased compared to 2010 due to our recognition of $48.9 million in the 2011 period for unrealized gains on commodity derivatives that were not designated as hedges at inception. These instruments were subsequently designated as hedges in August 2011 with unrealized gains and losses from that date forward recognized as a component of AOCI. We do not expect these charges to recur. These unrealized gains were partially offset by a decrease in fair value of the related hedge assets due to credit risk of our counterparties as of December 31, 2011. U.S. midstream revenue declined in 2011 primarily as a result of the sale of our interests in KGS in October 2010 and a decrease in volumes gathered in our HCDS (which contributed to the impairment more fully discussed elsewhere in these results of operations). The increase in Canada is primarily the result of additional customers under contract for the

43

transportation of natural gas. We had gains attributable to ineffectiveness of our production hedge derivatives for 2011 as compared to losses in 2010.

Other revenue for 2010 decreased as compared to 2009. Midstream revenue was lower for 2010 primarily as a result of the sale of our interests in KGS in October 2010 and lower volume on our HCDS. Losses attributable to ineffectiveness of our production hedge derivatives were greater for 2010 as compared to 2009.

Operating Expense

Lease Operating Expense

	Years Ended December 31,
	2011				2010				2009
	(In thousands, except per unit amounts)
				Per				Per				Per
				Mcfe				Mcfe				Mcfe
Barnett Shale
Cash expense	$	62,158	$	0.50	$	47,231	$	0.46	$	41,538	$	0.45
Equity compensation		904		0.01		841		0.01		761		0.01
	$	63,062	$	0.51	$	48,072	$	0.47	$	42,299	$	0.46
Other U.S.
Cash expense	$	6,327	$	5.24	$	5,945	$	4.05	$	6,348	$	5.20
Equity compensation		224		0.19		182		0.12		195		0.16
	$	6,551	$	5.43	$	6,127	$	4.17	$	6,543	$	5.36
Total U.S.
Cash expense	$	68,485	$	0.55	$	53,176	$	0.51	$	47,886	$	0.51
Equity compensation		1,128		0.01		1,023		0.01		956		0.01
	$	69,613	$	0.56	$	54,199	$	0.52	$	48,842	$	0.52
Horseshoe Canyon
Cash expense	$	29,853	$	1.40	$	27,221	$	1.21	$	27,881	$	1.18
Equity compensation		461		0.02		1,271		0.06		2,114		0.09
	$	30,314	$	1.42	$	28,492	$	1.27	$	29,995	$	1.27
Horn River
Cash expense	$	2,947	$	0.57	$	2,145	$	0.74	$	190	$	0.26
Equity compensation		-		-		-		-		-		-
	$	2,947	$	0.57	$	2,145	$	0.74	$	190	$	0.26
Total Canada
Cash expense	$	32,800	$	1.24	$	29,366	$	1.16	$	28,071	$	1.15
Equity compensation		461		0.02		1,271		0.05		2,114		0.09
	$	33,261	$	1.26	$	30,637	$	1.21	$	30,185	$	1.24
Total Company
Cash expense	$	101,285	$	0.67	$	82,542	$	0.63	$	75,957	$	0.64
Equity compensation		1,589		0.01		2,294		0.02		3,070		0.03
	$	102,874	$	0.68	$	84,836	$	0.65	$	79,027	$	0.67

Lease operating expense for 2011 in the U.S. increased compared to 2010 primarily due to higher production volumes in our Barnett Shale Asset including costs attributable to new producing wells such as gas lift, chemicals and overhead for approximately $8 million. In addition, non-variable costs such as compressor

44

overhauls, repairs and replacements, environmental compliance and other costs increased by approximately $7 million. Notably, saltwater disposal costs increased only slightly despite a 16% increase in water volumes due to a higher percentage being piped and disposed of in our own disposal wells at a lower cost.

Our Horseshoe Canyon Asset lease operating expense increased primarily due to increases in compression overhauls, utilities and surface costs. Notably, costs per Mcfe in our Horn River Asset decreased as a consequence of increased production levels creating greater coverage of the fixed portion of expense. We expect the trend of lower unit lease operating expense in our Horn River Asset will continue in 2012.

Although U.S. lease operating expense for 2010 was higher than 2009, lease operating expense per Mcfe was unchanged from 2009 to 2010. Increased expense was the result of the increase in production volume in our Barnett Shale Asset for 2010 as compared to 2009.

Lease operating expense for 2010 in Canada was almost unchanged from 2009 despite a 3% increase in 2010 production compared to 2009. Lease operating expense for 2010 on a Canadian dollar basis increased C$1.7 million, or 4%, from 2009. Canadian lease operating expense on a Canadian dollar basis per Mcfe for 2010 increased less than 1% from 2009.

Gathering, Processing and Transportation Expense

	Years Ended December 31,
	2011				2010				2009
	(In thousands, except per unit amounts)
				Per				Per				Per
				Mcfe				Mcfe				Mcfe
Barnett Shale	$	172,128	$	1.40	$	82,976	$	0.81	$	42,678	$	0.46
Other U.S.		70		0.05		22		0.01		11		0.01
Total U.S.	$	172,198	$	1.39	$	82,998	$	0.80	$	42,689	$	0.45
Horseshoe Canyon		4,157		0.19		4,867		0.22		4,803		0.20
Horn River		14,205		2.77		6,143		2.11		1,196		1.62
Total Canada		18,362		0.69		11,010		0.44		5,999		0.25
Total	$	190,560	$	1.27	$	94,008	$	0.73	$	48,688	$	0.41

GPT increased for 2011 compared to 2010 primarily due to the loss of fees earned by KGS for gathering and processing production from our Barnett Shale Asset following the closing of the Crestwood Transaction and the increase in our Barnett Shale Asset production. KGS’ revenue, net of associated operating expenses, was $72.9 million, or 0.71 per Mcfe, for 2010. The remainder of the increase is attributable to increases in production although unit costs were lower in 2010 (excluding KGS effects) because more production came from the northern portion of the basin. Canadian GPT increased for 2011 as compared to 2010 both in total dollars and on a per Mcfe basis primarily as a result of higher gathering fees and increased production from our Horn River Asset for 2011 and the recognition of $4.6 million for unutilized capacity under the Company’s firm transportation agreements with third parties. The decrease in our Horseshoe Canyon Asset is primarily due to reduced transportation fees and a decrease in production volumes. Our Horseshoe Canyon Asset GPT also decreased due to reduced operating costs on gathering lines which feature cost sharing arrangements.

GPT for 2010 compared to 2009 increased primarily due to the loss of fees earned by KGS for gathering and processing production from our Barnett Shale Asset following the closing of the Crestwood Transaction. KGS’ revenue, net of associated operating expense, averaged $18.5 million per quarter for the first three quarters of 2010. Fourth quarter 2010 GPT consisted primarily of fees charged by KGS. Canadian GPT increased for 2010 both in total dollars and on a per Mcfe basis primarily as a result of transportation fees associated with higher production from our Horn River Asset for 2010.

45

Production and Ad Valorem Taxes

	Years Ended December 31,
	2011				2010				2009
	(In thousands, except per unit amounts)
				Per				Per				Per
Production taxes				Mcfe				Mcfe				Mcfe
U.S.	$	8,983	$	0.07	$	9,171	$	0.09	$	4,746	$	0.05
Canada		231		0.01		609		0.03		222		0.01
Total production taxes		9,214		0.06		9,780		0.07		4,968		0.04
Ad valorem taxes
U.S.	$	17,095		0.14	$	21,797		0.21	$	16,658		0.18
Canada		2,917		0.11		2,579		0.10		2,255		0.09
Total ad valorem taxes		20,012		0.13		24,376		0.19		18,913		0.16
Total	$	29,226	$	0.19	$	34,156	$	0.26	$	23,881	$	0.20

U.S. production taxes for 2011 reflect the refund of 2008 severance taxes in the amount of $1.1 million. The decrease in Canadian production taxes is primarily the result of decreased volumes attributable to freehold acreage, which is subject to taxation, and due to decreased pricing upon which tax is levied. The decrease in 2011 U.S. ad valorem taxes as compared to 2010 is primarily the result of the sale of KGS, attributing $3.8 million of the decrease. The remaining approximate $1 million decrease is attributable to reduced assessed property values as a function of lower prices. The increase in 2011 Canadian ad valorem taxes is due to increased rates on freehold lands and an increase in the midstream property base.

Production taxes for 2010 reflect a 15% increase in realized prices before hedge settlements for production from our Barnett Shale Asset and an 11% increase in production volume from our Barnett Shale Asset when compared to 2009. Higher U.S. ad valorem taxes for 2010 reflect the addition of wells, particularly in areas with higher ad valorem tax rates, and increases to ad valorem tax rates assessed by taxing entities in Texas when compared to 2009. Production taxes for 2010 included $3.8 million of ad valorem taxes attributable to KGS. Production taxes in Canada increased in 2010 compared to 2009 due to increases in natural gas prices and increased production on freehold acreage.

Depletion, Depreciation and Accretion

	Years Ended December 31,
	2011				2010				2009
	(In thousands, except per unit amounts)
				Per				Per				Per
Depletion				Mcfe				Mcfe				Mcfe
U.S.	$	164,493	$	1.33	$	129,843	$	1.24	$	127,888	$	1.36
Canada		38,228		1.44		38,825		1.54		33,782		1.38
Total depletion		202,721		1.35		168,668		1.30		161,670		1.36
Depreciation of other fixed assets:
U.S.	$	12,931	$	0.10	$	30,252	$	0.29	$	33,329	$	0.35
Canada		7,415		0.28		4,698		0.19		3,952		0.16
Total depreciation		20,346		0.14		34,950		0.27		37,281		0.31
Accretion		2,696		0.02		3,585		0.03		2,436		0.02
Total	$	225,763	$	1.50	$	207,203	$	1.60	$	201,387	$	1.70

46

U.S. depletion for 2011 reflected an increase in the U.S. depletion rate and an increase in U.S. production when compared to the 2010 period. We expect that our consolidated depletion rate for 2012 will be approximately $1.40 per Mcfe. The increase in the rate was due to a 7% decrease in reserves and an increase in the depletion base associated with our 2011 capital program. Price deterioration adversely affected reserves in 2011. Canadian depletion rate in 2011 was impacted by the impairment recognized in 2011 as the 24% increase in proved reserves resulted in only a 8% increase in the depletion base.

U.S. depreciation decreased from 2010 primarily as the result of 2010 including KGS depreciation of $15.9 million and a $55.0 million impairment of midstream assets. Canadian depreciation for 2011 reflects seven months of depreciation on our Horn River Asset midstream additions which were contributed in the formation of Fortune Creek.

U.S. depletion expense for 2010 was greater than 2009 as an 11% increase in U.S. production was partially offset by a 4% decrease in the U.S. depletion rate. Changes in the U.S.-Canadian dollar exchange rate accounted for $3.7 million of the increase in Canadian depletion expense. Both our U.S. and Canadian depletion rates have been impacted by the impairment charges recognized during 2009. The Canadian depletion rate has been further impacted by evaluated Horn River Asset capital costs and future development costs included in proved reserve estimates at December 31, 2010.

The decrease in 2010 U.S. depreciation expense as compared to 2009 is the result of the sale of KGS. KGS’ depreciation expense through September 2010 was $15.9 million as compared to $18.8 million for all of 2009.

Impairment Expense

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

In performing our quarterly ceiling tests, we utilize first of month prices for the preceding 12 months. Due to the decrease in natural gas prices in the first quarter 2012 compared to the first quarter 2011, there is a significant likelihood of impairment of oil and gas properties. As of December 31, 2011, our U.S. and Canadian ceiling tests included $204 million and $104 million, respectively, in value for our derivatives treated as hedges of production. Absent this recognition, after tax we would have recognized $111 million of additional impairment expense for our U.S. oil and gas properties and $30 million for our Canadian oil and gas properties.

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

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

In 2010, we recognized impairment expense of $48.0 million. As a result of the decision by our board of directors to approve a plan for disposal of our HCDS, we conducted an impairment analysis of the HCDS and recognized a $28.6 million non-cash charge for impairment. We also recognized a non-cash $19.4 million charge for impairment of our Canadian oil and gas properties. Our Canadian full-cost pool has undergone significant change associated with the cost of bringing our initial Horn River Asset wells online and associated field costs while the proved reserves recognized have been limited due to the lack of any substantial production history for the area.

47

We recognized non-cash charges totaling $979.6 million for impairments related to both our U.S. and Canadian oil and gas properties in 2009. The primary factor that caused the decrease in the future cash flows from our proved oil and gas reserves was lower benchmark natural gas prices at March 31, 2009 for the U.S. and Canada and further Canadian price decreases at June 30, 2009. The Canadian impairment also resulted from a near-term decrease in expected capital spending with a consequent reduction in near-term production and revenue.

At September 30, 2009, the unamortized cost of our Canadian oil and gas properties exceeded the full cost ceiling limitation by $38.8 million. As permitted by full cost accounting rules in effect at that date, improvements in AECO spot natural gas prices subsequent to September 30, 2009 eliminated the necessity to record a charge for impairment.

General and Administrative Expense

	Years Ended December 31,
	2011				2010				2009
	(In thousands, except per unit amounts)
				Per				Per				Per
				Mcfe				Mcfe				Mcfe
Equity compensation	$	19,272	$	0.13	$	22,144	$	0.17	$	17,043	$	0.14
Litigation settlement		8,500		0.06		2,650		0.02		5,000		0.04
Strategic transactions		4,978		0.03		4,746		0.04		-		-
Other		46,832		0.31		50,567		0.39		55,200		0.47
Total	$	79,582	$	0.53	$	80,107	$	0.62	$	77,243	$	0.65

General and administrative costs for the 2011 period included $8.5 million for litigation settlement and $5.0 million for legal, accounting and professional fees incurred in connection with the evaluation of possible strategic transactions. General and administrative expense for the 2010 period included costs for the settlement of a separate legal matter for $2.4 million, professional and legal fees incurred in connection with the Crestwood Transaction of $2.6 million plus $5.0 million of KGS general and administrative expense arising prior to the Crestwood Transaction.

General and administrative expense for 2010 was $2.9 million greater than 2009 due to an increase in stock-based compensation expense, which included $3.6 million for the vesting of all of KGS’ unvested stock-based compensation at the time of its sale. Legal and professional fees for 2010, however, were $5.9 million lower than in 2009 primarily due to settlement of our litigation with BBEP in April 2010 and a decrease in litigation settlement costs. These decreases were partially offset by $2.5 million incurred in 2010 for transaction costs, principally investment banking and legal fees, related to the Crestwood Transaction.

We expect elevated levels of general and administrative expense in 2012 as there will be additional costs after the MLP becomes publicly traded, such as costs for director fees, listing fees and investor relations.

Gain on Sale of KGS

In October 2010, we recognized a $494.0 million gain upon closing of the Crestwood 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.

Income from Earnings of BBEP

We record our portion of BBEP’s earnings during the quarter in which its financial statements become publicly available. As a result, our 2011, 2010 and 2009 annual results of operations include BBEP’s earnings for the 12 months ended September 30, 2011, 2010 and 2009, respectively. Additionally, we reduced our ownership of BBEP Units in 2010 and eliminated our remaining ownership position in 2011. As of December 31, 2011, we no longer owned any BBEP Units.

48

We recognized an $8.4 million loss and income of $22.3 million for equity earnings from our investment in BBEP based upon its reported earnings for the 12-month period ended September 30, 2011 and 2010, respectively. During the time we owned BBEP Units, BBEP experienced significant volatility in its net earnings primarily due to changes in the value of its derivative instruments for which it did not employ hedge accounting.

Impairment of Investment in BBEP

During the first quarter of 2009, we evaluated our investment in BBEP for impairment in response to further decreases in prevailing commodity prices and the BBEP Unit price after December 31, 2008. As a result of these decreases, we made the determination that the decline in value was other-than-temporary. Accordingly, our impairment analysis, which utilized the March 31, 2009 closing price of $6.53 per BBEP Unit, resulted in aggregate fair value of $139.4 million for the portion of BBEP Units that we owned. The $139.4 million aggregate fair value was compared to the $241.5 million carrying value of our investment in BBEP. We recorded the difference of $102.1 million as an impairment charge during the first quarter of 2009. A similar analysis was performed at each subsequent quarter-end of 2009, 2010 and 2011, which resulted in no further impairment. Note 7 to our consolidated financial statements found in Item 8 of this Annual Report contains additional information regarding our investment in BBEP.

Other Income

We recognized gains of $217.9 million in 2011 from the sale of 15.7 million BBEP Units. We also recognized a gain of $35.4 million from the conveyance of 3.6 million BBEP Units as consideration in the acquisition of additional working interests in our Lake Arlington Asset in May 2010. Gains totaling $22.2 million were recognized in September and October 2010 from the sale of 2.05 million BBEP Units. In 2010, we also finalized a settlement of our litigation with BBEP and received $18.0 million from BBEP and a third party. Note 3 to the consolidated financial statements found in this Annual Report contains additional information about the Lake Arlington transaction.

Interest Expense

	Years Ended December 31,
	2011		2010		2009
			(In thousands)
Interest costs on debt outstanding	$	172,696	$	174,906	$	154,961
Fees paid on letters of credit outstanding		1,674		971		735
Cash premium on early debt extinguishment		2,560		-		-
Add:
Non-cash interest (1)		16,510		17,226		18,410
Non-cash loss on early debt extinguishment		-		-		27,122
Less: Interest capitalized		(7,416)		(4,750)		(6,127)
Interest expense	$	186,024	$	188,353	$	195,101

⁽¹⁾ Amortization of deferred financing costs and original issue discount.

Interest costs on debt outstanding for 2011 were flat compared to 2010. 2011 included slightly higher credit facility borrowing offset by lower senior debt and convertible debentures which offset the overall level of interest expense on all debt. 2011 included non-cash interest attributable to the repurchased senior notes and deferred financing fees attributable to the terminated 2007 Senior Secured Credit Facility and the Initial U.S Credit Facility. 2010 included interest expense attributable to KGS of $6.9 million in 2010.

49

In 2011, we repurchased notes as summarized below:

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

Interest costs on debt outstanding for 2010 were higher than 2009 primarily because of the full year impact of the senior notes due 2016 and senior notes due 2019 being outstanding. Overall interest expense was lower in 2010 than 2009 due to the absence of $27.1 million of expense related to the early retirement of a portion of our debt in 2009. We do not have a practice of maintaining higher debt balances throughout the quarter and minimizing them at quarter end for financial reporting purposes.

Income Taxes

The U.S effective tax rates for the three years ended December 31, 2011 are as follows:

	Years Ended December 31,
	2011			2010			2009
				(In thousands)
Income (loss) before income taxes	$	146,090		$	708,081		$	(744,053	)
Income tax expense (benefit)	$	53,599		$	255,207		$	(267,349	)
Effective tax rate		36.69	%		36.04	%		35.93	%

The Canadian effective tax rates for the three years ended December 31, 2011 are as follows:

	Years Ended December 31,
	2011			2010			2009
				(In thousands)
Income (loss) before income taxes	$	1,819		$	5,747		$	(92,803	)
Income tax expense (benefit)	$	4,264		$	3,331		$	(24,268	)
Effective tax rate		234.41	%		57.96	%		26.15	%

The consolidated effective tax rates for the three years ended December 31, 2011 are as follows:

	Years Ended December 31,
	2011			2010			2009
				(In thousands)
Income (loss) before income taxes	$	147,909		$	713,828		$	(836,856	)
Income tax expense (benefit)	$	57,863		$	258,538		$	(291,617	)
Effective tax rate		39.12	%		36.22	%		34.85	%

Taxation in the U.S. for the three years utilized a federal tax rate of 35% and a state tax rate of 1%. Actual effective tax rates differed from the combined U.S. and state rates primarily as a result of permanent items related to the non-deductible expenses.

The Canadian effective tax rates for the three years utilized a combined federal and provincial rate of 25%. The increase in the Canadian effective rate for 2011 was the result of an audit assessment imposed during 2011 and the application of capital gains rates related to the formation of Fortune Creek. The increase in the Canadian effective tax rate for 2010 was primarily the result of an audit assessment of $1.0 million related to a predecessor’s 1997 activities and other permanent items related to non-deductible expenses.

50

Our income tax provision for 2011 decreased from the income tax provision recognized for 2010, primarily as a result of the decrease in pretax earnings. The 2010 pretax earnings included the gain on the sale of KGS. Canadian taxes increased for 2011 due to the recognition of capital gain resulting from the formation of Fortune Creek. For 2011, our effective rate in the U.S. was 36.7% and in Canada, it was 234.41%.

Our 2010 income tax provision increased from 2009 due primarily to higher income before taxes including the gain recognized on the sale of KGS and gains recognized from the disposition or sale of a portion of our BBEP Units. Also, the impact of permanent items for non-deductible expense impact the income tax rate applied to pre-tax income in 2010 and pre-tax loss in 2009. Additionally, we recognized an assessment of $1.0 million in Canada related to a predecessor’s activities in 1997. The increase in our 2010 effective tax rate from the 2009 effective tax rate was primarily the result of U.S. and state income tax rates applied to the gains recognized from our sale of KGS and disposition of BBEP Units. For 2010, our effective rate in the U.S. was 36.0% and in Canada, excluding the $1.0 million assessment, it was 40.2%. Our U.S. operations generated 99% of our pre-tax income.

Quicksilver Resources Inc. and its Restricted Subsidiaries

Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 19 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 prior to October 1, 2010 consisted of KGS and its subsidiaries and the balances held by Fortune Creek which were included in the consolidated financial position as of December 31, 2011. 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

Operating Cash Flows

	Years Ended December 31,
	2011		2010		2009
	(In thousands)
Net cash provided by operating activities	$	253,053	$	397,720	$	612,303

Net cash provided by operations for 2011 decreased from 2010, primarily due to higher net payments to CMLP for GPT costs of $97 million and a $56 million decrease in production revenue due to our lower realized prices, partially offset by $18 million in settlement of litigation in 2010.

Net cash provided by operations for 2010 decreased from 2009, primarily due to our lower realized prices (including hedging effects), an increase in income tax payments and an increase in cash payments for interest. These reductions of operating cash were partially offset by a payment received for settlement of our BBEP litigation and an additional $9.8 million in BBEP distributions in 2010 as compared to 2009.

51

Investing Cash Flows

	Years Ended December 31,
	2011		2010		2009
	(In thousands)
Purchases of property, plant and equipment	$	(690,607)	$	(695,114)	$	(693,838)
Proceeds from sale of KGS		-		699,973		-
Proceeds from sale of BBEP units		272,965		34,016		-
Proceeds from sales of properties & equipment		4,163		9,953		220,974
Net cash provided (used) by investing activities	$	(413,479)	$	48,828	$	(472,864)

For each of the three years ended December 31, 2011, we have spent significant cash resources for the development of our large acreage positions in our core areas in the Barnett Shale and Horn River. During 2011, we sold 15.7 million BBEP Units for an average price of $17.40 or total proceeds of $273.0 million that was used to repay borrowings outstanding under our senior secured credit facilities. During 2010, we sold 2.0 million BBEP Units at an average price of $16.70 or total proceeds of $34.0 million. We completed several significant transactions during the years ended December 31, 2010 and 2009, including the Crestwood Transaction in 2010 with net cash proceeds of $700 million after transaction costs and the Eni Transaction in 2009 with net cash proceeds of $219.2 million.

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

The majority of the 2010 capital expenditures were associated with drilling, completion, and leasehold acquisition activity in the Barnett Shale which accounted for approximately 81% of the oil and gas related expenditures compared to only 45% in 2011.

We reduced our 2009 exploration and development activity from 2008 levels in response to lower natural gas and NGL prices. Of the $693.8 million of cash paid for property, plant and equipment during 2009, 79% was invested in our oil and gas properties and 20% was invested in our gas gathering and processing operations. Our 2009 midstream capital investment of $123.0 million was primarily related to expansion of our gas processing and gathering facilities in our Barnett Shale Asset.

52

Financing Cash Flows

	Years Ended December 31,
	2011		2010		2009
	(In thousands)
Net borrowings	$	12,714	$	(341,678)	$	(228,903)
Debt issuance costs		(12,506)		(3,111)		(32,472)
Partnership funds received		122,913		-		-
Gas Purchase Commitment		-		-		58,294
Gas Purchase Commitment repayments		-		(44,119)		(14,175)
Issuance of KGS common units		-		11,054		80,729
Distributions paid on KGS common units		-		(13,550)		(9,925)
Proceeds from exercise of stock options		1,299		1,801		4,046
Taxes paid on vesting of KGS equity compensation		-		(1,144)		(63)
Excess tax benefits on exercise of stock options		-		3,513		-
Purchase of treasury stock		(4,864)		(4,910)		(922)
Net cash provided (used) by financing activities	$	119,556	$	(392,144)	$	(143,391)

Net financing cash flows in 2011 include net borrowings of $227.5 million under our senior secured credit facilities and $122.9 million of funds received from Fortune Creek, partially offset by $48.4 million of purchases and retirement of our senior notes and repurchases of substantially all our $150 million convertible debentures. Financing cash flows in 2010 included $455 million to repay all outstanding balances on our 2007 Senior Secured Credit facility using a portion of the proceeds from the Crestwood Transaction. 2010 also included repayments of $44.1 million under the Gas Purchase Commitment.

Net financing cash flows for 2009 reflect our efforts to restructure and reduce our debt outstanding at December 31, 2008. In 2009, we received total proceeds of $873.1 million from the issuance of our senior notes due 2016 with a principal amount of $600 million and our senior notes due 2019 with a principal amount of $300 million. The senior notes due 2016 bear interest at the rate of 11.75% paid semiannually on January 1 and July 1. The senior notes due 2019 bear interest at the rate of 9.125% paid semiannually on February 15 and August 15. Borrowings and repayments in 2009 under the 2007 Senior Secured Credit Facility were $492 million and $890 million, respectively, which resulted in a net decrease of $398 million outstanding in 2009. KGS increased borrowings under the KGS Credit Agreement by $49.5 million in 2009. Proceeds from the debt issuances and the Eni Transaction in 2009 were used to repay and terminate the remaining indebtedness under our Senior Secured Second Lien Facility and to repay a portion of the outstanding borrowings under the 2007 Senior Secured Credit Facility. The KGS Secondary Offering, completed in December 2009, resulted in net proceeds of $80.3 million.

Liquidity and Borrowing Capacity

In September 2011, we terminated and replaced our $1.0 billion global 2007 Senior Secured Credit Facility with new five-year separate syndicated senior secured revolving credit facilities for our U.S. and Canadian operations. In December 2011, these facilities were amended and restated into the Combined Credit Agreements. “2011 Highlights” contains additional information about the changes to our debt.

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

53

Additional information about our debt and related covenants is more fully described in Note 11 to the consolidated financial statements in Item 8 of this Annual Report.

We believe that our capital resources are adequate to meet the requirements of our existing business. We anticipate that our 2012 capital program will be substantially funded by cash flow from operations, but expect that we will also draw on the Combined Credit Agreements. We are also pursuing joint ventures partners in our West Texas Asset and Horn River Asset.

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

Financial Position

The following impacted our balance sheet as of December 31, 2011, as compared to our balance sheet as of December 31, 2010:

Ÿ Our net property, plant and equipment balance increased $397 million from December 31, 2010 to December 31, 2011. We incurred capital expenditures of $694.5 million during 2011 and also recognized assets for retirement obligations established for new wells and facilities. DD&A and impairment expense and changes to U.S.—Canadian exchange rates reduced our property, plant and equipment balances $330.1 million and $13.6 million, respectively.

Ÿ The valuation of our current and non-current derivative assets and liabilities was $196 million higher on a net basis at December 31, 2011 as compared to December 31, 2010. The increase was primarily the result of recognized unrealized gains of $48.9 million associated with our 10-year natural gas price swaps prior to their designation as hedges and deferred unrealized gains of $229.1 million recognized in OCI partially offset by settlements received of $84.8 million.

Ÿ Our investment in BBEP Units decreased $83.3 million during 2011. In addition to recognizing $8.4 million in net losses from the earnings of BBEP, we received $19.8 million in dividends from BBEP and retired $55.1 million of our investment balance in connection with the sale of all our remaining 15.7 million BBEP Units.

Ÿ Long-term debt increased $156.7 million from net borrowings under our Combined Credit Agreements. We offset these borrowings with the repurchase of $150.0 million of our convertible debentures, and the repurchase of $48.4 million of our senior notes due 2015, 2016 and 2019.

54

Contractual Obligations and Commercial Commitments

Contractual Obligations

Information regarding our contractual and scheduled interest obligations, at December 31, 2011, 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	$	1,904,120	$	18	$	438,000	$	1,168,102	$	298,000
Scheduled interest obligations		762,227		166,639		484,739		66,743		44,106
GPT contracts		1,030,412		67,341		337,796		291,947		333,328
Drilling rig contracts		24,754		23,948		806		-		-
Purchase obligations		11,355		11,355		-		-		-
Asset retirement obligations		76,442		254		1,424		950		73,814
Unrecognized tax benefits		9,219		9,219		-		-		-
Operating lease obligations		40,747		5,484		13,351		6,570		15,342
Total obligations	$	3,859,276	$	284,258	$	1,276,116	$	1,534,312	$	764,590

Ÿ Long-Term Debt.  As of December 31, 2011, our outstanding indebtedness included $438 million of senior notes due 2015, $591 million of senior notes due 2016, $298 million of senior notes due 2019, $350 million of senior subordinated notes, and outstanding amounts under our Combined Credit Agreements. Based upon our debt outstanding and interest rates as of December 31, 2011, we anticipate interest payments, including our scheduled interest obligations, to be $167 million in 2012.

Ÿ Scheduled Interest Obligations.  As of December 31, 2011, we had scheduled interest payments of $36.1 million annually on our senior notes due 2015, $69.4 million annually on our senior notes due 2016, $27.2 million annually on our senior notes due 2019, $24.9 million annually on our $350 million of senior subordinated notes, and $9.0 million annually on our Combined Credit Agreements.

Ÿ 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.

Ÿ Drilling Rig Contracts.  We utilize drilling rigs from third parties in our development and exploration programs. The outstanding drilling rig contracts require payment of a specified day rate ranging from $12,500 to $27,005 for the entire lease term regardless of our utilization of the drilling rigs.

Ÿ Purchase Obligations.  At December 31, 2011, we were under contract to purchase goods and services for use in field and gas plant operations.

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

Ÿ Unrecognized Tax Benefits.  We have recorded obligations that have resulted from tax benefit claims in our tax returns that do not meet the recognition standard of more likely than not to be sustained upon examination by tax authorities. At December 31, 2011, $9.0 million of the unrecognized tax benefits, if recognized, would reduce our effective tax rate.

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

55

Commercial Commitments

We had the following commercial commitments as of December 31, 2011:

	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	$	9,072	$	9,072	$	-	$	-	$	-
Standby letters of credit		49,421		49,421		-		-		-
Total	$	58,493	$	58,493	$	-	$	-	$	-

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

Ÿ Standby Letters of Credit.  Our letters of credit have been issued to fulfill regulatory or contractual requirements including $32.1 million related to the NGTL Project as of December 31, 2011. All of these letters of credit were issued under our Combined Credit Agreements and generally have an annual renewal option. During 2012, we expect our utilization of letters of credit to increase in support of the NGTL Project and transportation contracts in our Horn River Asset by approximately $84.0 million.

Project and Expenditure Authorization

In April 2011, we entered into a Project and Expenditure Authorization (“PEA”) with NGTL, which supports the NGTL Project through our commitment for future delivery of gas from our Horn River Asset. In order to deliver gas that meets NGTL’s specifications, we, through Fortune Creek, will construct a treatment facility for our gas. Under the PEA, we agreed to provide financial assurances to cover NGTL’s costs for the NGTL Project, estimated to be C$257.4 million including taxes of approximately C$27.6 million, which is estimated to occur in stages based on NGTL’s forecast of the NGTL Project costs, in the following cumulative amounts:

	NGTL Cumulative Financial Assurances (1)
	(C$ in thousands)		(US$ in thousands)
July 1, 2012	$	68,264	$	67,124
October 1, 2012		109,816	$	107,982
July 1, 2013		148,400	$	145,922
October 1, 2013		257,400	$	253,101

⁽¹⁾ A letter of credit for C$32.6 million is outstanding for the NGTL Project as of December 31, 2011.

The PEA also requires that we execute firm transportation agreements for delivery of a minimum volume of gas of approximately 100 Mmcfd, increasing to 300 Mmcfd, over a ten-year term commencing with the in-service date of the NGTL Project.

The PEA may be terminated prior to completion of the NGTL Project for various reasons, including the failure to obtain NEB approval upon terms and conditions satisfactory to NGTL. Upon early termination, we must pay actual costs incurred or paid by NGTL, or for which NGTL is liable, as of the termination date except in certain limited situations. In the event that the termination occurs, we would pay those costs plus approximately C$26 million with the option to purchase for an additional $1.

Commitment Letter Agreement

In April 2011, we entered into a Commitment Letter Agreement (the “Commitment Letter”) with NGTL. Under the Commitment Letter, we agreed to deliver gas to NGTL beginning upon commissioning one of

56

its pipelines. The obligation terminates on the earlier of NGTL’s recovery of project costs or upon delivery of 1 Tcf cumulatively from us and any third-party producers. If neither has occurred by the end of the term of the transportation agreements, we will be required to renew the contract on an annual basis for a minimum volume of 106 Mmcfd until either the cost recovery or volume delivery requirements have been met. The Commitment Letter terminates if the PEA terminates for any reason other than the completion of the NGTL Project.

CRITICAL ACCOUNTING ESTIMATES

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

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

Oil and Gas Reserves

Policy Description

Proved oil and gas reserves are the estimated quantities of oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Under the current rule adopted by the SEC in December 2008, we incorporated the following changes into our proved reserve process and related disclosures for 2011, 2010 and 2009:

Ÿ the use of 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;

Ÿ consideration of and limitations on the types of technologies that may be used to reliably establish and estimate proved reserves;

Ÿ reporting of investments and progress made during the year to convert proved undeveloped reserves to proved developed reserves; and,

Ÿ reporting on the independence and qualifications of our personnel and independent petroleum engineers who are responsible for the preparation of our reserve estimates.

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. Our proved reserve estimates and related disclosures for 2011, 2010 and 2009 are presented in compliance with this new rule.

The current SEC rule allows the recognition of PUD reserves to be booked beyond one offset location where reliable technology exists that establishes reasonable certainty of economic producibility at greater distances, whereas the prior rule allowed recognizing only one offset. In accordance with the current rule, we recognized incremental PUD locations in our Barnett Shale Asset. In our Barnett Shale Asset, we had 341 proved

57

undeveloped gas well locations at December 31, 2011, including 60 locations that are more than one offset. Additional information regarding our proved oil and gas reserves may be found under “Oil and Natural Gas Reserves” found in Item 1 of this Annual Report.

Judgments and Assumptions

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

The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. The weighted average annual revisions to our reserve estimates over the last four years have been less than 3% 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 a ceiling test-related impairment. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling limitation, estimation of proved reserves is also a significant component of the calculation of depletion expense. For example, if estimates of proved reserves decline, the depletion rate will increase, resulting in a decrease in net income.

Full Cost Ceiling Calculations

Policy Description

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

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

Judgments and Assumptions

The discounted present value of future net cash flows from our proved oil, natural gas and NGL reserves is the major component of the ceiling calculation, and is determined in connection with the estimation of our proved oil, natural gas and NGL reserves. Estimates of reserves are forecasts based on engineering data,

58

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 quantities of proved reserves require substantial judgment, the associated prices of natural gas, NGL and oil reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. The current SEC rule requires the use of the future net cash flows from proved reserves discounted at 10%. Therefore, the future net cash flows associated with the proved reserves is not based on our assessment of future prices or costs. In calculating the ceiling, we adjust the future net cash flows by the discounted value of derivative contracts in place that hedge future prices. This valuation is determined by calculating the difference between reserve pricing and the contract prices for such hedges also discounted at 10%.

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

Derivative Instruments

Policy Description

We enter into financial derivative instruments to mitigate risk associated with the prices received from our production. We may also utilize financial derivative instruments to hedge the risk associated with interest rates on our outstanding debt. We account for our derivative instruments by recognizing qualifying derivative instruments on our balance sheet as either assets or liabilities measured at their fair value determined by reference to published future market prices and interest rates.

To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, includes performing regression analysis and is generally based on the most recent relevant historical correlation between the derivative and the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as revenue or interest expense when the underlying transaction occurs.

For derivative instruments that qualify as cash flow hedges, the effective portions of gains or losses are deferred in accumulated other comprehensive income and recognized in earnings during the period in which the hedged transactions are realized. Gains or losses on qualified derivative instruments terminated prior to their original expiration date are deferred and recognized as income or expense in the period in which the hedged transaction is recognized. If the hedged transaction becomes probable of not occurring, the deferred gain or loss is immediately recorded to earnings. The ineffective portion of the hedge relationship is recognized currently as a component of other revenue.

The fair values of natural gas and NGL derivatives are estimated using published market prices of natural gas and NGLs for the periods covered by the contracts. Estimates are determined by applying the net differential between the prices in each derivative and market prices for future periods, to the volume stipulated in each contract to arrive at an estimated value of future cash flow streams. These estimated future cash flow values are then discounted for each contract at rates commensurate with federal treasury instruments with similar contractual lives to arrive at estimated fair value.

For derivative instruments that qualify as fair value hedges the gains or losses on the derivative instruments are recognized currently in earnings and the changes in value of the hedged items are also recognized currently in

59

earnings. Any gains or losses on the derivative instruments not offset by the gains or losses on the hedged items are recognized as the value of ineffectiveness in the hedge relationships. For interest rate swaps that qualify as fair value hedges of our fixed-rate debt outstanding, ineffectiveness is recognized currently as a component of interest expense.

The fair value of all interest rate derivatives is estimated using published LIBOR interest rates for the periods covered by the contracts. The estimates are determined by applying the net differential between the interest rate in each derivative and interest rates for future periods, to the notional amount stipulated in each contract to arrive at estimated future cash flow streams.

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

Judgments and Assumptions

The estimates of the fair values of our commodity and interest rate derivative instruments require substantial judgment. Valuations are based upon multiple factors such as futures prices, volatility data from major oil and gas trading points, length of time to maturity 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.

Stock-Based Compensation

Policy Description

An estimate of fair value is determined for all share-based payment awards. Recognition of compensation expense for all share-based payment awards is recognized over the vesting period for each award.

Judgments and Assumptions

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

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

Income Taxes

Policy Description

Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that we expect will be

60

in effect during years in which we expect the temporary differences will reverse. Canadian taxes are computed at rates in effect or expected to be in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested in Canada and thus are not considered available for distribution to us. 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 and provide judgment on the amount of financial statement benefit that an uncertain tax position will realize upon ultimate settlement. To the extent that we believe that a more than 50% probability exists that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. Significant management judgment is required in determining any valuation allowance recorded against deferred tax assets and in determining the amount of financial statement benefit to record for uncertain tax positions. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed and 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. Evidence used for the valuation allowance includes information about our current financial position and results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax assets and liabilities and tax planning strategies available to us. To the extent that a valuation allowance or uncertain tax position is established or changed during any period, we would recognize expense or benefit within our consolidated tax expense.

OFF-BALANCE SHEET ARRANGEMENTS

Our contracts with NGTL provide financial assurances to it during the construction phase of the NGTL Project, which is expected to continue through 2014. Assuming the project is fully constructed at estimated costs of C$257.4 million, we expect to provide letters of credit through 2014. Note 14 to the consolidated financial statements found in Item 8 of this Annual Report contains additional information about our contracts with NGTL.

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.

61

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. As of December 31, 2011, the following forecasted production has been hedged with price collars or price swaps.

Production Year	Daily Production Volume
	Gas	NGL
	MMcfd	MBbld
2012	165	7
2013	105	-
2014-2015	65	-
2016-2021	35	-

Utilization of our financial hedging program will most often result in realized prices from the sale of our natural gas, NGL and oil that vary from market prices. As a result of settlements of derivative contracts, our revenue from natural gas, NGL and oil production was greater by $84.8 million, $248.9 million and $310.9 million for 2011, 2010 and 2009, respectively.

The following table details our open derivative positions at December 31, 2011:

					Remaining Contract Period		Volume		Weighted Avg Price Per Mcf or Bbl		Fair Value
Country	Product		Type								Total		2012		2013		2014		2015		2016		Thereafter
											(In thousands)
US		Gas		Collar		Jan 2012-Dec 2012		20 MMcfd	$	6.50-7.15		23,862		23,862		-		-		-		-		-
US		Gas		Collar		Jan 2012-Dec 2012		20 MMcfd		6.50-7.18		23,963		23,963		-		-		-		-		-
US		Gas		Collar		Jan 2012-Dec 2012		20 MMcfd		6.50-8.01		23,803		23,803		-		-		-		-		-
Canada		Gas		Swap		Jan 2012-Dec 2013		10 MMcfd	$	5.00		10,290		6,441		3,849
Canada		Gas		Swap		Jan 2012-Dec 2021		10 MMcfd		6.22		44,330		10,807		8,080		6,543		5,542		4,588		8,770
Canada		Gas		Swap		Jan 2012-Dec 2021		5 MMcfd		6.20		21,832		5,367		4,005		3,237		2,737		2,261		4,225
Canada		Gas		Swap		Jan 2012-Dec 2021		5 MMcfd		6.20		21,832		5,367		4,005		3,237		2,737		2,261		4,225
US		Gas		Swap		Jan 2012-Dec 2013		10 MMcfd		5.00		10,290		6,441		3,849		-		-		-		-
US		Gas		Swap		Jan 2012-Dec 2013		10 MMcfd		5.00		10,290		6,441		3,849		-		-		-		-
US		Gas		Swap		Jan 2012-Dec 2013		10 MMcfd		5.00		10,290		6,441		3,849		-		-		-		-
US		Gas		Swap		Jan 2012-Dec 2015		10 MMcfd		6.00		28,510		10,078		7,446		5,970		5,016		-		-
US		Gas		Swap		Jan 2012-Dec 2015		20 MMcfd		6.00		57,018		20,156		14,892		11,940		10,030		-		-
US		Gas		Swap		Jan 2012-Dec 2021		5 MMcfd		6.23		22,331		5,422		4,058		3,289		2,788		2,311		4,463
US		Gas		Swap		Jan 2012-Dec 2021		5 MMcfd		6.20		21,832		5,367		4,005		3,237		2,737		2,261		4,225
US		Gas		Swap		Jan 2012-Dec 2021		5 MMcfd		6.20		21,832		5,367		4,005		3,237		2,737		2,261		4,225
US		NGL		Swap		Jan 2012-Dec 2012		1 MBbld		42.81		(1,733)		(1,733)		-		-		-		-		-
US		NGL		Swap		Jan 2012-Dec 2012		1 MBbld		43.07		(1,639)		(1,639)		-		-		-		-		-
US		NGL		Swap		Jan 2012-Dec 2012		2 MBbld		43.94		(2,639)		(2,639)		-		-		-		-		-
US		NGL		Swap		Jan 2012-Dec 2012		1 MBbld		47.99		161		161		-		-		-		-		-
US		NGL		Swap		Jan 2012-Dec 2012		1 MBbld		46.55		(364)		(364)		-		-		-		-		-
US		NGL		Swap		Jan 2012-Dec 2012		1 MBbld		46.75		(292)		(292)		-		-		-		-		-
						Grand Total					$	345,799	$	158,817	$	65,892	$	40,690	$	34,324	$	15,943	$	30,133

During February 2012, we revamped our hedge platform. Through terminations of a portion of our existing natural gas hedge positions, we executed a new series of hedges that accomplish a revised natural gas hedging platform of:

Production Year	Daily Production		Floor		Cap
	Mmbtud
2012		220	$	5.78	$	6.04
2013		150		5.40		5.40
2014 - 2015		110		5.54		5.54

62

These hedges did not result in the transfer or the receipt of any net cash proceeds. We expect our entire hedge portfolio to continue to qualify for hedge accounting.

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.

Interest Rate Risk

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. For 2011, 2010 and 2009, interest expense decreased $4.8 million, $14.0 million and $13.7 million, respectively, because of our interest rate swaps.

Should we be required to borrow under our Combined Credit Agreements and based on interest rates as of December 31, 2011, each $50 million in borrowings would result in additional annual interest payments of $1.1 million. If the current borrowing availability under our Combined Credit Agreements were to be fully utilized by year-end 2012 at interest rates as of December 31, 2011, we estimate that annual interest payments would increase by $26.1 million. If interest rates change by 1% on our December 31, 2011 variable debt balances of $227.5 million our annual pre-tax income would decrease or increase by $2.3 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. For 2011, 2010 and 2009, non-functional currency transactions resulted in losses of $2.5 million, $0.5 million, and $2.2 million, respectively, included in net earnings. 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.

63

ITEM 8. Financial Statements and Supplementary Data

QUICKSILVER RESOURCES INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm		65
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) for the Years Ended December 31, 2011, 2010 and 2009		66
Consolidated Balance Sheets as of December 31, 2011 and 2010		67
Consolidated Statements of Equity for the Years ended December 31, 2011, 2010 and 2009		68
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		69
Notes to Consolidated Financial Statements for the Years Ended December 31, 2011, 2010 and 2009		70
Supplemental Selected Quarterly Financial Data (Unaudited)		107
Supplemental Oil and Gas Information (Unaudited)		108

64

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Quicksilver Resources Inc.

Fort Worth, Texas

We have audited the accompanying consolidated balance sheets of Quicksilver Resources Inc. and subsidiaries (the “Company”) as of December 31, 2011 and 2010, 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, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the 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, such consolidated financial statements present fairly, in all material respects, the financial position of Quicksilver Resources Inc. and subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, on December 31, 2009, the Company adopted Accounting Standards Update No. 2010-3, “Oil and Gas Reserve Estimation and Disclosures.”

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 15, 2012 expressed an adverse opinion on the effectiveness of the Company's internal control over financial reporting because of a material weakness.

/s/ Deloitte & Touche LLP

Fort Worth, Texas

April 15, 2012

65

QUICKSILVER RESOURCES INC.

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

FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009

In thousands, except for per share data

	2011			2010 (1)			2009
				(Restated)
Revenue
Production	$	800,543		$	856,349		$	796,698
Sales of purchased natural gas		86,645			64,089			23,654
Other		56,435			7,893			12,383
Total revenue		943,623			928,331			832,735
Operating expense
Lease operating		102,874			84,836			79,027
Gathering, processing and transportation		190,560			94,008			48,688
Production and ad valorem taxes		29,226			34,156			23,881
Costs of purchased natural gas		85,398			65,321			30,158
Other operating		557			4,522			6,684
Depletion, depreciation and accretion		225,763			207,203			201,387
Impairment		107,059			47,997			979,540
General and administrative		79,582			80,107			77,243
Total expense		821,019			618,150			1,446,608
Gain on sale of KGS (1)		-			493,953			-
Operating income (loss)		122,604			804,134			(613,873	)
Income (loss) from earnings of BBEP		(8,439	)		22,323			75,444
Impairment of investment in BBEP		-			-			(102,084	)
Other income (expense) - net		219,768			75,724			(1,242	)
Interest expense		(186,024	)		(188,353	)		(195,101	)
Income (loss) before income taxes		147,909			713,828			(836,856	)
Income tax (expense) benefit		(57,863	)		(258,538	)		291,617
Net income (loss)		90,046			455,290			(545,239	)
Net income attributable to noncontrolling interests		-			(9,724	)		(12,234	)
Net income (loss) attributable to Quicksilver	$	90,046		$	445,566		$	(557,473	)
Other comprehensive income (loss)
Reclassification adjustments related to settlements of derivative contracts - net of income tax		(58,125	)		(164,016	)		(211,863	)
Net change in derivative fair value - net of income tax		156,160			156,850			125,989
Foreign currency translation adjustment		(13,364	)		16,017			22,106
Comprehensive income (loss)	$	174,717		$	454,417		$	(621,241	)
Earnings (loss) per common share - basic	$	0.53		$	2.62		$	(3.30	)
Earnings (loss) per common share - diluted	$	0.52		$	2.50		$	(3.30	)

⁽¹⁾ Note 2 contains additional information.

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

66

QUICKSILVER RESOURCES INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2011 AND 2010

In thousands, except for share data

	2011			2010 (1)
				(Restated)
ASSETS
Current assets
Cash and cash equivalents	$	13,146		$	54,937
Accounts receivable - net of allowance for doubtful accounts		95,282			63,380
Derivative assets at fair value		162,845			89,205
Other current assets		29,154			30,650
Total current assets		300,427			238,172
Investment in equity-method affiliates		-			83,341
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $433,341 and $314,543, respectively)		3,226,476			2,840,319
Other property and equipment		234,043			222,926
Property, plant and equipment - net		3,460,519			3,063,245
Assets of midstream operations held for sale		-			27,178
Derivative assets at fair value		183,982			57,557
Other assets		50,534			38,241
	$	3,995,462		$	3,507,734
LIABILITIES AND EQUITY
Current liabilities
Current portion of long-term debt	$	18		$	143,478
Accounts payable		142,672			147,108
Accrued liabilities		142,193			122,904
Derivative liabilities at fair value		4,028			-
Current deferred tax liability		45,262			28,861
Total current liabilities		334,173			442,351
Long-term debt		1,903,431			1,746,716
Liabilities of midstream operations held for sale		-			1,431
Partnership liability		122,913			-
Asset retirement obligations		85,568			56,235
Other liabilities		28,461			28,461
Deferred income taxes		258,997			162,635
Commitments and contingencies (Note 14)
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 176,980,483 and 175,524,816 shares issued, respectively		1,770			1,755
Additional paid in capital		737,015			714,869
Treasury stock of 5,379,702 and 5,050,450 shares, respectively		(46,351	)		(41,487	)
Accumulated other comprehensive income		214,858			130,187
Retained earnings		354,627			264,581
Total equity		1,261,919			1,069,905
	$	3,995,462		$	3,507,734

⁽¹⁾ Note 2 contains additional information.

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

67

QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009

In thousands

	Quicksilver Resources Inc. Stockholders’ Equity
	Common Stock		Additional Paid-in Capital			Treasury   Stock			Accumulated Other Comprehensive Income			Retained Earnings  (1)			Noncontrolling Interest			Total
Balances at December 31. 2008		1,717		656,958			(35,441	)		185,104			376,488			26,737			1,211,563
Net income (loss)		-		-			-			-			(557,473	)		12,234			(545,239	)
Hedge settlements reclassified into earnings from AOCI, net of income tax of $99,004		-		-			-			(211,863	)		-			-			(211,863	)
Net change in derivative fair value, net of income tax of $57,007		-		-			-			125,989			-			-			125,989
Foreign currency translation adjustment		-		-			-			22,106			-			-			22,106
Issuance & vesting of stock compensation		22		19,085			(922	)		-			-			1,645			19,830
Stock option exercises		6		4,040			-			-			-			-			4,046
Issuance of KGS units		-		50,182			-			-			-			30,133			80,315
Distributions paid on KGS units		-		-			-			-			-			(9,925	)		(9,925	)
Balances at December 31. 2009		1,745		730,265			(36,363	)		121,336			(180,985	)		60,824			696,822
Net income (1)		-		-			-			-			445,566			9,724			455,290
Hedge settlements reclassified into earnings from AOCI, net of income tax of $84,835		-		-			-			(164,016	)		-			-			(164,016	)
Net change in derivative fair value, net of income tax of $78,616		-		-			-			156,850			-			-			156,850
Foreign currency translation adjustment		-		-			-			16,017			-			-			16,017
Issuance & vesting of stock compensation		7		23,531			(5,124	)		-			-			4,339			22,753
Stock option exercises		3		2,012			-			-			-			-			2,015
Issuance of KGS units		-		6,746			-			-			-			4,308			11,054
Distributions paid on KGS units		-		-			-			-			-			(13,550	)		(13,550	)
Disposition of KGS partnership interests		-		(47,685	)		-			-			-			(65,645	)		(113,330	)
Balances at December 31. 2010, restated (1)	$	1,755	$	714,869		$	(41,487	)	$	130,187		$	264,581		$	-		$	1,069,905
Net income		-		-			-			-			90,046			-			90,046
Hedge settlements reclassified into earnings from AOCI, net of income tax of $26,679		-		-			-			(58,125	)		-			-			(58,125	)
Net change in derivative fair value, net of income tax of $73,339		-		-			-			156,160			-			-			156,160
Foreign currency translation adjustment		-		-			-			(13,364	)		-			-			(13,364	)
Issuance & vesting of stock compensation		13		20,849			(4,864	)		-			-			-			15,998
Stock option exercises		2		1,297			-			-			-			-			1,299
Balances at December 31. 2011	$	1,770	$	737,015		$	(46,351	)	$	214,858		$	354,627		$	-		$	1,261,919

⁽¹⁾  Note 2 contains additional information.

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

68

QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS END DECEMBER 31, 2011, 2010 AND 2009

In thousands

	2011			2010 (1)			2009
				(Restated)
Operating activities:
Net income (loss)	$	90,046		$	455,290		$	(545,239	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion		225,763			207,203			201,387
Impairment expense		107,059			47,997			979,540
Deferred income tax expense (benefit)		64,492			185,367			(291,414	)
Non-cash (gain) loss from hedging and derivative activities		(51,780	)		(58,892	)		6,756
Gain on sale of KGS		-			(493,953	)		-
Divestiture expenses		-			2,555			-
Stock-based compensation		20,862			25,990			20,815
Non-cash interest expense		16,510			17,226			45,532
Gain on disposition of BBEP units		(217,893	)		(57,584	)		-
Loss (income) from BBEP in excess of cash distributions		28,269			(1,417	)		(64,344	)
Impairment of investment in BBEP		-			-			102,084
Other		1,311			(168	)		747
Changes in assets and liabilities
Accounts receivable		(31,803	)		(9,501	)		77,527
Derivative assets at fair value		-			30,816			54,896
Prepaid expenses and other assets		(6,017	)		6,364			3,061
Accounts payable		(11,434	)		33,957			(12,320	)
Income taxes payable		(4,803	)		4,611			60
Accrued and other liabilities		22,471			1,859			33,215
Net cash provided by operating activities		253,053			397,720			612,303
Investing activities:
Capital expenditures		(690,607	)		(695,114	)		(693,838	)
Proceeds from sale of KGS		-			699,973			-
Proceeds from sale of BBEP units		272,965			34,016			-
Proceeds from sale of properties and equipment		4,163			9,953			220,974
Net cash provided (used) by investing activities		(413,479	)		48,828			(472,864	)
Financing activities:
Issuance of debt		855,822			690,058			1,420,727
Repayments of debt		(843,108	)		(1,031,736	)		(1,649,630	)
Debt issuance costs paid		(12,506	)		(3,111	)		(32,472	)
Partnership funds received		122,913			-			-
Gas Purchase Commitment assumed		-			-			58,294
Gas Purchase Commitment repayments		-			(44,119	)		(14,175	)
Issuance of KGS common units - net offering costs		-			11,054			80,729
Distributions paid on KGS common units		-			(13,550	)		(9,925	)
Proceeds from exercise of stock options		1,299			1,801			4,046
Excess tax benefits on exercise of stock options		-			3,513			-
Taxes paid on vesting of KGS equity compensation		-			(1,144	)		(63	)
Purchase of treasury stock		(4,864	)		(4,910	)		(922	)
Net cash provided (used) by financing activities		119,556			(392,144	)		(143,391	)
Effect of exchange rate changes in cash		(921	)		(1,252	)		2,889
Net change in cash		(41,791	)		53,152			(1,063	)
Cash and cash equivalents at beginning of period		54,937			1,785			2,848
Cash and cash equivalents at end of period	$	13,146		$	54,937		$	1,785

⁽¹⁾  Note 2 contains additional information.

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

69

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009

1. NATURE OF OPERATIONS

We are an independent oil and gas company incorporated in the state of Delaware and headquartered in Fort Worth, Texas. We engage in the acquisition, exploration, development, production and sale of natural gas, NGLs and oil in North America. As of December 31, 2011, our significant oil and gas reserves and operations are located in:

• Texas

• U.S. Rocky Mountains

• Alberta

• British Columbia

We have offices located in:

• Fort Worth, Texas

• Glen Rose, Texas

• Cut Bank, Montana

• Steamboat Springs, Colorado

• Calgary, Alberta

• Fort Nelson, British Columbia

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

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Use of Estimates

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

Significant estimates underlying these financial statements include the estimated quantities of proved natural gas, NGL and oil reserves (including the associated future net cash flows from those proved 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 values of

70

derivatives, asset retirement obligations and employee 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 natural gas, NGL and oil production to various purchasers. Each of our counterparties is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although we do not 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 2011, two purchasers individually accounted for 15% and 11% of cash collected for our consolidated natural gas, NGL and oil sales. During 2010, two purchasers individually accounted for 17% and 12% of cash collected for our consolidated natural gas, NGL and oil sales.

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.

To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, includes performing regression analysis and is generally based on the most recent relevant historical correlation between the derivative and the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as revenue or interest expense when the underlying transaction occurs.

For derivatives that qualify as cash flow hedges, the effective portions of gains and losses are deferred in accumulated other comprehensive income and recognized in revenue or interest expense in the period in which the hedged transaction is recognized. Gains or losses on derivatives terminated prior to their original expiration date are deferred and recognized as earnings during the period that the hedge covered. If the hedged transaction is no longer probable, the deferred gain or loss would be immediately recorded to earnings. Changes in value of ineffective portions of hedges, if any, are recognized currently as a component of other revenue.

For derivatives that qualify as fair value hedges, such as interest rate swaps, the gains or losses are recognized currently in earnings, while the gains or losses on the hedged items adjust the carrying value of the hedged items and are recognized currently in earnings. Any gains or losses on the derivatives not offset by the gains or losses on the hedged items are recognized as the value of ineffectiveness in the hedge relationships.

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

71

Investments in Equity Affiliates

During December 2011, we liquidated our investment in BBEP which we had accounted for using the equity method. Prior to this liquidation, we reviewed our investment for impairment whenever events or circumstances indicated that the investment’s carrying amount may not be recoverable. We recorded our portion of BBEP’s earnings during the quarter in which its financial statements become publicly available. Consequently, our 2011, 2010 and 2009 annual results of operations include BBEP’s earnings for the 12 months ended September 30, 2011, 2010 and 2009. Note 7 contains more information on our BBEP investment.

Property, Plant, and Equipment

We follow the full cost method in accounting for our oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in 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 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 oil and gas reserves. We may exclude costs associated with unevaluated properties from amounts subject to depletion.

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

All 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.

Inventory

Inventories were comprised of $23.2 million and $25.3 million of materials and parts and $2.3 million and $2.1 million of NGLs as of December 31, 2011 and 2010, respectively. Our materials, parts and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, chemicals, operating supplies and ordinary maintenance materials and parts. The materials, parts and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. “Market,” in the context of inventory valuation, represents net realizable value, which is the amount that we are allowed to bill to the joint accounts under joint operating agreements to which we are a party. Impairments for materials and supplies inventories are recorded as lease operating expense in the accompanying consolidated statements of operations.

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 fair value to its estimated settlement value.

72

Revenue Recognition

Revenue is recognized when title to the products transfer 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, 2011 and 2010, our aggregate production imbalances were not material.

Environmental Compliance and Remediation

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

Debt

We record all debt instruments at face value. When an issuance of debt is made at other than par, a discount or premium is separately recorded. The discount or premium is amortized over the life of the debt using the effective interest method. We separately accounted for the liability and equity components of our convertible debentures, which resulted in our recognizing interest expense at our effective borrowing rate in effect at the time of issuance. Note 11 contains further information regarding our convertible debentures.

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. 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.

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 all awards, 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.

Disclosure of Fair Value of Financial Instruments

Our financial instruments include cash, 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. Gains and losses from foreign currency transactions are included in the consolidated results of operations.

73

Noncontrolling Interests in Consolidated Subsidiaries

Noncontrolling interests reflect the fractional outside ownership of our majority-owned and consolidated subsidiaries. Until we sold all of our interests in KGS in October 2010, we included the results of operations and financial position of KGS in our consolidated financial statements and recognized the portion of KGS’ results of operations attributable to unaffiliated unitholders as a component of “income attributable to noncontrolling interests.”

Immaterial Restatement

The consolidated financial statements as of and for the year ended December 31, 2010 have been restated to increase the previously recognized gain related to the sale of our interests in KGS by $20.7 million and to provide additional deferred taxes on the increased gain. The previously reported gain excluded certain liabilities for intercompany transactions related to services performed by KGS for our U.S. exploration and production segment, which should have been included in the gain calculation. Additional depletion expense was recognized due to the inclusion of additional future development costs in the 2010 depletion calculation. The results of this restatement, which had no impact on our total cash flow from operations, investing and financing activities as reported, were as follows:

Consolidated Statement of Income (Loss) and Comprehensive Income

For the year ended December 31, 2010

	Previously reported		Restated
Gain on sale of KGS	$	473,204	$	493,953
Depletion, depreciation and accretion		202,603		207,203
Operating income		787,985		804,134
Income before income taxes		697,679		713,828
Income tax expense		252,886		258,538
Net income		444,793		455,290
Net income attributable to Quicksilver		435,069		445,566
Comprehensive income		443,920		454,417
Earnings per common share - basic	$	2.56	$	2.62
Earnings per common share - diluted	$	2.45	$	2.50
Consolidated Balance Sheet as of December 31, 2010
	Previously reported		Restated
Oil and gas properties, full cost method	$	2,844,919	$	2,840,319
Property, plant and equipment, net		3,067,845		3,063,245
Accounts payable		167,857		147,108
Total current liabilities		463,100		442,351
Deferred income taxes		156,983		162,635
Retained earnings		254,084		264,581
Total equity		1,059,408		1,069,905

In addition to the restatement as described above, we restated amounts within the condensed consolidating financial information which is more fully described in Note 19. The effects of these restatements did not have an effect on retained earnings as of or prior to December 31, 2009.

Variable Interest Entities

An entity is a variable interest entity (VIE) if it meets the criteria outlined in ASC 810, Consolidation (formerly FASB Interpretation No. 46(R)), which are: (1) the entity has equity that is insufficient to permit the

74

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

In December 2011, we began to include the financial position of Fortune Creek in our consolidated financial statements. The results from operations for Fortune Creek for 2011 were immaterial. Note 16 contains additional discussion regarding the Fortune Creek.

Earnings per Share

We report basic earnings per common share, which excludes the effect of potentially diluted securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. The calculation of earnings per share is found at Note 18.

Recently Issued Accounting Standards

Accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements materially affecting our financial statements have been issued since the filing of our 2010 Annual Report on Form 10-K.

3.     ACQUISITIONS AND DIVESTITURES

2010 Crestwood Transaction and Midstream Operations

In October 2010, we completed the sale of all of our interests in KGS to Crestwood. The Crestwood Transaction included our conveying:

Ÿ a 100% ownership interest in Quicksilver Gas Services Holdings LLC, which owned;

Ÿ 5,696,752 common units of KGS;

Ÿ 11,513,625 subordinated units of KGS representing limited partner interests in KGS;

Ÿ 100% of the outstanding membership interests in Quicksilver Gas Services GP LLC including 469,944 general partner units in KGS and 100% of the outstanding incentive distribution rights in KGS; and,

Ÿ a subordinated promissory note issued to us by KGS with a carrying value of $58 million at September 30, 2010.

We received net proceeds of $700 million including $8.0 million from KGS for third quarter 2010 distributions and after transaction costs. We recognized a gain of $494.0 million. We have the right to collect up to an additional $72 million in future earn-out payments in 2012 and 2013, although we have recognized no assets related to these opportunities. In February 2012, we collected $41 million of these earn-out payments.

Under the agreements governing the Crestwood Transaction, we agreed not to compete with CMLP (to which KGS was renamed) with respect to the gathering, treating and processing of natural gas and the transportation of natural gas liquids in Denton, Hood, Somervell, Johnson, Tarrant, Parker, Bosque and Erath Counties in Texas. We also entered into an agreement with CMLP for the joint development of areas governed by certain of our existing agreements, and further, we amended our existing agreements. The most significant amendments include extending the terms of all gathering agreements with CMLP through 2020 and establishing a fixed gathering rate of $0.55 per Mcf for the gathering system in our Alliance Asset.

75

In September 2010, our board of directors approved a plan for disposal of the HCDS, which is included in our midstream segment. We conducted an impairment analysis of the HCDS and recognized a charge of $28.6 million for impairment in the third quarter of 2010. During the fourth quarter of 2011, we discontinued our efforts to actively market the HCDS assets to prospective buyers. GAAP also generally limits reporting such items as held for sale to one year. As a result, we have not reported the HCDS in our financial statements as an asset held for sale as of December 31, 2011. Further, we recognized an additional impairment charge of $10.3 million in 2011 for HCDS.

We have continued to report our interests sold in the Crestwood Transaction and the HCDS as part of our continuing operating results because our use of their midstream services constitutes a “continuation of service” that precludes presentation of those businesses as discontinued operations under GAAP.

The operating results of these midstream operations, as classified in our statement of income, are summarized below:

	For the Years Ended December 31,
	2010			2009
	(In thousands)
Revenue	$	13,119		$	9,342
Lease operating expense		-			-
PGT expense (1)		(57,679	)		(74,196	)
Ad valorem taxes		3,764			3,610
Other operations		3,444			5,233
DD&A		19,732			24,502
General and administrative expense		5,034			3,229
Impairment expense		28,611			-
Operating results of midstream operations		10,213			46,964
Interest and other expense		(6,916	)		(4,764	)
Results of midstream operations before income tax		3,297			42,200
Income tax expense		(1,265	)		(15,428	)
Results of midstream operations, net of income tax	$	2,032		$	26,772

⁽¹⁾  Our KGS operations earned revenue from processing and gathering of our natural gas and NGL production. This revenue was consolidated as a reduction of processing, gathering and transportation expense for purposes of presenting our consolidated statements of income.

2010 Lake Arlington Acquisition

In May 2010, we completed the acquisition of an additional 25% working interest in our company-operated Lake Arlington Asset, for which we conveyed $62.1 million in cash and 3,619,901 BBEP Units owned by us with a market value of $54.4 million on the date of closing. We recognized a gain of $35.4 million as other income for the difference between our carrying value of $5.24 per BBEP Unit and the fair value of $15.03 per BBEP Unit on the date of the transaction.

2009 Eni Transaction

In June 2009, we completed the Eni Transaction whereby we entered into a strategic alliance with Eni and sold a 27.5% interest in our Alliance Asset. The assets were sold to Eni for $279.7 million in cash, inclusive of the Gas Purchase Commitment assumed and normal post-closing adjustments. We used the proceeds generated to repay a portion of the Senior Secured Second Lien Facility.

76

In connection with the sale, we entered into a gas gathering agreement for a pre-set price with Eni covering Eni’s production. Under that agreement and subsequent agreements, CMLP will gather, treat and deliver Eni’s production. Eni paid $19.2 million to us for construction and installation of the facilities required to gather Eni’s production from future Alliance airport area wells. CMLP is now the sole owner of these facilities and is entitled to recognize gathering revenue for the volume of gas that are gathered.

Also as part of the sale, we entered into a joint development agreement with Eni. The joint development agreement includes a schedule of wells that we agreed to drill and complete with participation by Eni during the development period. In connection with the scheduled drilling of these wells, we have committed to drill and complete a minimum number of lateral feet each year. Eni agreed to pay us a turnkey drilling and completion cost of $994 per linear foot attributable to Eni. Through December 31, 2011 we had cumulatively completed 137,184 linear feet under the agreement, compared with a contract minimum of 130,743 feet. A total of 191,819 linear feet is required to be completed by December 31, 2013. Under the joint development agreement, we may be obligated to pay Eni for damages at the end of the development period should we fail to meet the linear footage requirements and certain production requirements have not been satisfied. We currently expect to satisfy these requirements and have recognized no liability related to non-performance.

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,
	2011		2010		2011		2010
	(in thousands)				(in thousands)
Level 2 inputs	$	195,838	$	146,762	$	4,028	$	-
Level 3 inputs		150,989		-		-		-
Total	$	346,827	$	146,762	$	4,028	$	-

The fair value of “Level 2” derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value reported by counterparties. The fair value of derivative instruments designated “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 hedges with an original tenure of 10 years utilize “Level 3” inputs, primarily related to comparatively less market data available for their later term compared with our other shorter term hedges. 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 the credit adjusted risk free rate.

77

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

	As of December 31,
	2011		2010
	(In thousands)
Balance at beginning of period	$	-	$	-
Total gains for the period:
Included in OCI		105,137		-
Included in earnings		45,852		-
Balance at end of period	$	150,989	$	-
Total gains for the period included in earnings attributable to the change in unrealized gains related to assets held at the reporting date	$	45,852	$	-

Commodity Price Derivatives

As of December 31, 2011, we had price collars and swaps hedging our anticipated natural gas and NGL production as follows:

Production	Daily Production Volume
Year	Gas	NGL
	MMcfd	MBbld
2012	165	7
2013	105	-
2014-2015	65	-
2016-2021	35	-

On August 31, 2011, we designated our 10-year natural gas swaps as hedges. Unrealized gains of $48.9 million were recognized from the date we entered into them through that date and have been reported in “other revenue.” After the designation date, additional unrealized gains and losses, net of hedge ineffectiveness, have been recognized in AOCI until the associated sale of natural gas production occurs. These gains were partially offset by a decrease in fair value of the related hedge assets due to credit risk of our counterparties as of December 31, 2011.

Interest Rate Derivatives

In June 2009, we entered into interest rate swaps on our $475 million senior notes due 2015 and our $350 million senior subordinated notes effectively converting the interest on those issues from a fixed to a floating rate indexed to a one-month LIBOR. The maturity dates and all other significant terms were the same as those of the underlying debt. Under these swaps, we paid a variable interest rate and received the fixed rate applicable to the underlying debt. The interest income or expense was accrued as earned and recorded as an adjustment to the interest expense accrued on the fixed-rate debt. The interest rate swaps were designated as fair value hedges of the underlying debt. The value of the contracts, excluding the net interest accrual, amounted to a net asset of $4.1 million and a $4.1 million offsetting fair value adjustment to the debt hedged as of December 31, 2009. No ineffectiveness was recorded in connection with the fair value hedges. The 2010 and 2009 average effective interest rates on the 2015 Senior Notes were 6.5% and 5.1%, respectively. The 2010 and 2009 average effective interest rates on the Senior Subordinated Notes were 5.4% and 3.7%, respectively.

In February 2010, we executed the early settlement of the 2009 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 $18.0 million in the settlement, including $3.7 million for interest previously accrued and earned, and recognized the remaining $14.3 million as a fair value adjustment to our debt.

In February 2010, we entered into new interest swaps to hedge the same debt instruments. We executed early settlement of a portion of the 2010 interest rate swaps in May 2010 and the remaining 2010 interest swaps

78

in July 2010 for $6.8 million and $16.7 million, respectively. These settlements included $7.0 million for interest previously accrued and earned. The remaining cash of $16.5 million was recognized as a fair value adjustment to our debt.

The remaining deferral of these early settlements from all interest rate swaps will continue to be recognized as a reduction of interest expense over the life of the associated underlying debt instruments currently scheduled as follows:

(In thousands)
2012	$	5,315
2013		5,769
2014		6,261
2015		4,824
2016		569
	$	22,738

Gas Purchase Commitment

We recognized a liability at the time of the Eni Transaction pursuant to the Gas Purchase Commitment based on the estimated production volume attributable to Eni through December 31, 2010, which then totaled 22.2 Bcf. The Gas Purchase Commitment contained an embedded derivative that was adjusted to fair value throughout the period of the commitment, which expired on December 31, 2010. The following summarizes activity to the Gas Purchase Commitment:

	As of December 31,
	2010
	(in thousands)
Beginning liability at fair value	$	50,744
Decrease due to gas volumes purchased		(35,057	)
Decrease due to changes in gas volumes		(9,062	)
Embedded derivative		(6,625	)
Ending liability at fair value	$	-

All Derivatives

The estimated fair value of all of our derivatives at December 31, 2011 and 2010 were as follows:

	Asset Derivatives				Liability Derivatives
	As of December 31,				As of December 31,
	2011		2010		2011		2010
	(In thousands)				(In thousands)
Derivatives designated as hedges:
Commodity contracts reported in:
Current derivative assets	$	165,484	$	97,863	$	2,639	$	8,658
Noncurrent derivative assets		183,982		63,419		-		5,862
Current derivative liabilities		-		-		4,028		-
Total derivatives designated as hedges	$	349,466	$	161,282	$	6,667	$	14,520
Total derivatives	$	349,466	$	161,282	$	6,667	$	14,520

The increase in carrying value of our commodity price derivatives since December 31, 2010 principally resulted from the overall decline in market prices for natural gas relative to the prices in our open derivative instruments at December 31, 2011 and due to more coverage of future production. These increases were partially offset by monthly settlements received during 2011.

79

The changes in the carrying value of our derivatives for 2011 and 2010 are presented below:

	For the Years Ended December 31,
	2011		2010
	Commodity		Gas Purchase		Fair Value		Commodity
	Derivatives		Commitment		Derivatives		Derivatives		Total
	(In thousands)
Derivative fair value at beginning of period		$  146,762		$    (6,625)		$    4,108		$  107,881		$  105,364
Change in net amounts receivable and payable		(759)		-		(9,180)		(3,451)		(12,631)
Net settlements reported in revenue		(84,046)		-		-		(190,504)		(190,504)
Net settlements reported in interest expense		-		-		(10,848)		-		(10,848)
Cash settlements reported in long-term debt		-		-		(30,816)		-		(30,816)
Unrealized change in fair value of Gas Purchase
Commitment reported in costs of purchased gas		-		6,625		-		-		6,625
Change in fair value of effective interest swaps		-		-		46,736		-		46,736
Ineffectiveness reported in other revenue		5,928		-		-		(2,629)		(2,629)
Unrealized gains reported in other revenue		45,852		-		-		-		-
Unrealized gains reported in OCI		229,062		-		-		235,465		235,465
Derivative fair value at end of period		$  342,799		$            -		$            -		$  146,762		$  146,762

Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during 2012 would result in a gain of $86.7 million net of income taxes. Hedge derivative ineffectiveness resulted in net gains of $5.9 million for 2011, and net losses of $2.6 million and $0.1 million for 2010 and 2009, respectively.

5. ACCOUNTS RECEIVABLE

Accounts receivable consisted of the following:

	As of December 31,
	2011		2010
	(In thousands)
Accrued production	$	57,220	$	36,144
Joint interest billings		7,770		8,172
Income taxes		13,332		17,368
Canadian value added taxes		14,750		-
Other		2,247		1,776
Allowance for doubtful accounts		(37)		(80)
	$	95,282	$	63,380

6. OTHER CURRENT ASSETS

Other current assets consisted of the following:

	As of December 31,
	2011		2010
	(In thousands)
Inventories	$	25,503	$	27,388
Deposits		391		597
Other prepaid expense		3,260		2,665
	$	29,154	$	30,650

80

7. INVESTMENT IN BBEP

At December 31, 2011, we no longer owned any BBEP Units. Note 3 contains additional information regarding the use of 3.6 million BBEP Units as partial consideration in the acquisition of oil and gas properties in May 2010. We further reduced our ownership in September 2010 when we sold 1.4 million BBEP Units at a unit price of $16.22, net of fees paid. We recognized a gain of $14.4 million as other income for the difference between our carrying value at the time of the sale of $5.82 per BBEP Unit and the net sales proceeds. In October 2010, we sold an additional 650,000 BBEP Units at a unit price of $17.72 and recognized a gain of $7.7 million.

Our ownership interest in BBEP was further reduced in February 2011 when BBEP issued approximately 4.9 million BBEP Units. During 2011, we eliminated our ownership through the sale of approximately 15.7 million BBEP Units at a weighted average unit sales price of $17.40. We recognized gains of $217.9 million as other income for the difference between our weighted average carrying value of $3.51 per BBEP Unit and the net sales proceeds.

We initially received 21.4 million BBEP Units during November 2007 as partial consideration of our oil and gas properties in Michigan, Indiana and Kentucky. On June 17, 2008, BBEP announced that it had repurchased and retired 14.4 million BBEP Units, which represented 22% of the units previously outstanding. The resulting reduction in the number of BBEP Units outstanding increased our ownership at the time from 32% to 41%.

After obtaining our BBEP Units, we evaluated our investment for impairment in response to decreases in both prevailing commodity prices and the BBEP Unit price. We considered numerous factors in evaluating whether this was an other-than-temporary decline. As a result of the period during which BBEP Units traded below our net carrying value per unit, prevailing petroleum prices and broad limitations on available capital resulted in the determination that this was an other-than-temporary decline. Accordingly, the impairment analysis at December 31, 2008 utilized a price of $7.05 per BBEP Unit, or an aggregate fair value of $150.5 million for our investment in BBEP. The estimated fair value of $150.5 million was then compared to our carrying value of $470.9 million. The difference of $320.4 million was recognized as an impairment charge during 2008.

At March 31, 2009, an additional charge for impairment of $102.1 million was recognized as the closing price of $6.53 per BBEP Unit, or an aggregate fair value of $139.4 million, exceeded our carrying value of $241.5 million. No subsequent impairment of our investment has occurred.

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

	For the Twelve Months Ended September 30,
	2011		2010			2009
	(In thousands)
Revenue (1)	$	425,386	$	375,446		$	609,846
Operating expense (2)		313,388		285,394			380,197
Operating income		111,998		90,052			229,649
Interest and other (3)		40,759		24,903			45,714
Income tax (benefit) expense		1,070		(939	)		323
Noncontrolling interests		183		146			27
Net income available to BBEP	$	69,986	$	65,942		$	183,585
Net income available to common unitholders	$	69,986	$	65,942		$	183,585

⁽¹⁾  For the twelve months ended September 30, 2011 and 2009, unrealized gains of $24.0 million and $181.9 million on commodity derivatives were recognized. For the twelve months ended September 30, 2010,

81

unrealized losses of $12.1 million on commodity derivatives were recognized. Realized gains on commodity derivatives of $70.6 million for the early settlement of derivative positions were included for the twelve months ended September 30, 2009.

⁽²⁾  An impairment of BBEP’s oil and gas properties of $86.4 million was included for the twelve months ended September 30, 2009.

⁽³⁾  The twelve months ended September 30, 2011, 2010 and 2009 included $3.3 million, $5.2 million and $11.1 million, respectively, for unrealized gains on interest rate swaps.

	As of September 30,
	2011		2010
	(In thousands)
Current assets	$	171,850	$	145,233
Property, plant and equipment		1,765,247		1,728,256
Other assets		104,264		98,113
Current liabilities		85,608		85,035
Long-term debt		511,489		516,000
Other non-current liabilities		55,042		64,715
Partners’ equity		1,389,222		1,305,852

Changes in the balance of our investment in BBEP for 2011 and 2010 were as follows:

	As of December 31,
	2011			2010
	(In thousands)
Beginning investment balance	$	83,341		$	112,763
Income (loss) from earnings in BBEP		(8,439	)		22,323
Distributions from BBEP		(19,830	)		(20,905	)
Disposal of BBEP Units		(55,072	)		(30,840	)
Ending investment balance	$	-		$	83,341

82

8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:

	As of December 31,
	2011		2010
	(In thousands)
Oil and gas properties
Subject to depletion	$	5,309,330	$	4,805,161
Unevaluated costs		433,341		314,543
Accumulated depletion		(2,516,195)		(2,279,385)
Net oil and gas properties		3,226,476		2,840,319
Other property and equipment
Pipelines and processing facilities		340,242		225,402
General properties		71,297		70,267
Accumulated depreciation		(177,496)		(72,743)
Net other property and equipment		234,043		222,926
Property, plant and equipment, net of accumulated depletion and depreciation	$	3,460,519	$	3,063,245

Ceiling Test Analysis and Impairment

The charges for impairment are summarized below:

		Pre-tax Charges for Impairment
	Segment	2011		2010		2009
		(in thousands)
U.S.
Oil and gas properties	Exploration and production	$	-	$	-	$	786,867
Other property and equipment	Midstream		57,996		28,611		-
Canada
Oil and gas properties	Exploration and production		49,063		19,386		192,673
		$	107,059	$	47,997	$	979,540

As described in Note 2, we are required to perform a quarterly ceiling test for impairment of our oil and gas properties in each of our cost centers. The charge for impairment in 2011 was recognized as a result of a 12% decrease in AECO natural gas price utilized in our Canadian ceiling test from December 31, 2010 to March 31, 2011. The charge for impairment in 2010 was recognized as a result of significant changes in our Canadian cost center for the initial producing wells in our Horn River Asset and associated field costs while new proved reserves recognized were limited because of the short production history for the area. We recognized charges for impairment of both our U.S. and Canadian cost centers during 2009 due to significant decreases in natural gas and NGL market prices.

In September 2010, our board of directors approved a plan for disposal of the HCDS. As a result of the decision, we conducted an impairment analysis of the HCDS and recognized a $28.6 million charge for impairment. During the third quarter 2011, we discontinued our efforts to actively market the HCDS assets and

83

re-assumed operating it from CMLP at which time we conducted a recovery test for impairment that did not result in an impairment charge. Based on decreased volumes and increased operating costs during the fourth quarter 2011, we recognized additional impairment of $13.3 million determined on a market-based approach to fair value. We also recognized an impairment charge of $44.7 million related to certain Barnett Shale midstream assets to reduce their carrying value to estimated fair value as a result of decreased development by us and others in response to decreased natural gas prices during the fourth quarter. This decrease in current and forecasted development coupled with CMLP’s inability to attract third parties to utilize their adjoining system is the underlying causes of the impairment. The resulting post-impairment carrying value equaled the discounted fair value of these assets’ future cash flows.

Because of the volatility of oil and natural gas prices, it is reasonably possible we may experience additional impairment in future periods.

Unevaluated Natural Gas and Oil Properties Not Subject to Depletion

Under full cost accounting, we may exclude certain unevaluated property costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties not subject to depletion at December 31, 2011 and 2010 and the year in which they were incurred follows:

	December 31, 2011 Costs Incurred During										December 31, 2010 Costs Incurred During
	2011		2010		2009		Prior		Total		2010		2009		2008		Prior		Total
	(In thousands)										(In thousands)
Acquisition costs	$	119,936	$	39,307	$	8,408	$	126,756	$	294,407	$	42,117	$	7,482	$	111,929	$	76,192	$	237,720
Exploration costs		58,944		31,644		21,389		11,056		123,033		36,383		21,531		7,616		-		65,530
Capitalized interest		6,613		2,769		3,219		3,300		15,901		4,874		2,866		3,553		-		11,293
Total	$	185,493	$	73,720	$	33,016	$	141,112	$	433,341	$	83,374	$	31,879	$	123,098	$	76,192	$	314,543

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

	As of December 31,
	2011		2010
	(In thousands)
Barnett Shale	$	68,351	$	121,854
West Texas		49,750		-
Horn River Basin		180,604		160,663
Sandwash Basin		132,965		30,688
Other		1,671		1,338
Total	$	433,341	$	314,543

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 will require an estimated eight to ten years of exploration and development activity before evaluation is complete.

Other Matters

Capitalized overhead costs that directly relate to exploration and development activities were $18.3 million, $17.7 million and $17.1 million for 2011, 2010 and 2009, respectively. Depletion per Mcfe was $1.35, $1.30 and $1.36 for 2011, 2010 and 2009, respectively. Depreciation expense was $20.3 million, $35.0 million and $37.3 million for 2011, 2010 and 2009, respectively.

84

9. OTHER ASSETS

Other assets consisted of the following:

	As of December 31,
	2011			2010
	(In thousands)
Deferred financing costs	$	55,952		$	60,233
Less accumulated amortization		(16,576	)		(22,222	)
Net deferred financing costs		39,376			38,011
Notes receivable		7,996			-
Other		3,162			230
	$	50,534		$	38,241

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

10. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:

	As of December 31,
	2011		2010
	(In thousands)
Interest payable	$	68,091	$	69,394
Accrued operating expense		46,569		34,136
Prepayments from partners		33		4,490
Revenue payable		26,073		5,563
Accrued state income and franchise taxes		-		4,497
Accrued production and property taxes		815		2,448
Environmental liabilities		63		235
Accrued product purchases		295		345
Current asset retirement obligations		254		1,574
Other		-		222
	$	142,193	$	122,904

85

11. LONG-TERM DEBT

Long-term debt consisted of the following:

	As of December 31,
	2011		2010
	(In thousands)
2007 Senior Secured Credit Facility	$	-	$	21,114
Combined Credit Agreements		227,482		-
Senior notes due 2015, net of unamortized discount of $2,980 and $4,134		435,020		470,866
Senior notes due 2016, net of unamortized discount of $13,643 and $16,395		576,977		583,605
Senior notes due 2019, net of unamortized discount of $5,945 and $6,504		292,055		293,496
Senior subordinated notes due 2016		350,000		350,000
Convertible debentures, net of unamortized discount of $0 and $6,522		18		143,478
Total debt		1,881,552		1,862,559
Unamortized deferred gain—terminated interest rate swaps		21,897		27,635
Current portion of long-term debt		(18)		(143,478)
Long-term debt	$	1,903,431	$	1,746,716

Maturities are as follows:

	Total Indebtedness		Combined  Credit Agreement		Senior Notes due in 2015		Senior Notes due in 2016		Senior Notes due in 2019		Senior Subordinated Notes		Convertible Debentures
							(In thousands)
2012	$	18	$	-	$	-	$	-	$	-	$	-	$	18
2013		-		-		-		-		-		-		-
2014		-		-		-		-		-		-		-
2015		438,000		-		438,000		-		-		-		-
2016		1,168,102		227,482		-		590,620		-		350,000		-
Thereafter		298,000		-		-		-		298,000		-		-
	$	1,904,120	$	227,482	$	438,000	$	590,620	$	298,000	$	350,000	$	18

Credit Facilities

In September 2011, we terminated and replaced our $1.0 billion global 2007 Senior Secured Credit Facility with new separate five-year syndicated senior secured revolving credit facilities for our U.S. and Canadian operations. The $1.25 billion Initial U.S. Credit Facility had a borrowing base of $850 million, including a letter of credit capacity of $75 million, as of September 30, 2011. The C$500 million Initial Canadian Credit Facility had a borrowing base of C$225 million, including a letter of credit capacity of C$100 million, as of September 30, 2011. The borrowing base for each facility was to be re-determined at least semi-annually based upon engineering reports and such other information deemed appropriate by the applicable administrative agent, in a manner consistent with its normal oil and gas lending criteria as it exists at the time of such redetermination.

During December 2011, the Initial U.S. Credit Facility and the Initial Canadian Credit Facility were amended and restated by the Combined Credit Agreements. The Combined Credit Agreements provide for an up to five-year combined revolving credit facility pursuant to which revolving credit loans and letters of credit may be provided to Quicksilver and Quicksilver Resources Canada Inc., as applicable, from time to time in an amount not to exceed the lesser of the borrowing base or commitments. The $1.75 billion Combined Credit Agreements have a global borrowing base of $1.075 billion, including a global letter of credit capacity of $175 million, as of December 31, 2011. The Combined Credit Agreements’ availability is governed by a global borrowing base. The global borrowing base and the U. S. borrowing base will be re-determined at least semi-annually based

86

upon engineering reports and such other information deemed appropriate by the global administrative agent, in a manner consistent with its normal oil and gas lending criteria as it exists at the time of such redetermination. At the time of each such redetermination up to 100% of the U. S. borrowing base (less a $50 million minimum retained amount) may be allocated to the Canadian borrowing base. The commitments under each of the Amended and Restated U.S. Credit Facility and the Amended and Restated Canadian Credit Facility may be increased by an amount up to $250 million, subject to certain conditions, without the consent of the lenders.

Borrowings under the Amended and Restated U.S. Credit Facility are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured 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, and Quicksilver Resources Partners Operating Ltd. and certain oil and gas properties and related assets of Quicksilver. Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by 100% of the equity interests of Quicksilver Resources Canada Inc. and its oil and gas properties and related assets and certain oil and gas properties and related assets of Quicksilver. At December 31, 2011, there was $798.1 million available under the Combined Credit Agreements.

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

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

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.

Senior Notes Due 2016

In June 2009, we issued $600 million of senior notes due 2016, which are unsecured senior obligations. 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 the Senior Secured Second Lien Facility. Interest at the rate of 11.75% is payable semiannually on January 1 and July 1.

Senior Notes Due 2019

In August 2009, we issued $300 million of senior notes due 2019, which are unsecured senior obligations. 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.

Senior Subordinated Notes

In 2009, we issued $350 million of senior subordinated notes due 2016. The senior subordinated notes are unsecured senior subordinated obligations and bear interest at the rate of 7.125% which is payable semiannually on April 1 and October 1.

87

Senior Note Repurchases

During 2011, we repurchased the following senior notes in open market transactions:

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

Convertible Debentures

The convertible debentures due November 1, 2024 are contingently convertible into shares of our common stock. The debentures bear interest at an annual rate of 1.875% payable semi-annually on May 1 and November 1. Additionally, holders of the debentures can require us to repurchase all or a portion of their debentures on November 1, 2011, 2014 and 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into shares of our common stock at a rate of 65.4418 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events including certain changes of control, holders of the debentures are not entitled to exercise their conversion rights unless the closing price of our stock is at least $18.34 (120% of the conversion price per share) for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter. Upon conversion, we have the option to deliver any combination of our common stock and cash. Should all debentures be converted to our common stock, an additional 9,816,270 shares, subject to adjustment, would become outstanding; however, as of January 1, 2011, the debentures were not convertible based on share prices for the quarter ended December 31, 2010. We reported these obligations as current obligations in our December 31, 2010 balance sheet.

On November 1, 2011, we repurchased substantially all of the debentures for $150.0 million, after they were presented to us for repurchase by debenture holders. The repurchase transaction was completed utilizing borrowings from the Initial U.S. Credit Facility. During the first quarter of 2012, we repurchased the remaining debentures.

At December 31, 2010, the remaining unamortized discount on the debentures was $6.5 million, resulting in a carrying value of $143.5 million. The remaining discount was accreted to face value through October 2011. For 2011 and 2010, interest expense on our convertible debentures, recognized at an effective interest rate of 6.75%, was $8.9 million and $10.2 million, respectively, including contractual interest of $2.3 million for 2011 and $2.8 million for 2010.

88

Summary of All Outstanding Debt

As of December 31, 2011, the following subsidiaries are guarantors under our debt obligations: Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., and Barnett Shale Operating LLC. The following table summarizes other significant aspects of our long-term debt outstanding at December 31, 2011:

	Priority on Collateral and Structural Seniority (1)
	Highest priority				Lowest priority
	Equal Priority	Equal priority
	Combined Credit Agreements	2015 Senior Notes	2016 Senior Notes	2019 Senior Notes	Senior Subordinated Notes
Principal amount	$1.075 billion (2)	$438 million	$591 million	$298 million	$350 million
Scheduled maturity date	September 6, 2016	August 1, 2015	January 1, 2016	August 15, 2019	April 1, 2016
Interest rate on outstanding borrowings at December 31, 2011 (3)	2.13%	8.25%	11.75%	9.125%	7.125%
Base interest rate options	LIBOR, ABR, CDOR (4) (5)	N/A	N/A	N/A	N/A
Financial covenants (6)	- Minimum current ratio of 1.0 - Minimum EBITDA to cash interest expense ratio of 2.5	N/A	N/A	N/A	N/A
Significant restrictive covenants (6)	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions - Limitations on derivatives	- 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	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions
Optional redemption (6)	Any time	August 1, 2012:     103.875 2013:     101.938         2014:      par	July 1, 2013:     105.875 2014:     102.938         2015:      par	August 15, 2014:     104.563 2015:     103.042 2016:     101.521          2017:     par	April 1,    2012:     102.375    2013:     101.188           2014:     par
Make-whole redemption (6)	N/A	Callable prior to August 1, 2012 at make-whole call price of Treasury + 50 bps	Callable prior to July 1, 2013 at make-whole call price of Treasury + 50 bps	Callable prior to August 15, 2014 at make-whole call price of Treasury + 50 bps	N/A
Change of control (6)	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
Equity clawback (6)	N/A	N/A	Redeemable until July 1, 2012 at 111.75%, plus accrued interest for up to 35%	Redeemable until August 15, 2012 at 109.125%, plus accrued interest for up to 35%	N/A
Estimated fair value (7)	$227.5 million	$446.7 million	$669.7 million	$314.4 million	$346.5 million

⁽¹⁾  Borrowings under the Amended and Restated U.S. Credit Facility are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured 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, and Quicksilver Resources Partners Operating Ltd., and certain oil and gas properties and related assets of Quicksilver. Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by 100% of the equity interests of Quicksilver Resources Canada Inc. and its oil and gas properties and related assets, and certain oil and gas properties and related assets of Quicksilver. The other debt presented is based upon structural seniority and priority of payment.

⁽²⁾  The principal amount for the Combined Credit Agreements represents the borrowing base as of December 31, 2011.

⁽³⁾  Represents the weighted average borrowing rate payable to lenders.

⁽⁴⁾  Amounts outstanding under the Amended and Restated U.S. Credit Facility bear interest, at our election, at (i) adjusted LIBOR (as defined in the credit agreement) plus an applicable margin between 1.50% to 2.50%, (ii) ABR (as defined in the credit agreement), which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) adjusted LIBOR (as defined in the credit agreement) plus 1.0%, plus, in each case under scenario (ii), an applicable margin between 0.50% to 1.50%. We also pay a per annum fee on all letters of credit issued under the Amended and

89

Restated U.S. Credit Facility equal to the applicable margin and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.375% to 0.50%, in each case, based on global borrowing base usage.

⁽⁵⁾  Amounts outstanding under the Amended and Restated Canadian Credit Facility bear interest, at our election, at (i) the CDOR Rate (as defined in the credit agreement) plus an applicable margin between 1.50% and 2.50%, (ii) the Canadian Prime Rate (as defined in the credit agreement) plus an applicable margin between 0.50% and 1.50%, (iii) the U.S. Prime Rate (as defined in the credit agreement) plus an applicable margin between 0.50% and 1.50% and (iv) eurodollar loans (as defined in the credit agreement) plus an applicable margin between 1.50% to 2.50%. We pay a per annum fee on all letters of credit issued under the Amended and Restated Canadian Credit Facility equal to the applicable margin and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.375% to 0.50%, in each case, based on global borrowing base usage.

⁽⁶⁾  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.

⁽⁷⁾  The estimated fair value is determined based on market quotations on the balance sheet date for fixed rate obligations. We consider debt with variable interest rates to have a fair value equal to its carrying value.

12. ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated asset retirement obligation from January 1, 2010 through December 31, 2011.

	As of December 31,
	2011		2010
	(In thousands)
Beginning asset retirement obligations	$	57,809	$	48,581
Additional liability incurred		6,134		2,440
Change in estimates		20,573		2,042
Accretion expense		2,696		2,568
Asset retirement costs incurred		(2,857)		(1,184)
Gain on settlement of liability		816		1,264
Reclassification of liability of operations previously held for sale		1,431		-
Currency translation adjustment		(780)		2,098
Ending asset retirement obligations		85,822		57,809
Less current portion		(254)		(1,574)
Long-term asset retirement obligation	$	85,568	$	56,235

90

13. INCOME TAXES

Significant components of our deferred tax assets and liabilities as of December 31, 2011 and 2010 are as follows:

	As of December 31,
	2011		2010 (1)
	(In thousands)
Deferred tax assets:
Net operating loss carry-forwards	$	136,492	$	98,870
Investment in Fortune Creek		3,681		-
AMT tax credit		62,067		67,633
Settlements of interest rate swaps		7,664		9,672
Deferred compensation expense		17,865		8,401
Other		589		7,028
Less: Valuation allowance — Fortune Creek		(3,681)		-
Deferred tax assets		224,677		191,604
Deferred tax liabilities:
Property, plant and equipment		(420,564)		(297,798)
Gains from hedging and derivative activities		(95,373)		(49,153)
Unrealized gains reported in earnings		(12,999)		-
Investment in BBEP		-		(16,545)
Convertible debentures		-		(19,604)
Deferred tax liabilities		(528,936)		(383,100)
Total deferred tax asset (liability)	$	(304,259)	$	(191,496)
Reflected in the consolidated balance sheets as:
Non-current deferred income tax asset	$	-	$	-
Current deferred income tax liability		(45,262)		(28,861)
Non-current deferred income tax liability		(258,997)		(162,635)
	$	(304,259)	$	(191,496)

⁽¹⁾  Note 2 contains additional information regarding restated 2010 amounts.

The components of net income (loss) before income tax for 2011, 2010 and 2009 are as follows:

	2011		2010		2009
			(In thousands)
U.S.	$	146,090	$	708,081	$	(744,053)
Canada		1,819		5,747		(92,803)
Total	$	147,909	$	713,828	$	(836,856)

No rate changes occurred in any taxing jurisdiction for 2009, 2010 or 2011. For 2012 and beyond, we have utilized a rate of 25% 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.

91

The components of income tax expense for 2011, 2010 and 2009 are as follows:

	2011		2010 (1)		2009
			(In thousands)
Current state income tax expense (benefit)	$	(1,706)	$	4,501	$	(2)
Current U.S. federal income tax expense (benefit)		(5,565)		67,632		(202)
Current Canadian income tax expense		642		1,038		-
Total current income tax expense (benefit)		(6,629)		73,171		(204)
Deferred state income tax expense (benefit)		1,980		3,674		(4,928)
Deferred U.S. federal income tax expense (benefit)		58,890		179,400		(262,217)
Deferred Canadian income tax expense (benefit)		3,622		2,293		(24,268)
Total deferred income tax expense (benefit)		64,492		185,367		(291,413)
Total income tax expense (benefit)	$	57,863	$	258,538	$	(291,617)

⁽¹⁾ Note 2 contains additional information regarding restated 2010 amounts.

The following table reconciles the statutory federal income tax rate to the effective tax rate for 2011, 2010 and 2009:

	2011		2010 (1)		2009
U.S. federal statutory tax rate		35.00%		35.00%		35.00%
Permanent differences		1.51%		0.78%		(0.18%)
Noncontrolling interest benefit (expense)		0.00%		(0.48%)		0.71%
State income taxes net of federal deduction		0.12%		0.74%		0.38%
Canadian income taxes		2.41%		0.18%		(0.98%)
Other		0.08%		0.00%		(0.08%)
Effective income tax rate		39.12%		36.22%		34.85%

(1) Note 2 to contains additional information regarding restated 2010 amounts.

We incurred net operating tax losses of $35 million, $336 million and $656 million in 2011, 2009 and 2008, respectively, of which $138 million was carried back to 2007. Approximately $476 million of the remaining $889 million has been applied to our 2010 taxable income and the remainder is included in deferred tax assets at December 31, 2011. Our net operating losses will expire between 2029 and 2032. In December 2009, newly enacted federal legislation allowed us to carry back 2008 alternative minimum tax losses of $35 million to 2004 and 2007. The net operating losses have not been reduced by a valuation allowance, because we believe that future taxable income would more likely than not be sufficient to utilize substantially all of our operating loss tax carry-forwards prior to their expiration.

QRI’s tax basis in the Fortune Creek Partnership exceeds book basis by $29 million. The Company expects to realize the deferred tax asset related to this balance only through the Partnership’s sale at which time the transaction will be treated as a capital transaction under Canadian tax law, taxed at the Canadian statutory rate of 12.5% for capital gains. We believe that it is more likely than not that we will be unable to realize the benefit of this deferred tax asset. Accordingly, we have recorded a full valuation allowance of $3.7 million for this item.

During October 2009, the IRS commenced an audit of our 2007 and 2008 consolidated U.S. federal income tax returns. No significant adjustments have been proposed by the IRS for those years. The Joint Committee of Taxation has reviewed and accepted the net operating loss carrybacks we filed in 2009. We remain subject to examination by the IRS for the years 2001 through 2006 except for 2004. An audit was completed by the IRS for 2004 and the statute of limitations has now expired for that year.

92

The following schedule reconciles the total amounts of unrecognized tax benefits for 2011 and 2010:

	As of December 31,
	2011		2010
	(In thousands)
Beginning unrecognized tax benefits	$	9,219	$	9,219
Changes		-		-
Ending unrecognized tax benefits	$	9,219	$	9,219

At December 31, 2011, $9.0 million of these unrecognized tax benefits, if recognized, would impact the effective tax rate.

14. COMMITMENTS AND CONTINGENCIES

Contractual Obligations

Information regarding our contractual obligations, at December 31, 2011, is set forth in the following table:

	GPT     Contracts (1)		Drilling Rig     Contracts (2)		Operating     Leases (3)		Purchase     Obligations (4)
	(In thousands)
2012	$	67,341	$	23,948	$	5,484	$	11,355
2013		82,807		806		4,715		-
2014		111,894		-		4,478		-
2015		143,095		-		4,158		-
2016		147,692		-		3,285		-
Thereafter		477,583		-		18,627		-
Total	$	1,030,412	$	24,754	$	40,747	$	11,355

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

⁽²⁾ We lease drilling rigs from third parties for use in our development and exploration programs. The outstanding drilling rig contracts require payment of a specified day rate ranging from $12,500 to $27,005 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 $4.8 million in 2011, $4.3 million in 2010 and $4.1 million in 2009.

⁽⁴⁾ At December 31, 2011, we were under contract to purchase goods and services for use in field and gas plant operations.

93

Commitments and Contingencies

In April 2011, we entered into the NGTL Project, which will serve our Horn River Asset. Under the governing agreements, we agreed to provide financial assurances in the form of letters of credit to NGTL during the construction phase of the project, which is expected to continue through 2014. Assuming the project is fully constructed and based on estimated costs of C$257.4 million, including taxes of C$27.6 million, we expect to provide cumulative letters of credit as follows:

	NGTL Cumulative
	Financial Assurances (1)
	(C$ in thousands)		(US$ in thousands)
July 1, 2012	$	68,264	$	67,124
October 1, 2012		109,816	$	107,982
July 1, 2013		148,400	$	145,922
October 1, 2013		257,400	$	253,101

⁽¹⁾  A letter of credit for C$32.6 million is outstanding for the NGTL Project as of December 31, 2011.

Should other companies subscribe to the project, then our financial assurances under the agreements will be reduced. If the project is terminated by NGTL, then we would be responsible for all of the costs incurred or for which NGTL is liable, and we would have the option to purchase NGTL’s rights in the project for a nominal fee. Should the project be terminated by NGTL, we are required to pay NGTL an additional C$26.4 million. NGTL may terminate the project if it is not approved by the National Energy Board of Canada. Based on this and on numerous other factors, we consider the likelihood to be remote that NGTL will terminate the project. Accordingly, no amounts have been recognized on our consolidated balance sheet as of December 31, 2011. Upon completion of the project, all construction-related guarantees will expire.

We have also entered into agreements to deliver production from our Horn River Asset to NGTL over a 10-year period. These agreements will be extended in the event NGTL has either not received 1 Tcf of gas from us and other third parties, or recovered its costs as of the end of the 10-year period. In such event, the extension will be for delivery of minimum volumes of 106 MMcfd until such time that 1 Tcf of gas is delivered.

Also under the agreements, we are required to treat the gas to meet NGTL pipeline specifications. Such treatment will require us to construct treating facilities. We will develop our plans to address the treating requirements prior to the commissioning of the assets being constructed by NGTL.

At December 31, 2011, we had $9.1 million in surety bonds issued to fulfill contractual, legal or regulatory requirements and $49.4 million in letters of credit outstanding against the credit facility. Surety bonds and letters of credit generally have an annual renewal option.

On July 26, 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arises out of press releases in 2011 questioning the projected decline curves and economics of shale gas wells.

The allegations against our Executive Vice President – Operations in the District Court of Cleveland County, Oklahoma were dismissed on January 17, 2012.

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, 2011, we had recorded $0.1 million for liabilities for environmental matters.

15. NONCONTROLLING INTERESTS AND KGS

KGS issued 4,000,000 newly issued common units in December 2009 in the KGS Secondary Offering and received $80.3 million, net of underwriters’ discount and other offering costs. The portion of these proceeds

94

related to our initial ownership interests, $50.2 million, was recognized as an increase to “Additional Paid-in Capital” on our consolidated balance sheet. In January 2010, the underwriters exercised their option to purchase an additional 549,200 newly issued common units for $11.1 million. As a result we recognized an additional $6.7 million to “Additional Paid-in Capital” in January 2010. KGS offered additional units to the public to provide funding for its acquisition of certain midstream assets from us, which was completed in January 2010 for $95.2 million.

With the closing of the Crestwood Transaction, we no longer consolidate the KGS (or CMLP as it is now known) in our financial statements. Accordingly, we no longer have noncontrolling interests attributable to it within our financial statements.

16. FORTUNE CREEK

In December 2011, we entered into an agreement to form a midstream partnership, Fortune Creek, dedicated to the construction and operation of midstream assets to support natural gas producers 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 connection with the partnership formation, we contributed an existing 20-mile, 20-inch gathering line, its related compression facilities, and 10-year contracts dedicating our future gas production from our Horn River Asset, as more fully described below. KKR contributed $125 million cash in exchange for a 50% interest in the partnership. Our Canadian subsidiary has responsibility of the day-to-day operations of Fortune Creek.

Our Canadian subsidiary entered into a firm gathering agreement with Fortune Creek which is guaranteed by us. At our election, KKR has the responsibility to fund all of the capital contributions associated with the development of the new gas treatment facility in exchange for preferential cash flow distributions. If our subsidiary does not meet its obligations under the gathering agreement, KKR has the right to liquidate the partnership and consequently we have recorded the funds contributed by KKR as a liability in our consolidated financial statements.

Based on an analysis of the entities 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 facilities, we have determined we are the primary beneficiary and therefore, we consolidate Fortune Creek.

The following December 31, 2011 balances related to Fortune Creek are recorded in our consolidated balance sheet:

(In thousands)
Cash and cash equivalents	$	12,783
Canadian value-added tax receivable		14,750
Property, plant and equipment, net		80,761
Total assets	$	108,294
Partnership liability	$	122,913
Asset retirement obligations		80
Total liabilities	$	122,993

17. 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, 2011, we had 171.6 million shares of common stock outstanding.

95

The following table shows common share and treasury share activity since January 1, 2009:

	Common     Shares Issued		Treasury     Shares Held
Balance at January 1, 2009		171,742,699		4,572,795
Stock options exercised		610,000		-
Restricted stock activity		2,117,137		131,653
Balance at December 31, 2009		174,469,836		4,704,448
Stock options exercised		336,629		16,908
Restricted stock activity		718,351		329,094
Balance at December 31, 2010		175,524,816		5,050,450
Stock options exercised		209,221		-
Restricted stock activity		1,246,446		329,252
Balance at December 31, 2011		176,980,483		5,379,702

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. 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 $90, after adjustments to reflect the two-for-one stock split in January 2008.

The rights will be exercisable only if such a person or group acquires 15% or more of our common stock or announces a tender offer the consummation of which would result in ownership by such a person or group (an “Acquiring Person”) of 15% or more of common stock. This 15% threshold does not apply to certain members of the Darden family and affiliated entities, which collectively owned, directly or indirectly, approximately 30% of our common stock at February 15, 2012.

If an Acquiring Person acquires 15% or more of our outstanding common stock, each right 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, each right 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, the rights are redeemable for $0.01 per right at the option of our Board of Directors.

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, stockholders approved an amendment to the 2006 Equity Plan, which increased the number of shares available for issuance to 15 million. 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 10 years from the date of grant. At December 31, 2011 and 2010, 12.6 million shares and 14.1 million shares (including 0.9 million shares and 0.6 million shares, respectively, surrendered to us to satisfy participants’ tax withholding obligations which then became available for future issuance under the 2006 Equity Plan), respectively, were available for issuance under the 2006 Equity Plan.

96

Stock Options

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

	2011	2010	2009
Weighted average grant date fair value	$9.16	$ 9.88	$3.36
Weighted average grant date	Jan 3, 2011	Jan 4, 2010	Jan 2, 2009
Weighted average risk-free interest rate	2.38%	3.00%	1.90%
Expected life (in years)	6.0	6.0	6.0
Weighted average volatility	66.77%	66.76%	56.76%
Expected dividends	-	-	-

The following table summarizes our stock option activity for 2011:

	Shares		Weighted Average   Exercise Price		Weighted Average Remaining   Contractual   Life		Aggregate   Intrinsic Value
					(In years)		(In thousands)
Outstanding at January 1, 2011		3,348,642	$	11.10
Granted		834,970		14.88
Exercised		(209,221)		6.21
Cancelled		(150,231)		10.78
Expired		(63,464)		23.62
Outstanding at December 31, 2011		3,760,696	$	12.01		7.5	$	922
Exercisable at December 31, 2011		1,815,782	$	11.79		6.8	$	597

We estimate that a total of 3.7 million stock options will become vested including those options already exercisable. The unexercised options have a weighted average exercise price of $12.03 and a weighted average remaining contractual life of 7.5 years.

Compensation expense related to stock options of $7.0 million, $6.7 million and $4.5 million was recognized for 2011, 2010 and 2009, respectively. The total intrinsic value of options exercised during 2011, 2010 and 2009, was $1.2 million, $2.8 million and $4.3 million, respectively.

Restricted Stock and Stock Units

The following table summarizes our restricted stock and stock unit activity for 2011:

	Payable in shares				Payable in cash
	Shares		Weighted Average Grant Date Fair Value		Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1, 2011		2,329,089	$	11.27		372,633	$	10.31
Granted		1,389,404		13.89		214,515		14.88
Vested		(1,115,235)		12.17		(154,505)		9.88
Cancelled		(142,958)		12.23		(62,797)		13.19
Outstanding at December 31, 2011		2,460,300	$	12.29		369,846	$	13.12

At December 31, 2010, we had unrecognized compensation cost related to outstanding unvested restricted stock and RSUs of $13.9 million. As of December 31, 2011, the unrecognized compensation cost related to outstanding unvested restricted stock and RSUs was $17.3 million, which is expected to be recognized in

97

expense over the next 2 years. Grants of restricted stock and RSUs during 2011 had an estimated grant date fair value of $19.3 million. The fair value of RSUs settled in cash was $2.5 million and $5.5 million at December 31, 2011 and 2010, respectively. For 2011, 2010 and 2009, compensation expense of $13.9 million, $13.3 million and $14.6 million, respectively, was recognized. The total fair value of shares vested during 2011, 2010 and 2009 was $13.6 million, $16.4 million and $11.0 million, respectively.

Accumulated Other Comprehensive Income

At December 31, 2011, AOCI included $195.2 million and $19.7 million for derivatives and foreign currency translation, respectively. At December 31, 2010, AOCI included $97.2 million and $33.0 million for derivatives and foreign currency translation, respectively. All of these balances were attributable to us.

18. 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,
	2011		2010 (3)		2009
	(In thousands, except per share data)
Net income (loss) attributable to Quicksilver	$	90,046	$	445,566	$	(557,473)
Basic income allocable to participating securities (1)		(1,106)		(5,698)		-
Basic net income (loss) attributable to Quicksilver	$	88,940	$	439,868	$	(557,473)
Impact of assumed conversions — interest on 1.875% convertible debentures, net of income taxes (2)		-		7,194		-
Income (loss) available to stockholders assuming conversion of convertible debentures	$	88,940	$	447,062	$	(557,473)
Weighted average common shares — basic		168,993		168,010		169,004
Effect of dilutive securities (2):
Share-based compensation awards		742		802		-
Convertible debentures		-		9,816		-
Weighted average common shares — diluted		169,735		178,628		169,004
Earnings (loss) per common share — basic	$	0.53	$	2.62	$	(3.30)
Earnings (loss) per common share — diluted	$	0.52	$	2.50	$	(3.30)

⁽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 2011, the effects of 9.8 million shares associated with our convertible debentures for the period outstanding were antidilutive, and stock options and unvested restricted stock units representing 1.9 million and 0.1 million shares, respectively, were antidilutive and, therefore, excluded from the diluted share calculations. For 2010, stock options and unvested restricted stock units representing 1.2 million and 0.1 million shares, respectively, were antidilutive and, therefore, excluded from the diluted share calculations. For 2009, the effects of 9.8 million shares associated with our contingently convertible debt and all share-based compensation awards were antidilutive and, therefore, excluded from the diluted share calculations.

⁽³⁾ Note 2 contains additional information regarding restated 2010 amounts.

19. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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

98

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

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

⁽¹⁾ This entity was inactive for the three-year period ended December 31, 2011.

⁽²⁾ We sold all our interests in this entity to Crestwood on October 1, 2010.

⁽³⁾ These entities were created in 2011.

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 or are related to our midstream MLP. Neither the restricted non-guarantor subsidiaries nor the unrestricted non-guarantor subsidiaries guarantee the obligations under the senior notes and 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:

Ÿ incurring additional indebtedness;

Ÿ paying dividends;

Ÿ selling assets;

Ÿ making investments; and

Ÿ making restricted payments.

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

The following tables present financial information about Quicksilver and our restricted subsidiaries for the annual periods covered by the consolidated financial statements. Under the indenture, Fortune Creek is not considered to be a subsidiary and therefore it is presented separately from the other subsidiaries for these purposes. The 2011, 2010 and 2009 condensed consolidating financial information includes changes in the financial information of our unrestricted non-guarantor subsidiaries to present the 2011, 2010 and 2009 financial information including the effects of the purchase of certain of our midstream assets by KGS and the Crestwood Transaction where we sold all of our interests in the unrestricted subsidiaries.

99

Immaterial Restatement of Condensed Consolidating Financial Information

We have restated 2010 results of operation and financial condition related to the gain on sale of our interests in KGS, which is more fully described in Note 2. This restatement impacted the “Quicksilver Resources Inc.” column.

In addition, we restated 2010 results of operation and financial condition to reclassify an $85.0 million intercompany payable previously recorded in current assets to current liabilities within the “Quicksilver Resources Inc.” column. We also restated to reclassify a $243.6 million intercompany receivable and payable previously reported as Investment in subsidiaries to Other Assets in the “Quicksilver Resources Inc.” column and to Long-term liabilities in the “Restricted Non-Guarantor Subsidiaries” column. These restatements had no impact on the totals reported for the “Quicksilver and Restricted Subsidiaries” for 2010 results of operation and financial condition.

Condensed Consolidating Balance Sheets

	December 31, 2011
	Quicksilver   Resources Inc.		Restricted Guarantor   Subsidiaries			Restricted   Non-Guarantor   Subsidiaries			Restricted Subsidiary   Eliminations			Quicksilver   and Restricted   Subsidiaries			Unrestricted   Non-Guarantor   Subsidiaries			Fortune   Creek		Consolidating   Eliminations			Quicksilver   Resources Inc.   Consolidated
	(In thousands)
ASSETS
Current assets	$	336,893	$	87,767		$	63,711		$	(200,727	)	$	287,644		$	-		$	27,533	$	(14,750	)	$	300,427
Property and equipment		2,743,379		37,936			598,443			-			3,379,758			-			80,761		-			3,460,519
Investment in subsidiaries (equity method)		241,680		-			(29,449	)		(241,680	)		(29,449	)		(29,449	)		-		58,898			-
Other assets		401,279		-			76,857			(243,620	)		234,516			-			-		-			234,516
Total assets	$	3,723,231	$	125,703		$	709,562		$	(686,027	)	$	3,872,469		$	(29,449	)	$	108,294	$	44,148		$	3,995,462
LIABILITIES AND EQUITY
Current liabilities	$	348,512	$	109,938		$	76,450		$	(200,727	)	$	334,173		$	-		$	14,750	$	(14,750	)	$	334,173
Long-term liabilities		2,112,800		21,903			385,294			(243,620	)		2,276,377			-			80		122,913			2,399,370
Quicksilver stockholders’ equity		1,261,919		(6,138	)		247,818			(241,680	)		1,261,919			(29,449	)		93,464		(64,015	)		1,261,919
Total liabilities and equity	$	3,723,231	$	125,703		$	709,562		$	(686,027	)	$	3,872,469		$	(29,449	)	$	108,294	$	44,148		$	3,995,462

	December 31, 2010 (Restated)
	Quicksilver   Resources Inc.		Restricted Guarantor   Subsidiaries		Restricted   Non-Guarantor   Subsidiaries		Restricted Subsidiary   Eliminations			Quicksilver   and Restricted   Subsidiaries		Unrestricted   Non-Guarantor   Subsidiaries		Consolidating   Eliminations		Quicksilver   Resources Inc.   Consolidated
	(In thousands)
ASSETS
Current assets	$	295,697	$	86,582	$	49,424	$	(193,531	)	$	238,172	$	-	$	-	$	238,172
Property and equipment		2,413,080		68,390		581,775		-			3,063,245		-		-		3,063,245
Assets of midstream operations		-		27,178		-		-			27,178		-		-		27,178
Investment in subsidiaries (equity method)		367,845		-		-		(284,504	)		83,341		-		-		83,341
Other assets		339,227		-		191		(243,620	)		95,798		-		-		95,798
Total assets	$	3,415,849	$	182,150	$	631,390	$	(721,655	)	$	3,507,734	$	-	$	-	$	3,507,734
LIABILITIES AND EQUITY
Current liabilities	$	475,882	$	106,627	$	53,373	$	(193,531	)	$	442,351	$	-	$	-	$	442,351
Long-term liabilities		1,870,062		20,346		347,259		(243,620	)		1,994,047		-		-		1,994,047
Liabilities of midstream operations		-		1,431		-		-			1,431		-		-		1,431
Quicksilver stockholders’ equity		1,069,905		53,746		230,758		(284,504	)		1,069,905		-		-		1,069,905
Total liabilities and equity	$	3,415,849	$	182,150	$	631,390		$    (721,655)		$	3,507,734	$	-	$	-	$	3,507,734

100

Condensed Consolidating Statements of Income

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

	For the Year Ended December 31, 2010 (Restated)
	Quicksilver   Resources Inc.			Guarantor   Subsidiaries			Restricted   Non-Guarantor   Subsidiaries			Restricted Subsidiary   Eliminations			Quicksilver   and Restricted   Subsidiaries			Unrestricted   Non-Guarantor   Subsidiaries			Eliminations			Quicksilver   Resources Inc.   Consolidated
	(In thousands)
Revenue	$	788,714		$	6,863		$	126,322		$	(3,197	)	$	918,702		$	82,299		$	(72,670	)	$	928,331
Operating expenses		494,373			37,508			113,768			(3,197	)		642,452			48,368			(72,670	)		618,150
Gain on sale of subsidiary		493,953			-			-			-			493,953			-			-			493,953
Equity in net earnings of subsidiaries		(7,666	)		15,228			-			7,666			15,228			-			(15,228	)		-
Operating income (loss)		780,628			(15,417	)		12,554			7,666			785,431			33,931			(15,228	)		804,134
Income from earnings of BBEP		22,323			-			-			-			22,323			-			-			22,323
Interest expense and other		(96,953	)		-			(6,868	)		-			(103,821	)		(8,808	)		-			(112,629	)
Income tax (expense) benefit		(260,432	)		5,396			(3,331	)		-			(258,367	)		(171	)		-			(258,538	)
Net income (loss)	$	445,566		$	(10,021	)	$	2,355		$	7,666		$	445,566		$	24,952		$	(15,228	)	$	455,290
Net income attributable to noncontrolling interests		-			-			-			-			-			(9,724	)		-			(9,724	)
Net income (loss) attributable to Quicksilver	$	445,566		$	(10,021	)	$	2,355		$	7,666		$	445,566		$	15,228		$	(15,228	)	$	445,566

	For the Year Ended December 31, 2009
	Quicksilver   Resources Inc.			Restricted Guarantor   Subsidiaries			Restricted   Non-Guarantor   Subsidiaries			Restricted Subsidiary   Eliminations			Quicksilver   and Restricted Subsidiaries			Unrestricted   Non-Guarantor   Subsidiaries			Consolidated   Eliminations			Quicksilver Resources Inc.   Consolidated
	(In thousands)
Revenue	$	634,321		$	4,395		$	188,769		$	(2,014	)	$	825,471		$	91,706		$	(84,442	)	$	832,735
Operating expenses		1,202,124			9,413			273,969			(2,014	)		1,483,492			47,610			(84,494	)		1,446,608
Equity in net earnings of subsidiaries		(52,643	)		27,161			-			52,643			27,161			-			(27,161	)		-
Operating income (loss)		(620,446	)		22,143			(85,200	)		52,643			(630,860	)		44,096			(27,109	)		(613,873	)
Income from earnings of BBEP		75,444			-			-			-			75,444			-			-			75,444
Impairment of investment in BBEP		(102,084	)		-			-			-			(102,084	)		-			-			(102,084	)
Interest expense and other		(180,980	)		3,725			(8,526	)		-			(185,781	)		(8,518	)		(2,044	)		(196,343	)
Income tax (expense) benefit		270,593			(9,054	)		24,269			-			285,808			5,809			-			291,617
Discontinued operations		-			-			-			-			-			(1,992	)		1,992			-
Net income (loss)	$	(557,473	)	$	16,814		$	(69,457	)	$	52,643		$	(557,473	)	$	39,395		$	(27,161	)	$	(545,239	)
Net income attributable to noncontrolling interests		-			-			-			-			-			(12,234	)		-			(12,234	)
Net income (loss) attributable to Quicksilver	$	(557,473	)	$	16,814		$	(69,457	)	$	52,643		$	(557,473	)	$	27,161		$	(27,161	)	$	(557,473	)

101

Condensed Consolidating Statements of Cash Flows

		000000		000000		000000		000000		000000		000000		000000	000000		000000		000000		000000		000000		000000		000000		000000
	For the Year Ended December 31, 2011
	Quicksilver Resources Inc.				Restricted Guarantor Subsidiaries				Restricted Non-Guarantor Subsidiaries				Restricted Subsidiary Eliminations			Quicksilver and Restricted Subsidiaries				Fortune Creek				Eliminations				Quicksilver Resources Inc. Consolidated
	(In thousands)
Net cash flow provided by operations	$	202,043			$	2,225			$	48,785			$	-		$	253,053			$	-			$	-			$	253,053
Capital expenditures		(518,454	)			(2,225	)			(169,928	)			-			(690,607	)			-				-				(690,607	)
Proceeds from sale of BBEP units		272,965				-				-				-			272,965				-				-				272,965
Investment in Fortune Creek		-				-				(12,783	)			-			(12,783	)			-				12,783				-
Proceeds from sale of properties and equipment		2,959				-				1,204				-			4,163				-				-				4,163
Net cash flow used by investing activities		(242,530	)			(2,225	)			(181,507	)			-			(426,262	)			-				12,783				(413,479	)
Issuance of debt		587,500				-				268,322				-			855,822				-				-				855,822
Repayments of debt		(588,862	)			-				(254,246	)			-			(843,108	)			-				-				(843,108	)
Debt issuance costs		(9,160	)			-				(3,346	)			-			(12,506	)			-				-				(12,506	)
Proceeds from exercise of stock options		1,299				-				-				-			1,299				-				-				1,299
Partnership funds received		-				-				-				-			-				135,696				(12,783	)			122,913
Creation of partnership liability		-				-				122,913				-			122,913				(122,913	)			-				-
Purchase of treasury stock		(4,864	)			-				-				-			(4,864	)			-				-				(4,864	)
Net cash flow provided by financing activities		(14,087	)			-				133,643				-			119,556				12,783				(12,783	)			119,556
Effect of exchange rates on cash		-				-				(921	)			-			(921	)			-				-				(921	)
Net increase (decrease) in cash and equivalents		(54,574	)			-				-				-			(54,574	)			12,783				-				(41,791	)
Cash and equivalents at beginning of period		54,937				-				-				-			54,937				-				-				54,937
Cash and equivalents at end of period	$	363			$	-			$	-			$	-		$	363			$	12,783			$	-			$	13,146

		000000		000000		000000		000000		000000		000000		000000	000000		000000		000000		000000		000000		000000		000000		000000
	For the Year Ended December 31, 2010 (Restated)
	Quicksilver Resources Inc.				Restricted Guarantor Subsidiaries				Restricted Non-Guarantor Subsidiaries				Restricted Subsidiary Eliminations			Quicksilver and Restricted Subsidiaries				Unrestricted Non-Guarantor Subsidiaries				Eliminations				Quicksilver Resources Inc. Consolidated
	(In thousands)
Net cash flow provided by operations	$	288,164			$	651			$	78,959			$	-		$	367,774			$	44,816			$	(14,870	)		$	397,720
Capital expenditures		(534,404	)			(651	)			(100,183	)			-			(635,238	)			(52,470	)			(7,406	)			(695,114	)
Distribution to parent		80,276				-				-				-			80,276				(80,276	)			-				-
Proceeds from sale of KGS		699,973				-				-				-			699,973				-				-				699,973
Proceeds from sale of BBEP units		34,016				-				-				-			34,016				-				-				34,016
Proceeds from sale of properties and equipment		9,953				-				-				-			9,953				-				-				9,953
Net cash flow used for investing activities		289,814				(651	)			(100,183	)			-			188,980				(132,746	)			(7,406	)			48,828
Issuance of debt		478,500				-				68,358				-			546,858				143,200				-				690,058
Repayments of debt		(712,000	)			-				(289,636	)			-			(1,001,636	)			(30,100	)			-				(1,031,736	)
Debt issuance costs		(2,211	)			-				(900	)			-			(3,111	)			-				-				(3,111	)
Gas Purchase Commitment repayments		(44,119	)			-				-				-			(44,119	)			-				-				(44,119	)
Issuance of KGS common units		-				-				-				-			-				11,054				-				11,054
Distributions to parent		-				-				-				-			-				(22,276	)			22,276				-
Intercompany note		(243,620	)			-				243,620				-			-				-				-				-
Distributions to noncontrolling interests		-				-				-				-			-				(13,550	)			-				(13,550	)
Proceeds from exercise of stock options		1,801				-				-				-			1,801				-				-				1,801
Excess tax benefits on exercise of stock options		3,513				-				-				-			3,513				-				-				3,513
Taxes paid on vested KGS equity compensation		-				-				-				-			-				(1,144	)							(1,144	)
Purchase of treasury stock		(4,910	)			-				-				-			(4,910	)			-				-				(4,910	)
Net cash flow provided by (used for) financing activities		(523,046	)			-				21,442				-			(501,604	)			87,184				22,276				(392,144	)
Effect of exchange rates on cash		-				-				(1,252	)			-			(1,252	)			-				-				(1,252	)
Net decrease in cash and equivalents		54,932				-				(1,034	)			-			53,898				(746	)			-				53,152
Cash and equivalents at beginning of period		5				-				1,034				-			1,039				746				-				1,785
Cash and equivalents at end of period	$	54,937			$	-			$	-			$	-		$	54,937			$	-			$	-			$	54,937

102

	For the Year Ended December 31, 2009
			Restricted		Restricted		Restricted		Quicksilver		Unrestricted				Quicksilver
	Quicksilver		Guarantor		Non-Guarantor		Subsidiary		and Restricted		Non-Guarantor				Resources Inc.
	Resources Inc.		Subsidiaries		Subsidiaries		Eliminations		Subsidiaries		Subsidiaries		Eliminations		Consolidated
	(In thousands)
Net cash flow provided by operating activities	$	358,405	$	73,202	$	148,280	$	-	$	579,887	$	68,133	$	(35,717)	$	612,303
Capital expenditures		(474,659)		(73,202)		(94,209)		-		(642,070)		(54,818)		3,050		(693,838)
Proceeds from sale of properties and equipment		220,206		-		768		-		220,974		-		-		220,974
Net cash flow used for investing activities		(254,453)		(73,202)		(93,441)		-		(421,096)		(54,818)		3,050		(472,864)
Issuance of debt		1,305,137		-		59,590		-		1,364,727		56,000		-		1,420,727
Repayments of debt		(1,428,105)		-		(116,025)		-		(1,544,130)		(105,500)		-		(1,649,630)
Debt issuance costs		(29,901)		-		(1,125)		-		(31,026)		(1,446)		-		(32,472)
Repayments to parent		-		-		-		-		-		(5,645)		5,645		-
Gas Purchase Commitment—net		44,119		-		-		-		44,119		-		-		44,119
Issuance of KGS common units		-		-		-		-		-		80,729		-		80,729
Distributions to parent		-		-				-		-		(27,022)		27,022		-
Distributions to noncontrolling interests		-		-		-		-		-		(9,925)		-		(9,925)
Proceeds from exercise of stock options		4,046		-		-		-		4,046		-		-		4,046
Taxes paid on vested KGS equity compensation		-		-		-		-		-		(63)		-		(63)
Purchase of treasury stock		(922)		-		-		-		(922)		-		-		(922)
Net cash flow provided by (used for) financing activities		(105,626)		-		(57,560)		-		(163,186)		(12,872)		32,667		(143,391)
Effect of exchange rates on cash		-		-		2,889		-		2,889		-		-		2,889
Net decrease in cash and equivalents		(1,674)		-		168		-		(1,506)		443		-		(1,063)
Cash and equivalents at beginning of period		1,679		-		866		-		2,545		303		-		2,848
Cash and equivalents at end of period	$	5	$	-	$	1,034	$	-	$	1,039	$	746	$	-	$	1,785

103

20. SEGMENT INFORMATION

We operate in two geographic segments, the U.S. and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. Additionally, prior to the Crestwood Transaction, we operated in the midstream segment in the U.S., where we provided natural gas gathering and processing services predominantly through KGS. Following our announced partnership with KKR, we expect to have a midstream segment in Canada beginning in 2012 conducted through Fortune Creek. Revenue earned by KGS prior to the Crestwood Transaction for the gathering and processing of our gas has been eliminated on a consolidated basis as is the GPT recognized by our producing properties. 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)
2011
Revenue	$	806,657		$	135,948		$	4,573		$	-		$	(3,555	)	$	943,623
DD&A		171,438			47,116			4,889			2,320			-			225,763
Impairment expense		-			49,063			57,996			-			-			107,059
Operating income (loss)		251,495			12,914			(59,903	)		(81,902	)		-			122,604
Property and equipment costs incurred		487,145			131,699			64,119			11,516			-			694,479
																	-
2010
Revenue	$	788,714		$	126,322		$	87,426		$	-		$	(74,131	)	$	928,331
DD&A (1)		136,361			45,335			23,523			1,984			-			207,203
Impairment expense		-			19,386			28,611			-			-			47,997
Operating income (loss) (1)		857,170			16,765			12,290			(82,091	)		-			804,134
Property and equipment costs incurred		452,044			123,348			154,271			5,146			-			734,809
2009
Revenue	$	634,321		$	188,770		$	99,817		$	-		$	(90,173	)	$	832,735
DD&A		134,066			38,965			26,682			1,674			-			201,387
Impairment expense		786,867			192,673			-			-			-			979,540
Operating income (loss)		(500,164	)		(81,529	)		46,737			(78,917	)		-			(613,873	)
Property and equipment costs incurred		391,916			91,949			115,655			2,161			-			601,681
Property, plant and equipment—net
December 31, 2011	$	2,752,101		$	677,695		$	21,477		$	9,246		$	-		$	3,460,519
December 31, 2010 (1)		2,398,439			581,775			68,389			14,642			-			3,063,245
December 31, 2009		1,968,430			491,528			71,264			11,623			-			2,542,845
Investment in equity affiliates
December 31, 2011	$	-		$	-		$	-		$	-		$	-		$	-
December 31, 2010		83,341			-			-			-			-			83,341
December 31, 2009		112,763			-			-			-			-			112,763

⁽¹⁾ Note 2 contains additional information regarding restated 2010 amounts.

104

21. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Years Ended December 31,
	2011		2010		2009
	(In thousands)
Interest, net of capitalized interest	$	170,814	$	136,459	$	128,217
Income taxes		(4,249)		78,083		(41,267)

Other significant non-cash transactions are as follows:

	Years Ended December 31,
	2011		2010		2009
	(In thousands)
Working capital related to capital expenditures	$	107,586	$	100,587	$	118,294
Conveyance of 3,619,901 BBEP common units for producing properties		-		54,407		-
Quicksilver common shares received for cashless exercise of 34,415 stock options		-		214		-
Note receivable received for sale of land and building		5,300		-		-

22. 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 $2.3 million, $2.5 million and $2.3 million for 2011, 2010 and 2009, 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 2011, 2010 and 2009 was $0.8 million for each year.

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 and an aggregating stop loss of $175,000. For 2011, 2010 and 2009 we recognized expense of $4.8 million, $3.5 million and $4.6 million, respectively, for this plan.

23. TRANSACTIONS WITH RELATED PARTIES

As of February 15, 2012, members of the Darden family and entities controlled by them beneficially own approximately 30% of our outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.

We paid $0.2 million in 2011, $0.6 million in 2010, and $0.7 million in 2009 for rent and property management services on buildings owned by entities controlled by members of the Darden family. Rental rates were determined based on comparable rates charged by third parties. In October 2011, we agreed to purchase a manufacturing facility from an entity controlled by members of the Darden family for $1.1 million. We previously leased this facility from the seller for the manufacture of oil and gas equipment.

105

During 2011, 2010 and 2009, we paid $0.9 million, $0.8 million and $0.2 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.

We paid $0.2 million in 2009 primarily for delay rentals under leases for over 5,000 acres held by a related entity. The lease terms were determined based on comparable prices and terms granted to third parties with respect to similar leases in the area. No payments were made in 2011 or 2010.

Payments received in 2011, 2010 and 2009 from Mercury for sublease rentals, employee insurance coverage and administrative services were $0.1 million, $0.3 million, and $0.3 million, respectively.

An entity affiliated with Mercury received $0.2 million in commission for the sale and purchases of property to unrelated third parties in 2011. The entity also received a $1.4 million commission from the lessor in connection with office space leased as of August 2010.

106

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)
2011 (1) (5)
Operating revenue	$	212,187		$	248,446	$	259,893	$	223,097
Operating income		(793	)		78,676		67,981		(23,260	)
Net income		(70,758	)		108,587		28,686		23,531
Basic net earnings per share	$	(0.42	)	$	0.63	$	0.17	$	0.14
Diluted net earnings per share		(0.42	)		0.61		0.17		0.14
2010 (2) (3) (4)
Operating revenue	$	222,158		$	228,570	$	237,700	$	239,903
Operating income		75,845			108,867		65,092		554,330
Net income		10,600			90,744		26,569		327,377
Net income attributable to Quicksilver		8,188			86,803		21,803		328,772
Basic net earnings per share	$	0.05		$	0.51	$	0.13	$	1.93
Diluted net earnings per share		0.05			0.49		0.13		1.80

⁽¹⁾ Operating income for the first quarter of 2011 includes a charge of $49.1 million for impairment of the Canadian oil and gas properties to net realizable value.

⁽²⁾  Operating income for the third quarter of 2010 includes a charge of $28.6 million for impairment of the HDCS to net realizable value.

⁽³⁾  Operating income for the fourth quarter of 2010 includes a gain on sale of $494.0 million for the sale of all of our interests in KGS and a charge of $19.4 million for the impairment of our Canadian oil and gas properties.

⁽⁴⁾ Note 2 to the consolidated financial statements contains additional information regarding restated 2010 amounts. Given the sale of our interests in KGS occurred in October 2010, only the fourth quarter of 2010 was affected.

⁽⁵⁾  Operating income for fourth quarter 2011 includes gains of $217.9 million from the sale of BBEP Units. Operating income also includes charges for impairment of $58.0 million for our HCDS and certain midstream assets in Texas.

107

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Proved oil and gas reserves estimates for our properties in the U.S. and Canada were prepared by independent petroleum engineers from Schlumberger Data and Consulting Services 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 2011, 2010 and 2009 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 without any. 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.

As required by GAAP, we have also included separate disclosure and presentation of our share of BBEP’s proved reserves for 2010 and 2009 because we account for BBEP by the equity method.

Consolidated Quicksilver (Excluding BBEP Reserves)

The changes in our proved reserves for the three years ended December 31, 2011 were as follows:

	Natural Gas (MMcf)						NGL (MBbl)						Oil (MBbl)
	U.S.		Canada		Total		U.S.		Canada		Total		U.S.		Canada		Total
December 31, 2008		1,306,497		332,571		1,639,068		91,927		8		91,935		2,914		-		2,914
Revisions (4)		(28,833)		(67,207)		(96,040)		(4,178)		7		(4,171)		205		1		206
Extensions and discoveries (3)		460,214		12,153		472,367		15,487		-		15,487		165		-		165
Purchases in place		314		-		314		-		-		-		-		-		-
Sales in place (2)		(120,539)		(44)		(120,583)		-		-		-		-		-		-
Production		(61,619)		(24,420)		(86,039)		(4,975)		(2)		(4,977)		(425)		(1)		(426)
December 31, 2009		1,556,034		253,053		1,809,087		98,261		13		98,274		2,859		-		2,859
Revisions (4)		13,389		(1,224)		12,165		4,845		2		4,847		606		-		606
Extensions and discoveries (3)		323,713		17,309		341,022		13,695		-		13,695		146		-		146
Purchases in place (1)		124,996		22,005		147,001		-		-		-		-		-		-
Production		(76,409)		(25,255)		(101,664)		(4,357)		(3)		(4,360)		(303)		-		(303)
December 31, 2010		1,941,723		265,888		2,207,611		112,444		12		112,456		3,308		-		3,308
Revisions (4)		(172,643)		15,066		(157,577)		(8,519)		1		(8,518)		(43)		-		(43)
Extensions and discoveries (3)		155,662		76,067		231,729		2,652		-		2,652		43		-		43
Production		(95,838)		(26,390)		(122,228)		(4,432)		(2)		(4,434)		(273)		-		(273)
December 31, 2011		1,828,904		330,631		2,159,535		102,145		11		102,156		3,035		-		3,035
Proved developed reserves
December 31, 2009		1,044,140		223,300		1,267,440		60,997		13		61,010		2,467		-		2,467
December 31, 2010		1,312,777		242,941		1,555,718		64,908		12		64,920		2,775		-		2,775
December 31, 2011		1,244,187		299,371		1,543,558		60,902		11		60,913		2,545		-		2,545
Proved undeveloped reserves
December 31, 2009		511,894		29,753		541,647		37,264		-		37,264		392		-		392
December 31, 2010		628,946		22,947		651,893		47,536		-		47,536		533		-		533
December 31, 2011		584,717		31,260		615,977		41,243		-		41,243		490		-		490

⁽¹⁾  Purchases of U.S. reserves in place during 2010 relate principally to the acquisition of additional working interest in our company-operated Lake Arlington Asset and the Alliance Transaction, respectively. These transactions are more fully described in Note 3 to our consolidated financial statements. The 2010 purchase of Canadian reserves in place relates to the acquisition of additional working interests in a company-operated field located in our Horseshoe Canyon Asset.

⁽²⁾  Sales of reserves in place during 2009 relate principally to the Eni Transaction, which is more fully described in Note 3 to our consolidated financial statements.

⁽³⁾  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:

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

108

Ÿ 2010 are 100% attributable to our Barnett Shale Asset (of which 40% were proved developed);

Ÿ 2009 are 99% attributable to our Barnett Shale Asset (of which 42% were proved developed); and

Canadian extensions and discoveries for:

Ÿ 2011 are 97% attributable to our Horn River Asset and 3% are attributable to our Horseshoe Canyon Asset;

Ÿ 2010 are 69% attributable to our Horn River Asset and 31% are attributable to our Horseshoe Canyon Asset,

Ÿ 2009 are 53% attributable to our Horn River Asset and 47% are attributable to our Horseshoe Canyon Asset.

⁽⁴⁾  Revisions for each period presented reflect upward (downward) changes in previous estimates attributable to changes in operating and development costs, new information gained primarily from development drilling activity and production history and changes to development plans. Revisions include (154,405) MMcfe, (73,096) MMcfe and 132,846 MMcfe for such matters in 2011, 2010 and 2009, respectively. Revisions also include (54,539) MMcfe, 117,975 MMcfe and (251,676) MMcfe for changes in economic factors in 2011, 2010 and 2009. In 2011, negative revisions not related to economic factors resulted from removing proved undeveloped reserves that had not been developed within five years (55 Bcfe), change in performance related to offsetting activities, higher pipeline pressures and other factors (85 Bcfe) and various operational issues (14 Bcfe).

The carrying value of our oil and gas assets as of December 31, 2011, 2010 and 2009 were as follows:

	U.S.		Canada		Consolidated
	(In thousands)
2011
Proved properties	$	4,380,745	$	928,585	$	5,309,330
Unevaluated properties		252,737		180,604		433,341
Accumulated DD&A		(1,965,258)		(550,937)		(2,516,195)
Net capitalized costs	$	2,268,224	$	558,252	$	3,226,476
2010
Proved properties	$	3,965,585	$	839,576	$	4,805,161
Unevaluated properties		153,880		160,663		314,543
Accumulated DD&A		(1,800,764)		(478,621)		(2,279,385)
Net capitalized costs	$	2,318,701	$	521,618	$	2,840,319
2009
Proved properties	$	3,218,796	$	728,880	$	3,947,676
Unevaluated properties		340,707		117,330		458,037
Accumulated DD&A		(1,670,923)		(396,546)		(2,067,469)
Net capitalized costs	$	1,888,580	$	449,664	$	2,338,244

109

Our consolidated capital costs incurred for acquisition, exploration and development activities during each of the three years ended December 31, 2011, were as follows:

	U.S.		Canada		Consolidated
	(In thousands)
2011
Proved acreage	$	-	$	-	$	-
Unproved acreage		145,099		-		145,099
Development costs		304,373		90,361		394,734
Exploration costs		37,673		41,338		79,011
Total	$	487,145	$	131,699	$	618,844
2010
Proved acreage	$	125,647	$	19,271	$	144,918
Unproved acreage		44,271		827		45,098
Development costs		378,056		14,182		392,238
Exploration costs		9,385		57,896		67,281
Total	$	557,359	$	92,176	$	649,535
2009
Proved acreage	$	118	$	-	$	118
Unproved acreage		11,300		2,658		13,958
Development costs		341,658		24,179		365,837
Exploration costs		32,798		59,402		92,200
Total	$	385,874	$	86,239	$	472,113

110

Consolidated results of operations from our producing activities for each of the three years ended December 31, 2011, are set forth below:

	U.S.		Canada		Consolidated
	(In thousands)
2011
Natural gas, NGL and oil revenue	$	673,041	$	127,502	$	800,543
Operating expense		267,890		54,770		322,660
Depletion expense		164,493		38,228		202,721
Impairment expense		-		49,063		49,063
		240,658		(14,559)		226,099
Income tax expense (benefit)		84,230		(4,222)		80,008
Results from producing activities	$	156,428	$	(10,337)	$	146,091
2010
Natural gas, NGL and oil revenue	$	732,456	$	123,893	$	856,349
Operating expense		168,164		44,836		213,000
Depletion expense		129,843		38,825		168,668
Impairment expense		-		19,386		19,386
		434,449		20,846		455,295
Income tax expense		152,057		6,045		158,102
Results from producing activities	$	282,392	$	14,801	$	297,193
2009
Natural gas, NGL and oil revenue	$	608,013	$	188,685	$	796,698
Operating expense		112,935		38,661		151,596
Depletion expense		127,888		33,783		161,671
Impairment expense		786,867		192,673		979,540
		(419,677)		(76,432)		(496,109)
Income tax benefit		(146,887)		(22,165)		(169,052)
Results from producing activities	$	(272,790)	$	(54,267)	$	(327,057)

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

Under the Standardized Measure, future cash inflows for 2011 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

111

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,
	2011		2010		2009
Natural gas – Henry Hub, per MMBtu	$	4.12	$	4.38	$	3.87
Natural gas – AECO, per MMBtu		3.65		4.08		3.76
NGL – Mont Belvieu, Texas, per Bbl		47.16		37.56		24.94
Oil – WTI Cushing, per Bbl		95.71		79.43		61.18

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

The Standardized Measure at December 31, 2011, 2010 and 2009 was as follows:

	U.S.			Canada			Total
				(In thousands)
December 31, 2011
Future revenue	$	11,647,002		$	1,055,711		$	12,702,713
Future production costs		(5,496,246	)		(463,852	)		(5,960,098	)
Future development costs		(1,125,641	)		(146,658	)		(1,272,299	)
Future income taxes		(1,229,968	)		(44,183	)		(1,274,151	)
Future net cash flows		3,795,147			401,018			4,196,165
10% discount		(2,286,449	)		(174,863	)		(2,461,312	)
Standardized measure of discounted future cash flows relating to proved reserves	$	1,508,698		$	226,155		$	1,734,853
December 31, 2010
Future revenue	$	12,057,094		$	1,047,106		$	13,104,200
Future production costs		(5,636,375	)		(458,187	)		(6,094,562	)
Future development costs		(1,253,546	)		(93,668	)		(1,347,214	)
Future income taxes		(1,254,255	)		(62,370	)		(1,316,625	)
Future net cash flows		3,912,918			432,881			4,345,799
10% discount		(2,377,166	)		(182,255	)		(2,559,421	)
Standardized measure of discounted future cash flows relating to proved reserves	$	1,535,752		$	250,626		$	1,786,378
December 31, 2009
Future revenue	$	7,787,422		$	916,765		$	8,704,187
Future production costs		(4,169,783	)		(403,874	)		(4,573,657	)
Future development costs		(938,675	)		(93,588	)		(1,032,263	)
Future income taxes		(222,576	)		(47,125	)		(269,701	)
Future net cash flows		2,456,388			372,178			2,828,566
10% discount		(1,492,469	)		(153,418	)		(1,645,887	)
Standardized measure of discounted future cash flows relating to proved reserves	$	963,919		$	218,760		$	1,182,679

112

The primary changes in the Standardized Measure for 2011, 2010 and 2009 were as follows:

	Years Ended December 31,
	2011		2010		2009
			(In thousands)
Sales of oil and gas net of production costs	$	(477,883)	$	(643,349)	$	(645,102)
Net changes in economic factors		32,175		1,080,136		(715,484)
Extensions and discoveries		251,635		274,255		561,544
Development costs incurred		233,294		208,613		205,781
Changes in estimated future development costs		(60,642)		(341,612)		81,754
Purchase and sale of reserves, net		-		103,865		(144,279)
Revision of estimates		(224,784)		182,772		(248,681)
Accretion of discount		197,902		124,644		192,325
Net change in income taxes		1,404		(392,275)		196,691
Change in timing and other differences		(4,626)		6,650		(96,132)
Net increase (decrease)	$	(51,525)	$	603,699	$	(611,583)

Quicksilver’s Share of BBEP Reserves

The following disclosures required under GAAP represent our share of BBEP’s reserves and BBEP’s oil and gas operations as of December 31, 2010 and 2009, which are all located in the U.S. In 2011, our investment in BBEP was eliminated and we no longer own any BBEP Units as of December 31, 2011. Note 7 in our consolidated financial statements contains additional information regarding our relationship with BBEP.

The following provides information regarding ownership percentages applied to BBEP’s gross reported amounts, as applicable:

	2010		2009
Ownership in BBEP at December 31,		29.44%		40.45%
Annualized weighted average ownership of BBEP		34.62%		40.45%

The changes in our share of BBEP’s oil and gas reserves were as follows:

	For the Years Ended December 31,
	2010									2009
	Total (Mboe)			Gas (MMcf)			Oil (MBbl)			Total (Mboe)			Gas (MMcf)			Oil (MBbl)
Beginning balance		45,027			175,869			15,715			42,038			189,176			10,509
Revision of previous estimates		4,438			14,371			2,043			6,191			(4,203	)		6,891
Purchase of reserves in place (1)		515			2,943			24			-			-			-
Sale of reserves in place (1)		(12,652	)		(49,363	)		(4,424	)		(566	)		(543	)		(476	)
Production		(2,319	)		(7,357	)		(1,093	)		(2,636	)		(8,561	)		(1,209	)
Ending balance		35,009			136,463			12,265			45,027			175,869			15,715
Proved developed reserves (2)
Beginning balance		40,847			161,491			13,931			38,791			175,933			9,469
Ending balance		31,881			122,887			11,399			40,847			161,491			13,931
Proved undeveloped reserves (2) (3)
Beginning balance		4,180			14,378			1,784			3,247			13,243			1,040
Ending balance		3,128			13,576			866			4,180			14,378			1,784

⁽¹⁾  Amounts are included as needed to reconcile Quicksilver’s portion of beginning reserves to ending reserves that result from changes in Quicksilver’s proportionate ownership of BBEP.

113

⁽²⁾  During 2010, capital expenditures of $11.3 million were incurred and 16 wells drilled to convert 922 MMcf of natural gas and 959 MBbl of oil from proved undeveloped to proved developed. During 2009, capital expenditures of $2.3 million were incurred and 11 wells drilled to convert 196 MMcf of natural gas and 230 MBbl of oil from proved undeveloped to proved developed.

⁽³⁾  As of December 31, 2010 and 2009, no material proved undeveloped reserves have remained undeveloped for more than five years.

The following representative prices were used in BBEP’s Standardized Measure:

	Years Ended December 31,
	2010		2009
Representative prices:
Natural Gas-Henry Hub	$	4.38	$	3.87
Oil-WTI Cushing		79.40		61.18

The following table summarizes the carrying value of our portion of BBEP’s consolidated oil and gas assets as of December 31, 2010.

	At December 31,
	2010
Proved properties and related producing assets	$	551,573
Pipeline and processing facilities		43,171
Unproved properties		33,291
Accumulated depreciation, depletion and amortization		(122,295	)
Net capitalized costs	$	505,740

The following table summarizes our share of the capital costs incurred by BBEP during the two years ended December 31, 2010:

	2010		2009
	(In thousands)
Proved properties	$	580	$	-
Unproved properties		996		-
Development costs		22,487		11,598
Asset retirement costs		3,349		1,975
Total	$	27,412	$	13,573

The following table summarizes our share of BBEP’s results of operations from its producing activities for each of the two years ended December 31, 2010:

	2010		2009
	(In thousands)
Oil, natural gas and NGL sales	$	110,003	$	103,126
Gain (loss) on commodity derivative instruments		12,156		(20,808)
Operating costs		(49,343)		(56,029)
Depreciation, depletion & amortization		(34,684)		(42,194)
Income tax benefit		71		618
Results from producing activities	$	38,203	$	(15,287)

114

The following table summarizes our share of BBEP’s Standardized Measure at December 31, 2010 and 2009:

	At December 31,
	2010		2009
	(In thousands)
Future revenues	$	1,500,867	$	1,552,493
Future development costs		(73,954)		(79,983)
Future production costs		(770,940)		(850,917)
Future net cash flows		655,973		621,593
10% discount		(342,435)		(314,290)
Standardized measure of discounted future cash flows relating to proved reserves	$	313,538	$	307,303

The following table summarizes our share of the primary changes in BBEP’s Standardized Measure for 2010 and 2009:

	At December 31,
	2010			2009
		(In thousands)
Beginning balance	$	307,303		$	240,209
Sales, net of production costs		(51,587	)		(47,097	)
Net changes in sales and transfer prices, net of production expense		90,185			88,093
Previously estimated development costs incurred		14,053			11,748
Changes in estimated future development costs		(30,975	)		(14,969	)
Purchase of reserves in place (1)		493			–
Sale of reserves in place (1)		(83,651	)		(2,231	)
Revision of quantity estimates and timing of production		45,353			7,590
Accretion of discount		22,365			23,960
Ending balance	$	313,539		$	307,303

⁽¹⁾  Amounts are included as needed to reconcile our portion of beginning value to ending value that result from changes in our proportionate ownership of BBEP.

115

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, 2011. In making this evaluation, our management considered the matters relating to the material weakness discussed below.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2011. In light of the material weakness described below, we revised our impairment analysis for midstream assets and have concluded that the financial statements in this Annual Report on Form 10-K present fairly, in all material respects, our consolidated financial position, results of operation and cash flows in conformity with generally accepted accounting principles.

Management’s Report on Internal Control Over Financial Reporting

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

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

Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management conducted an assessment of our internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, our management has concluded that, as of December 31, 2011, it did not maintain effective internal control over financial reporting due to a material weakness relating to the design and operating effectiveness of the computation of impairment of our non-oil and gas assets. The weakness relates to design deficiencies regarding the assessment of triggering events and the consideration of asset groupings; and other deficiencies related to the performance and documentation of a recovery test and other fair value computational matters.

The effectiveness of our internal control over financial reporting as of December 31, 2011, has been audited by Deloitte & Touche LLP, our independent registered public accounting firm, and they have issued an attestation report on the effectiveness of our internal control over financial reports, as stated in their report included herein.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2011, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. In response to the identification of the material weakness, management has enhanced its process for documenting identification of impairment indicators, and the preparation and review of undiscounted recoverability tests and discounted cash flow analyses. Management believes that these enhancements and improvements, when repeated as applicable in future periods, remediate the material weakness described above.

116

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Quicksilver Resources Inc.

Fort Worth, Texas

We have audited the internal control over financial reporting of Quicksilver Resources Inc. and subsidiaries (the "Company") as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company'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 by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. A material weakness was identified relating to the design and operating effectiveness of the computation of impairment of non-oil and gas assets. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements as of and for the year ended December 31, 2011, of the Company and this report does not affect our report on such financial statements.

In our opinion, because of the effect of the material weakness identified above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2011 of the

117

Company. We considered the material weakness identified above in determining the nature, timing, and extent of audit tests applied in our audit of the 2011 consolidated financial statements, and this report does not affect our report dated April 15, 2012, which expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the adoption of Accounting Standards Update No. 2010-3, “Oil and Gas Reserve Estimation Disclosures.”

/s/ Deloitte & Touche LLP

Fort Worth, Texas

April 15, 2012

118

ITEM 9B.     Other Information

On July 26, 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arises out of recent press reports questioning the projected decline curves and economics of shale gas wells. We understand from the SEC that a number of other shale gas producers received similar subpoenas.

PART III

ITEM 10.     Directors, Executive Officers and Corporate Governance

The information concerning our directors set forth under “Corporate Governance Matters” in the proxy statement for our May 16, 2012 annual meeting of stockholders (“2012 Proxy Statement”) is incorporated herein by reference. The information concerning any changes to the procedure by which a security holder may recommend nominees to the board of directors set forth under “Corporate Governance Matters – Committees of the Board” in the 2012 Proxy Statement is incorporated herein by reference. Certain information concerning our executive officers is set forth under the heading “Business – Executive Officers of the Registrant” in Item 1 of this Annual Report. The information concerning compliance with Section 16(a) of the Exchange Act set forth under “Section 16(a) Beneficial Ownership Reporting Compliance” in the 2012 Proxy Statement is incorporated herein by reference.

The information concerning our audit committee set forth under “Corporate Governance Matters – Committees of the Board” in the 2012 Proxy Statement is incorporated herein by reference.

The information regarding our Code of Business Conduct and Ethics set forth under “Corporate Governance Matters – Corporate Governance Principles, Processes and Code of Business Conduct and Ethics” in the 2012 Proxy Statement is incorporated herein by reference.

ITEM 11.     Executive Compensation

The information set forth under “Executive Compensation,” “Corporate Governance Matters – Compensation Committee Interlocks and Insider Participation,” “Corporate Governance Matters – Director Compensation for 2011” and “Certain Relationships and Related Transactions” in the 2012 Proxy Statement is incorporated herein by reference.

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

The information set forth under “Security Ownership of Management and Certain Beneficial Holders” in the 2012 Proxy Statement is incorporated herein by reference. The information regarding our equity plans under which shares of our common stock are authorized for issuance as set forth under “Equity Compensation Plan Information” in the 2012 Proxy Statement is incorporated herein by reference.

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

The information set forth under “Certain Relationships and Related Transactions” in the 2012 Proxy Statement is incorporated herein by reference.

Information regarding our directors’ independence set forth under “Corporate Governance Matters – Independent Directors” in the 2012 Proxy Statement is incorporated herein by reference.

ITEM 14.     Principal Accountant Fees and Services

The information set forth under “Independent Registered Public Accountants” in the 2012 Proxy Statement is incorporated herein by reference.

119

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.

120

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		7/23/10
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		11/8/10
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		6/23/08
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		5/8/06
3.3	Amended and Restated Bylaws of Quicksilver Resources Inc.		8-K		001-14837		3.1		11/16/07
4.1	Indenture Agreement for 1.875% Convertible Subordinated Debentures Due 2024, dated as of November 1, 2004, between Quicksilver Resources Inc., as Issuer, and The Bank of New York, as Trustee (as successor in interest to JPMorgan Chase Bank, National Association)		8-K		001-14837		4.1		11/1/04
4.2	First Supplemental Indenture, dated July 31, 2009, between Quicksilver Resources Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee		10-Q		001-14837		4.2		8/10/09
4.3	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		12/22/05
4.4	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		3/21/06

121

		Incorporated by Reference								Filed (†)  or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form		SEC File No.		Exhibit		Filing Date
4.5	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		3/15/10
4.6	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		11/7/06
4.7	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		3/15/10
4.8	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		6/30/08
4.9	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		7/10/08
4.10	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		6/26/09
4.11	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		8/17/09
4.12	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										†

122

		Incorporated by Reference								Filed (†)  or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form		SEC File No.		Exhibit		Filing Date
4.13	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										†
4.14	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										†
4.15	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										†
4.16	Amended and Restated Rights Agreement, dated as of December 20, 2005, between Quicksilver Resources Inc. and Mellon Investor Services LLC, as Rights Agent		8-A/A		001-14837		4.1		12/21/05
4.17	Amendment dated as of February 23, 2011 to the Amended and Restated Rights Agreement between Quicksilver Resources Inc. and Mellon Investor Services LLC, as rights agent		8-K		001-14837		4.1		2/24/11
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		8/21/97
10.2**	Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan		8-K		001-14837		10.4		5/25/07
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		1/28/05
10.4**	Quicksilver Resources Inc. Fourth Amended and Restated 2006 Equity Plan										‡
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		5/25/06
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		11/24/08

123

		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		11/24/08
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		11/24/08
10.9**	Form of Incentive Stock Option Agreement pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended										†
10.10**	Form of Nonqualified Stock Option Agreement pursuant to the Quicksilver Resources Inc. 2006 Equity Plan, as amended										†
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		5/25/06
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		11/24/08
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		5/25/06
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		5/25/07
10.15**	Quicksilver Resources Inc. 2010 Executive Bonus Plan		8-K		001-14837		10.1		12/10/09
10.16**	Quicksilver Resources Inc. 2011 Executive Bonus Plan		8-K		001-14837		10.1		2/25/11
10.17**	Description of 2011 Cash Bonuses										†
10.18**	Quicksilver Resources Inc. Amended and Restated Change in Control Retention Incentive Plan		8-K		001-14837		10.9		11/24/08

124

		Incorporated by Reference								Filed (†)  or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form		SEC File No.		Exhibit		Filing Date
10.19**	Quicksilver Resources Inc. Second Amended and Restated Key Employee Change in Control Retention Incentive Plan		8-K		001-14837		10.8		11/24/08
10.20**	Quicksilver Resources Inc. Amended and Restated Executive Change in Control Retention Incentive Plan		8-K		001-14837		10.7		11/24/08
10.21**	Form of Director and Officer Indemnification Agreement (filed as Exhibit 10.2 to the Company’s Form 10-Q filed on November 8, 2010 and included herein by reference)		10-Q		001-14837		10.2		11/8/10
10.22	Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Inc. and the lenders identified therein		8-K		001-14837		10.1		2/12/07
10.23	Amended and Restated Credit Agreement, dated as of February 9, 2007, among Quicksilver Resources Canada Inc. and the lenders and/or agents identified therein		8-K		001-14837		10.2		2/12/07
10.24	First Amendment to Combined Credit Agreements, dated as of February 4, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein		10-K		001-14837		10.30		3/15/10
10.25	Second Amendment to Combined Credit Agreements, dated as of May 8, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein		10-K		001-14837		10.31		3/15/10
10.26	Third Amendment to Combined Credit Agreements, dated as of May 28, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein		10-K		001-14837		10.32		3/15/10
10.27	Fourth Amendment to Combined Credit Agreements, dated as of June 20, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein		8-K		001-14837		10.1		6/25/08

125

		Incorporated by Reference								Filed (†)  or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form		SEC File No.		Exhibit		Filing Date
10.28	Fifth Amendment to Combined Credit Agreements, dated as of August 4, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein		8-K		001-14837		10.1		8/5/08
10.29	Sixth Amendment to Combined Credit Agreements, dated as of September 30, 2008, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein		10-K		001-14837		10.35		3/15/10
10.30	Seventh Amendment to Combined Credit Agreements, dated as of April 20, 2009, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein		10-K		001-14837		10.36		3/15/10
10.31	Eighth Amendment to Combined Credit Agreements, dated as of May 28, 2009, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein		8-K		001-14837		10.1		6/17/09
10.32	Letter Agreement, dated as of June 15, 2009, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein		8-K		001-14837		10.1		6/17/09
10.33	Ninth Amendment to the Combined Credit Agreements, dated as of September 17, 2010, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein		10-Q		001-14837		10.1		11/8/10
10.34	Tenth Amendment to the Combined Credit Agreements, dated as of December 21, 2010, among Quicksilver Resources Inc., Quicksilver Resources Canada Inc. and the agents and combined lenders identified therein		8-K		001-14837		10.1		12/22/10
10.35	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		11/9/11

126

		Incorporated by Reference								Filed (†)  or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form		SEC File No.		Exhibit		Filing Date
10.36	Amended and Restated U.S. Credit Agreement, dated as of December 22, 2011, among Quicksilver Resources Inc. and the agents and lenders identified therein		8-K		001-14837		10.1		12/27/11
10.37	Credit Agreement, dated as of September 6, 2011, among Quicksilver Resources Canada Inc. and the agents and lenders identified therein		10-Q		001-14837		10.2		11/9/11
10.38	Amended and Restated Canadian Credit Agreement, dated as of December 22, 2011, among Quicksilver Resources Canada Inc. and the agents and lenders identified therein		8-K		001-14837		10.2		12/27/11
10.39	Asset Purchase Agreement, dated as of May 15, 2009, among Quicksilver Resources Inc., as Seller, and ENI US Operating Co. Inc. and ENI Petroleum US LLC, as Buyers		8-K		001-14837		10.1		5/19/09
10.40	Asset Purchase Agreement, dated May 11, 2010, between Marshall R. Young Oil Co., as Seller, and Quicksilver Resources Inc., as Buyer		8-K		001-14837		10.1		5/12/10
10.41	Confidentiality Agreement dated October 24, 2010 among Quicksilver Resources Inc. and Quicksilver Energy L.P		8-K		001-14837		10.1		10/25/10
10.42	Confidentiality Agreement dated October 26, 2010 among Quicksilver Resources Inc. and SPO Partners II, L.P.		8-K		001-14837		10.1		10/26/10
10.43	Limited Waiver dated as of February 23, 2011 between Quicksilver Resources Inc. and Quicksilver Energy L.P.		8-K		001-14837		10.1		2/24/11
10.44	Limited Waiver dated as of February 23, 2011 between Quicksilver Resources Inc. and SPO Partners II, L.P.		8-K		001-14837		10.2		2/24/11
10.45	Project and Expenditure Authorization, dated as of April 6, 2011, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd.		8-K		001-14837		10.1		4/14/11
10.46	Commitment Letter Agreement, dated as of April 6, 2011, between Quicksilver Resources Canada Inc. and Nova Gas Transmission Ltd.		8-K		001-14837		10.2		4/14/11

127

		Incorporated by Reference								Filed (†)  or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form		SEC File No.		Exhibit		Filing Date
10.47	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		001-14837		10.1		12/27/11
10.48	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		12/27/11
10.49	Gas Gathering Agreement, effective December 1, 2009, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.		8-K		001-33631		10.1		1/8/10
10.50	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		2/25/11
10.51	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		11/6/08
10.52	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		3/15/10
10.53	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		2/25/11
10.54	Amended and Restated Gas Gathering Agreement, effective September 1, 2008, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.										†
10.55	First Amendment to Amended and Restated Gas Gathering Agreement, dated September 29, 2009, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.										†

128

		Incorporated by Reference				Filed (†)  or Furnished (‡) Herewith (as indicated)
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date
10.56	Second Amendment to Gas Gathering Agreement, dated October 1, 2010, between Cowtown Pipeline L.P. and Quicksilver Resources Inc.						†
21.1*	List of subsidiaries of Quicksilver Resources Inc.						†
23.1	Consent of Deloitte & Touche LLP						†
23.2	Consent of Schlumberger Data and Consulting Services						†
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						†
99.1	Report of Schlumberger Data and Consulting Services						†
99.2	Report of LaRoche Petroleum Consultants, Ltd.						†

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

** Indicates a management contract or compensatory plan or arrangement

129

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: April 15, 2012		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/    Thomas F. Darden	Chairman of the Board; Director	April 15, 2012
Thomas F. Darden
/s/    Glenn Darden	President and Chief Executive Officer	April 15, 2012
Glenn Darden	(Principal Executive Officer); Director
/s/    Philip Cook	Executive Vice President – Chief Financial Officer	April 15, 2012
Philip Cook	(Principal Financial Officer)
/s/    John C. Regan	Vice President, Controller and Chief Accounting	April 15, 2012
John C. Regan	Officer (Principal Accounting Officer)
/s/    Anne Darden Self	Director	April 15, 2012
Anne Darden Self
/s/    W. Byron Dunn	Director	April 15, 2012
W. Byron Dunn
/s/    Steven M. Morris	Director	April 15, 2012
Steven M. Morris
/s/    Yandell Rogers, III	Director	April 15, 2012
W. Yandell Rogers, III
/s/    Mark J. Warner	Director	April 15, 2012
Mark J. Warner

130

EX-4.12

Exhibit 4.12

NINTH SUPPLEMENTAL INDENTURE

This NINTH SUPPLEMENTAL INDENTURE, dated as of December 23, 2011, among Barnett Operating LLC, a Delaware limited liability company (the “Guaranteeing Subsidiary”), a subsidiary of Quicksilver Resources Inc. (or its permitted successor), a Delaware corporation (the “Company”), the Company, the other Subsidiary Guarantors (as defined in the Indenture referred to herein) and The Bank of New York Mellon Trust Company N.A. (as successor in interest to JPMorgan Chase Bank, National Association (the “Initial Trustee”)), as Trustee.

W I T N E S S E T H

WHEREAS, the Company and the Trustee (as successor in interest to the Initial Trustee) entered into an Indenture (the “Original Indenture”), dated as of December 22, 2005, as supplemented by a First Supplemental Indenture, dated as of March 16, 2006 among the Company, the Subsidiary Guarantors and the Trustee (as successor in interest to the Initial Trustee) (the “First Supplemental Indenture”), a Second Supplemental Indenture, dated as of July 31, 2006 among the Company, the Subsidiary Guarantors and the Trustee (as successor in interest to the Initial Trustee) (the “Second Supplemental Indenture”), a Third Supplemental Indenture, dated as of September 26, 2006 among the Company, the Subsidiary Guarantors and the Trustee (as successor in interest to the Initial Trustee) (the “Third Supplemental Indenture”) and a Fourth Supplemental Indenture, dated as of October 31, 2007 among the Company, the Subsidiary Guarantors and the Trustee (the “Fourth Supplemental Indenture”; and together with the Original Indenture, the First Supplemental Indenture, the Second Supplemental Indenture and the Third Supplemental Indenture, the “Indenture”), pursuant to which the Company has issued $350,000,000 of aggregate principal amount of 7 ¹/8 % Senior Subordinated Notes due 2016 (the “Notes”);

WHEREAS, Section 6.01(b) of the First Supplemental Indenture provides that the Company, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture in order to add Subsidiary Guarantees with respect to the Notes, without the consent of the Holders of the Notes; and

WHEREAS, all acts and things prescribed by the Indenture, by law and by the Certificate of Incorporation and the Bylaws (or comparable constituent documents) of the Company, the Subsidiary Guarantors, the Guaranteeing Subsidiary and the Trustee necessary to make this Supplemental Indenture a valid instrument legally binding on the Company, the Subsidiary Guarantors, the Guaranteeing Subsidiary and the Trustee, in accordance with its terms, have been duly done and performed;

NOW THEREFORE, to comply with the provisions of the Indenture, and in consideration of the foregoing, the Guaranteeing Subsidiary, the Company, the Subsidiary Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

ARTICLE 1

Section 1.01. This Supplemental Indenture is supplemental to the Indenture and does and shall be deemed to form a part of, and shall be construed in connection with and as part of, the Indenture for any and all purposes.

Section 1.02. This Supplemental Indenture shall become effective immediately upon its execution and delivery by the Guaranteeing Subsidiary, the Company, the Subsidiary Guarantors and the Trustee.

ARTICLE 2

Section 2.01. The Guaranteeing Subsidiary hereby agrees to be bound by the terms, conditions and other provisions of the Indenture with all attendant rights, duties and obligations stated therein, on a joint and several basis with the Subsidiary Guarantors parties hereto and thereto, with the same force and effect as if originally named as a Subsidiary Guarantor therein and as if such party executed the Indenture on the date thereof.

ARTICLE 3

Section 3.01. Except as specifically modified herein, the Indenture and the Notes are in all respects ratified and confirmed (mutatis mutandis) and shall remain in full force and effect in accordance with their terms.

Section 3.02. All capitalized terms used but not defined herein shall have the same respective meanings ascribed to them in the Indenture.

Section 3.03. Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Supplemental Indenture. This Supplemental Indenture is executed and accepted by the Trustee subject to all of the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.

Section 3.04. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

Section 3.05. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

Section 3.06. The headings herein are inserted for convenience of reference only and are not intended to be part of, or to affect the meaning or interpretation of, this Supplemental Indenture.

Section 3.07. The recitals hereto are statements only of the Company, the Subsidiary Guarantors and the Guaranteeing Subsidiary and shall not be considered statements of or attributable to the Trustee.

2

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

BARNETT OPERATING LLC
By:	QUICKSILVER RESOURCES INC.,
	its member
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

QUICKSILVER RESOURCES INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN PIPELINE FUNDING, INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN PIPELINE MANAGEMENT, INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

[Signature Page to Ninth Supplemental Indenture]

3

COWTOWN PIPELINE L.P.
By:	COWTOWN PIPELINE MANAGEMENT, INC its general partner
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN GAS PROCESSING L.P.
By:	COWTOWN PIPELINE MANAGEMENT, INC its general partner
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

THE BANK OF NEW YORK MELLON TRUST     COMPANY, N.A., as Trustee
By:	/s/ Alejandro Hoyos
	Name: Alejandro Hoyos
	Title: Associate

[Signature Page to Ninth Supplemental Indenture]

4

EX-4.13

Exhibit 4.13

TENTH SUPPLEMENTAL INDENTURE

This TENTH SUPPLEMENTAL INDENTURE, dated as of December 23, 2011, among Barnett Operating LLC, a Delaware limited liability company (the “Guaranteeing Subsidiary”), a subsidiary of Quicksilver Resources Inc. (or its permitted successor), a Delaware corporation (the “Company”), the Company, the other Subsidiary Guarantors (as defined in the Indenture referred to herein) and The Bank of New York Trust Company, N.A., as Trustee.

W I T N E S S E T H

WHEREAS, the Company and the Trustee entered into an Indenture (the “Original Indenture”), dated as of December 22, 2005, as supplemented by a Fifth Supplemental Indenture, dated as of June 27, 2008 among the Company, the Subsidiary Guarantors and the Trustee (the “Fifth Supplemental Indenture”) and a Sixth Supplemental Indenture, dated as of July 10, 2008 among the Company, the Subsidiary Guarantors and the Trustee (the “Sixth Supplemental Indenture”; and together with the Original Indenture and the Fifth Supplemental Indenture, the “Indenture”), pursuant to which the Company has issued $475,000,000 of aggregate principal amount of 8 ¹/4% Senior Notes due 2015 (the “Notes”);

WHEREAS, Section 5.01(b) of the Fifth Supplemental Indenture provides that the Company, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture in order to add Subsidiary Guarantees with respect to the Notes, without the consent of the Holders of the Notes; and

WHEREAS, all acts and things prescribed by the Indenture, by law and by the Certificate of Incorporation and the Bylaws (or comparable constituent documents) of the Company, the Subsidiary Guarantors, the Guaranteeing Subsidiary and the Trustee necessary to make this Supplemental Indenture a valid instrument legally binding on the Company, the Subsidiary Guarantors, the Guaranteeing Subsidiary and the Trustee, in accordance with its terms, have been duly done and performed;

NOW THEREFORE, to comply with the provisions of the Indenture, and in consideration of the foregoing, the Guaranteeing Subsidiary, the Company, the Subsidiary Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

ARTICLE 1

Section 1.01 This Supplemental Indenture is supplemental to the Indenture and does and shall be deemed to form a part of, and shall be construed in connection with and as part of, the Indenture for any and all purposes.

Section 1.02 This Supplemental Indenture shall become effective immediately upon its execution and delivery by the Guaranteeing Subsidiary, the Company, the Subsidiary Guarantors and the Trustee.

ARTICLE 2

Section 2.01 The Guaranteeing Subsidiary hereby agrees to be bound by the terms, conditions and other provisions of the Indenture with all attendant rights, duties and obligations stated therein, on a joint and several basis with the Subsidiary Guarantors parties hereto and thereto, with the same force and effect as if originally named as a Subsidiary Guarantor therein and as if such party executed the Indenture on the date thereof.

ARTICLE 3

Section 3.01 Except as specifically modified herein, the Indenture and the Notes are in all respects ratified and confirmed (mutatis mutandis) and shall remain in full force and effect in accordance with their terms.

Section 3.02 All capitalized terms used but not defined herein shall have the same respective meanings ascribed to them in the Indenture.

Section 3.03 Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Supplemental Indenture. This Supplemental Indenture is executed and accepted by the Trustee subject to all of the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.

Section 3.04 THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

Section 3.05 The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

Section 3.06 The headings herein are inserted for convenience of reference only and are not intended to be part of, or to affect the meaning or interpretation of, this Supplemental Indenture.

Section 3.07 The recitals hereto are statements only of the Company, the Subsidiary Guarantors and the Guaranteeing Subsidiary and shall not be considered statements of or attributable to the Trustee.

Section 3.08 The Guaranteeing Subsidiary hereby designates the obligations with respect to the Notes and the Subsidiary Guarantees as Senior Indebtedness which is senior in right of payment in full to any Subordinated Obligation of the Company or any Subsidiary Guarantor. The Guaranteeing Subsidiary further designates the obligations with respect to the Notes and the Subsidiary Guarantees as “Designated Senior Indebtedness” (as defined by the (i) 1.875% Convertible Subordinated Debentures Indenture and (ii) the 7 ¹/8% Senior Subordinated Notes Indenture) for all purposes under (x) the 1.875% Convertible Subordinated Debentures

2

Indenture and (y) the 7 ¹/8% Senior Subordinated Notes Indenture, with respect to the Notes and the Subsidiary Guarantees, respectively.

3

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

BARNETT OPERATING LLC
By:	QUICKSILVER RESOURCES INC.,
	its member

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

QUICKSILVER RESOURCES INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN PIPELINE FUNDING, INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN PIPELINE MANAGEMENT, INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

[Signature Page to Tenth Supplemental Indenture]

4

COWTOWN PIPELINE L.P.
By:	COWTOWN PIPELINE MANAGEMENT, INC its general partner
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN GAS PROCESSING L.P.
By:	COWTOWN PIPELINE MANAGEMENT, INC its general partner
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

THE BANK OF NEW YORK MELLON TRUST     COMPANY, N.A., as Trustee
By:	/s/ Alejandro Hoyos
	Name: Alejandro Hoyos
	Title: Associate

[Signature Page to Tenth Supplemental Indenture]

5

EX-4.14

Exhibit 4.14

ELEVENTH SUPPLEMENTAL INDENTURE

This ELEVENTH SUPPLEMENTAL INDENTURE, dated as of December 23, 2011, among Barnett Operating LLC, a Delaware limited liability company (the “Guaranteeing Subsidiary”), a subsidiary of Quicksilver Resources Inc. (or its permitted successor), a Delaware corporation (the “Company”), the Company, the other Subsidiary Guarantors (as defined in the Indenture referred to herein) and The Bank of New York Mellon Trust Company, N.A., as Trustee.

W I T N E S S E T H

WHEREAS, the Company and the Trustee entered into an Indenture (the “Original Indenture”), dated as of December 22, 2005, as supplemented by a Seventh Supplemental Indenture, dated as of June 25, 2009 among the Company, the Subsidiary Guarantors and the Trustee (the “Seventh Supplemental Indenture”; and together with the Original Indenture, the “Indenture”), pursuant to which the Company has issued $600,000,000 of aggregate principal amount of 11 ³/4% Senior Notes due 2016 (the “Notes”);

WHEREAS, Section 5.01(b) of the Seventh Supplemental Indenture provides that the Company, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture in order to add Subsidiary Guarantees with respect to the Notes, without the consent of the Holders; and

WHEREAS, all acts and things prescribed by the Indenture, by law and by the certificate of incorporation and the bylaws (or comparable constituent documents) of the Company, the Subsidiary Guarantors, the Guaranteeing Subsidiary and the Trustee necessary to make this Supplemental Indenture a valid instrument legally binding on the Company, the Subsidiary Guarantors, the Guaranteeing Subsidiary and the Trustee, in accordance with its terms, have been duly done and performed;

NOW THEREFORE, to comply with the provisions of the Indenture, and in consideration of the foregoing, the Guaranteeing Subsidiary, the Company, the Subsidiary Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders as follows:

ARTICLE 1

Section 1.01 This Supplemental Indenture is supplemental to the Indenture and does and shall be deemed to form a part of, and shall be construed in connection with and as part of, the Indenture for any and all purposes.

Section 1.02 This Supplemental Indenture shall become effective immediately upon its execution and delivery by the Guaranteeing Subsidiary, the Company, the Subsidiary Guarantors and the Trustee.

ARTICLE 2

Section 2.01 The Guaranteeing Subsidiary hereby agrees to be bound by the terms, conditions and other provisions of the Indenture with all attendant rights, duties and obligations stated therein, on a joint and several basis with the Subsidiary Guarantors parties hereto and thereto, with the same force and effect as if originally named as a Subsidiary Guarantor therein and as if such party executed the Indenture on the date thereof.

ARTICLE 3

Section 3.01 Except as specifically modified herein, the Indenture and the Notes are in all respects ratified and confirmed (mutatis mutandis) and shall remain in full force and effect in accordance with their terms.

Section 3.02 All capitalized terms used but not defined herein shall have the same respective meanings ascribed to them in the Indenture.

Section 3.03 Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Supplemental Indenture. This Supplemental Indenture is executed and accepted by the Trustee subject to all of the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.

Section 3.04 THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

Section 3.05 The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

Section 3.06 The headings herein are inserted for convenience of reference only and are not intended to be part of, or to affect the meaning or interpretation of, this Supplemental Indenture.

Section 3.07 The recitals hereto are statements only of the Company, the Subsidiary Guarantors and the Guaranteeing Subsidiary and shall not be considered statements of or attributable to the Trustee.

Section 3.08 The Guaranteeing Subsidiary hereby designates the obligations with respect to the Notes and the Subsidiary Guarantees as Senior Indebtedness which is senior in right of payment in full to any Subordinated Obligation of the Company or any Subsidiary Guarantor. The Guaranteeing Subsidiary further designates the obligations with respect to the Notes and the Subsidiary Guarantees as “Designated Senior Indebtedness” (as defined by the (i) 2024 Convertible Subordinated Debentures Indenture and (ii) the 2016 Senior Subordinated

2

Notes Indenture) for all purposes under (x) the 2024 Convertible Subordinated Debentures Indenture and (y) the 2016 Senior Subordinated Notes Indenture, with respect to the Notes and the Subsidiary Guarantees, respectively.

[Signature Pages Follow]

3

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

BARNETT OPERATING LLC
By:	QUICKSILVER RESOURCES INC.,
	its member

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

QUICKSILVER RESOURCES INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN PIPELINE FUNDING, INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN PIPELINE MANAGEMENT, INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

[Signature Page to Eleventh Supplemental Indenture]

4

COWTOWN PIPELINE L.P.
By:	COWTOWN PIPELINE MANAGEMENT, INC its general partner
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN GAS PROCESSING L.P.
By:	COWTOWN PIPELINE MANAGEMENT, INC its general partner
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

THE BANK OF NEW YORK MELLON TRUST     COMPANY, N.A., as Trustee
By:	/s/ Alejandro Hoyos
	Name: Alejandro Hoyos
	Title: Associate

[Signature Page to Eleventh Supplemental Indenture]

5

EX-4.15

Exhibit 4.15

TWELFTH SUPPLEMENTAL INDENTURE

This TWELFTH SUPPLEMENTAL INDENTURE, dated as of December 23, 2011, among Barnett Operating LLC, a Delaware limited liability company (the “Guaranteeing Subsidiary”), a subsidiary of Quicksilver Resources Inc. (or its permitted successor), a Delaware corporation (the “Company”), the Company, the other Subsidiary Guarantors (as defined in the Indenture referred to herein) and The Bank of New York Mellon Trust Company, N.A., as Trustee.

W I T N E S S E T H

WHEREAS, the Company and the Trustee entered into an Indenture (the “Original Indenture”), dated as of December 22, 2005, as supplemented by an Eighth Supplemental Indenture, dated as of August 14, 2009 among the Company, the Subsidiary Guarantors and the Trustee (the “Eighth Supplemental Indenture”; and together with the Original Indenture, the “Indenture”), pursuant to which the Company has issued $300,000,000 of aggregate principal amount of 9 ¹/8% Senior Notes due 2019 (the “Notes”);

WHEREAS, Section 5.01(b) of the Eighth Supplemental Indenture provides that the Company, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture in order to add Subsidiary Guarantees with respect to the Notes, without the consent of the Holders; and

WHEREAS, all acts and things prescribed by the Indenture, by law and by the certificate of incorporation and the bylaws (or comparable constituent documents) of the Company, the Subsidiary Guarantors, the Guaranteeing Subsidiary and the Trustee necessary to make this Supplemental Indenture a valid instrument legally binding on the Company, the Subsidiary Guarantors, the Guaranteeing Subsidiary and the Trustee, in accordance with its terms, have been duly done and performed;

NOW THEREFORE, to comply with the provisions of the Indenture, and in consideration of the foregoing, the Guaranteeing Subsidiary, the Company, the Subsidiary Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders as follows:

ARTICLE 1

Section 1.01 This Supplemental Indenture is supplemental to the Indenture and does and shall be deemed to form a part of, and shall be construed in connection with and as part of, the Indenture for any and all purposes.

Section 1.02 This Supplemental Indenture shall become effective immediately upon its execution and delivery by the Guaranteeing Subsidiary, the Company, the Subsidiary Guarantors and the Trustee.

ARTICLE 2

Section 2.01 The Guaranteeing Subsidiary hereby agrees to be bound by the terms, conditions and other provisions of the Indenture with all attendant rights, duties and obligations stated therein, on a joint and several basis with the Subsidiary Guarantors parties hereto and thereto, with the same force and effect as if originally named as a Subsidiary Guarantor therein and as if such party executed the Indenture on the date thereof.

ARTICLE 3

Section 3.01 Except as specifically modified herein, the Indenture and the Notes are in all respects ratified and confirmed (mutatis mutandis) and shall remain in full force and effect in accordance with their terms.

Section 3.02 All capitalized terms used but not defined herein shall have the same respective meanings ascribed to them in the Indenture.

Section 3.03 Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Supplemental Indenture. This Supplemental Indenture is executed and accepted by the Trustee subject to all of the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.

Section 3.04 THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

Section 3.05 The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

Section 3.06 The headings herein are inserted for convenience of reference only and are not intended to be part of, or to affect the meaning or interpretation of, this Supplemental Indenture.

Section 3.07 The recitals hereto are statements only of the Company, the Subsidiary Guarantors and the Guaranteeing Subsidiary and shall not be considered statements of or attributable to the Trustee.

Section 3.08 The Guaranteeing Subsidiary hereby designates the obligations with respect to the Notes and the Subsidiary Guarantees as Senior Indebtedness which is senior in right of payment in full to any Subordinated Obligation of the Company or any Subsidiary Guarantor. The Guaranteeing Subsidiary further designates the obligations with respect to the Notes and the Subsidiary Guarantees as “Designated Senior Indebtedness” (as defined by the (i) 2024 Convertible Subordinated Debentures Indenture and (ii) the 2016 Senior Subordinated

2

Notes Indenture) for all purposes under (x) the 2024 Convertible Subordinated Debentures Indenture and (y) the 2016 Senior Subordinated Notes Indenture, with respect to the Notes and the Subsidiary Guarantees, respectively.

[Signature Pages Follow]

3

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

BARNETT OPERATING LLC
By:	QUICKSILVER RESOURCES INC.,
	its member

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

QUICKSILVER RESOURCES INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN PIPELINE FUNDING, INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN PIPELINE MANAGEMENT, INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

[Signature Page to Twelfth Supplemental Indenture]

4

COWTOWN PIPELINE L.P.
By:	COWTOWN PIPELINE MANAGEMENT, INC its general partner
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

COWTOWN GAS PROCESSING L.P.
By:	COWTOWN PIPELINE MANAGEMENT, INC its general partner
By:	/s/ Glenn Darden
	Name: Glenn Darden
	Title: President and Chief Executive Officer

THE BANK OF NEW YORK MELLON TRUST     COMPANY, N.A., as Trustee
By:	/s/ Alejandro Hoyos
	Name: Alejandro Hoyos
	Title: Associate

[Signature Page to Twelfth Supplemental Indenture]

5

EX-10.4

Exhibit 10.4

QUICKSILVER RESOURCES INC.

FOURTH AMENDED AND RESTATED

2006 EQUITY PLAN

QUICKSILVER RESOURCES INC.

FOURTH AMENDED AND RESTATED

2006 EQUITY PLAN

SECTION		PAGE
1.	Purpose		1
2.	Term		1
3.	Definitions		1
4.	Shares Available Under Plan		5
5.	Limitations on Awards		6
6.	Stock Options		6
7.	Appreciation Rights		8
8.	Restricted Shares		9
9.	Restricted Stock Units		10
10.	Performance Shares and Performance Units		11
11.	Senior Executive Plan Bonuses		12
12.	Awards to Eligible Directors		13
13.	Transferability		18
14.	Adjustments		18
15.	Fractional Shares		19
16.	Withholding Taxes		19
17.	Administration of the Plan		19
18.	Amendments and Other Matters		20
19.	Governing Law		21

QUICKSILVER RESOURCES INC.

FOURTH AMENDED AND RESTATED

2006 EQUITY PLAN

The Quicksilver Resources Inc. 2006 Equity Plan (the “Plan”) was established by Quicksilver Resources Inc., a Delaware corporation (the “Company”), effective as of May 23, 2006, and approved by stockholders of the Company on May 23, 2006. The Company amended and restated the Plan effective as of May 23, 2007, November 24, 2008 and May 20, 2009, and again amends and restates the Plan effective as of November 16, 2011.

1. Purpose. The purpose of the Plan is to attract and retain the best available talent and encourage the highest level of performance by directors, executive officers and selected employees and consultants, and to provide them incentives to put forth maximum efforts for the success of the Company’s business, in order to serve the best interests of the Company and its stockholders.

2. Term. The Plan will expire on May 23, 2016. No further Awards will be made under the Plan on or after such date. Awards that are outstanding on the date the Plan terminates will remain in effect according to their terms and the provisions of the Plan.

3. Definitions. The following terms, when used in the Plan with initial capital letters, will have the following meanings:

(a) Appreciation Right means a right granted pursuant to Section 7.

(b) Award means the award of a Senior Executive Plan Bonus; the grant of Appreciation Rights, Stock Options, Performance Shares, Performance Units or Restricted Stock Units; or the grant or sale of Restricted Shares. An Award may be an obligation of the Company or any Subsidiary.

(c) Board means the Board of Directors of the Company.

(d) Change in Control means the occurrence of any of the following events:

(i) any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) is or becomes the beneficial owner (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 50% or more of the combined voting power of the then-outstanding Voting Stock of the Company; provided, however, that the following acquisitions will not constitute a Change in Control: (A) any acquisition of Voting Stock of the Company directly from the Company that is approved by a majority of the Incumbent Directors; (B) any acquisition of Voting Stock of the Company by the Company or any subsidiary of the Company; (C) any acquisition of Voting Stock of the Company by the trustee or other fiduciary holding securities under any employee benefit plan (or related trust) sponsored or maintained by the Company or any subsidiary of the Company; and (D) any acquisition of Voting Stock of the Company by Mercury Exploration Company, Quicksilver Energy, L.P., The

Discovery Fund, Pennsylvania Avenue Limited Partnership, Pennsylvania Management Company, the estate of Frank Darden, Lucy Darden, Anne Darden Self, Glenn Darden or Thomas Darden, or their respective successors, assigns, designees, heirs, beneficiaries, trusts, estates or controlled affiliates;

(ii) a majority of the Board ceases to be comprised of Incumbent Directors; or

(iii) the consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the consolidated assets of the Company (each, a “Business Combination Transaction”) immediately after which (A) the Voting Stock of the Company outstanding immediately prior to such Business Combination Transaction does not continue to represent (either by remaining outstanding or by being converted into Voting Stock of the entity surviving, resulting from, or succeeding to all or substantially all of the Company’s consolidated assets as a result of, such Business Combination Transaction or any parent of such entity), at least 50% of the combined voting power of the then outstanding shares of Voting Stock of the entity surviving, resulting from, or succeeding to all or substantially all of the Company’s consolidated assets as a result of, such Business Combination Transaction or any parent of any such entity (including, without limitation, an entity which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries).

(e) Code means the Internal Revenue Code of 1986, as amended.

(f) Committee means the Compensation Committee of the Board and, to the extent the administration of the Plan has been assumed by the Board pursuant to Section 17 or with respect to the administration of Section 12, the Board.

(g) Common Stock means the common stock, par value $.01 per share, of the Company or any security into which such Common Stock may be changed by reason of any transaction or event of the type described in Section 14.

(h) Covered Employee means a Participant who is, or is determined by the Committee to be likely to become, a “covered employee” within the meaning of Section 162(m) of the Code (or any successor provision) and who is identified in writing by the Committee as a Covered Employee within the period specified in Section 11(a) for the fiscal year.

(i) Date of Grant means the date specified by the Committee on which an Award will become effective.

(j) Deferral Period means the period of time during which Restricted Stock Units are subject to deferral limitations under Section 9.

(k) Eligible Director means a member of the Board who is not an employee of the Company or any Subsidiary.

2

(l) Evidence of Award means an agreement, certificate, resolution or other type or form of writing or other evidence approved by the Committee which sets forth the terms and conditions of an Award. An Evidence of Award may be in any electronic medium, may be limited to a notation on the books and records of the Company and need not be signed by a representative of the Company or a Participant.

(m) Exchange Act means the Securities Exchange Act of 1934, as amended.

(n) Grant Price means the price per share of Common Stock at which an Appreciation Right is granted.

(o) Incumbent Directors means the individuals who, as of the date first set forth above, are Directors of the Company and any individual becoming a Director subsequent to the date thereof whose election, nomination for election by the Company’s stockholders, or appointment, was approved by a vote of a majority of the then-Incumbent Directors (either by a specific vote or by approval of the proxy statement of the Company in which such person is named as a nominee for director, without objection to such nomination).

(p) Management Objectives means the measurable performance objectives, if any, established by the Committee for a Performance Period that are to be achieved with respect to an Award. Management Objectives may be described in terms of company-wide objectives (i.e., the performance of the Company and all of its Subsidiaries) or in terms of objectives that are related to the performance of the individual Participant or of the division, Subsidiary, department, region or function within the Company or a Subsidiary in which the Participant receiving the Award is employed or on which the Participant’s efforts have the most influence. The achievement of the Management Objectives established by the Committee for any Performance Period will be determined without regard to the effect on such Management Objectives of any acquisition or disposition by the Company of a trade or business, or of substantially all of the assets of a trade or business, during the Performance Period and without regard to any change in accounting standards by the Financial Accounting Standards Board or any successor entity.

The Management Objectives applicable to any Award to a Participant who is a Covered Employee for the fiscal year will be limited to specified levels of, growth in, or performance in, one or more of the following performance measures (excluding the effect of extraordinary or nonrecurring items unless the Committee specifically includes any such extraordinary or nonrecurring item at the time such Award is granted):

(i) profitability measures;

(ii) cash flow measures;

(iii) proven reserves;

(iv) production growth rate;

3

(v) revenue measures;

(vi) business unit performance;

(vii) leverage measures;

(viii) stockholder return;

(ix) expense management;

(x) asset and liability measures;

(xi) individual performance;

(xii) supply chain efficiency;

(xiii) productivity measures;

(xiv) return measures; or

(xv) product development and/or performance.

If the Committee determines that, as a result of a change in the business, operations, corporate structure or capital structure of the Company (other than an acquisition or disposition described in the first paragraph of this Section 3(p)), or the manner in which the Company conducts its business, or any other events or circumstances, the Management Objectives are no longer suitable, the Committee may in its discretion modify such Management Objectives or the related minimum acceptable level of achievement, in whole or in part, with respect to a Performance Period as the Committee deems appropriate and equitable.

(q) Market Value per Share means, at any date, the closing sale price of the Common Stock on that date (or, if there are no sales on that date, the last preceding date on which there was a sale) on the principal national securities exchange or in the principal market on or in which the Common Stock is traded.

(r) Option Price means the purchase price per share payable on exercise of a Stock Option.

(s) Participant means a (i) person who is selected by the Committee to receive an Award under the Plan and who at that time is an executive officer or other employee of or a consultant to the Company or any Subsidiary or (ii) an Eligible Director.

(t) Performance Period means, with respect to an Award, a period of time within which the Management Objectives relating to such Award are to be measured. The Performance Period for a Senior Executive Plan Bonus will be the fiscal year of the Company, and, unless otherwise expressly provided in the Plan, the Performance Period for all other Awards will be established by the Committee at the time of the Award.

4

(u) Performance Share means a bookkeeping entry that records the equivalent of one share of Common Stock awarded pursuant to Section 10.

(v) Performance Unit means a unit equivalent to $1.00 (or such other value as the Committee determines) granted pursuant to Section 10.

(w) Restricted Stock Units means an Award pursuant to Section 9 of the right to receive shares of Common Stock, cash or other consideration at the end of a specified Deferral Period.

(x) Restricted Shares means shares of Common Stock granted or sold pursuant to Section 8 or Section 12 as to which neither the ownership restrictions nor the restrictions on transfer have expired.

(y) Rule 16b-3 means Rule 16b-3 under Section 16 of the Exchange Act, as amended (or any successor rule to the same effect).

(z) Senior Executive Plan Bonus means an Award of annual incentive compensation made pursuant to and subject to the conditions set forth in Section 11.

(aa) Spread means the excess of the Market Value per Share on the date an Appreciation Right is exercised over (i) the Option Price provided for in the Stock Option granted in tandem with the Appreciation Right or (ii) if there is no tandem Stock Option, the Grant Price provided for in the Appreciation Right, in either case multiplied by the number of shares of Common Stock in respect of which the Appreciation Right is exercised.

(bb) Stock Option means the right to purchase shares of Common Stock upon exercise of an option granted pursuant to Section 6 or Section 12.

(cc) Subsidiary means (i) any corporation of which at least 50% of the combined voting power of the then outstanding shares of Voting Stock is owned directly or indirectly by the Company, (ii) any partnership of which at least 50% of the profits interest or capital interest is owned directly or indirectly by the Company and (iii) any other entity of which at least 50% of the total equity interest is owned directly or indirectly by the Company.

(dd) Voting Stock means the securities entitled to vote generally in the election of directors or persons who serve similar functions.

4. Shares Available Under Plan. The aggregate number of shares of Common Stock that may be (i) subject to an Award of Appreciation Rights or Stock Options or (ii) issued or transferred as Restricted Shares and released from all restrictions or in payment of Performance Shares, Performance Units, Restricted Stock Units or Senior Executive Plan Bonuses will not exceed in the aggregate 15 million shares. Such shares may be shares of

5

original issuance, treasury shares, shares acquired by the Company or any of its Subsidiaries in the open market or otherwise or a combination of the foregoing. The number of shares of Common Stock available under this Section 4 will be subject to adjustment as provided in Section 14 and will be further adjusted to include shares that relate to Awards that (i) expire or are forfeited, (ii) are withheld by, or tendered to, the Company or a Subsidiary in payment of the Option Price with respect to a Stock Option or in satisfaction of the taxes required to be withheld in connection with any Award granted under the Plan or (iii) are subject to an Appreciation Right that are not transferred to a Participant upon exercise of the Appreciation Right.

5. Limitations on Awards. Awards under the Plan will be subject to the following limitations:

(a) No more than 15 million shares of Common Stock, subject to adjustment as provided in Section 4, may be subject to an Award of Stock Options that are intended to qualify as incentive stock options under Section 422 of the Code.

(b) The maximum number of shares of Common Stock that may be subject to all Awards granted to a Participant during any calendar year will not exceed 1,500,000 shares. The limitations set forth in this Section 5(b) will apply without regard to whether an Award is settled in cash or in shares of Common Stock.

(c) The maximum aggregate cash value of payments to any Participant for any Performance Period pursuant to an award of Performance Units will not exceed $5 million.

(d) The payment of a Senior Executive Plan Bonus to any Participant will not exceed $5 million.

6. Stock Options. The Committee may from time to time authorize grants of options to any Participant to purchase shares of Common Stock upon such terms and conditions as it may determine in accordance with this Section 6. Each Participant who is an employee of the Company or any Subsidiary will be eligible to receive a grant of Stock Options that are intended to qualify as incentive stock options within the meaning of Section 422 of the Code. Each grant of Stock Options may utilize any or all of the authorizations, and will be subject to all of the requirements, contained in the following provisions:

(a) Each grant will specify the number of shares of Common Stock to which it relates.

(b) Each grant will specify the Option Price, which will not be less than 100% of the Market Value per Share on the Date of Grant.

(c) Each grant will specify whether the Option Price will be payable (i) in cash or by check acceptable to the Company or a Subsidiary, as the case may be, or by wire transfer of immediately available funds, (ii) by the actual or constructive transfer to the Company or a Subsidiary of shares of Common Stock owned by the Participant and having an aggregate Market Value per Share at the date of exercise equal to the aggregate Option Price, (iii) with the consent of the Committee, by authorizing the Company or a

6

Subsidiary to withhold a number of shares of Common Stock otherwise issuable or deliverable to the Participant having an aggregate Market Value per Share on the date of exercise equal to the aggregate Option Price, (iv) by a combination of such methods of payment or (v) by any other method of payment approved by the Committee; provided, however, that the payment methods described in clauses (ii) and (iii) will not be available at any time that the Company or, if applicable, the Subsidiary is prohibited from purchasing or acquiring such shares of Common Stock.

(d) To the extent permitted by law, any grant may provide for deferred payment of the Option Price from the proceeds of sale through a bank or broker of some or all of the shares to which such exercise relates.

(e) Successive grants may be made to the same Participant whether or not any Stock Options or other Awards previously granted to such Participant remain unexercised or outstanding.

(f) Each grant will specify the required period or periods of continuous service by the Participant with the Company or any Subsidiary that are necessary before the Stock Options or installments thereof will become exercisable.

(g) Any grant may specify the Management Objectives that must be achieved as a condition to the exercise of the Stock Options.

(h) Any grant may provide for the earlier exercise of the Stock Options in the event of a Change in Control or other similar transaction or event.

(i) Stock Options may be (i) options which are intended to qualify under particular provisions of the Code, (ii) options which are not intended to so qualify or (iii) combinations of the foregoing.

(j) On or after the Date of Grant, the Committee may provide for the payment to the Participant of dividend equivalents thereon in cash or Common Stock on a current, deferred or contingent basis.

(k) No Stock Option will be exercisable more than ten years from the Date of Grant, unless the Evidence of Award provides for an extended exercise period in the event of death, disability or retirement.

(l) The Committee will have the right to substitute Appreciation Rights for outstanding Options granted to one or more Participants, provided the terms and the economic benefit of the substituted Appreciation Rights are at least equivalent to the terms and economic benefit of such Options, as determined by the Committee in its discretion.

(m) Any grant may provide for the effect on the Stock Options or any shares of Common Stock issued, or other payment made, with respect to the Stock Options of any conduct of the Participant determined by the Committee to be injurious, detrimental or prejudicial to any significant interest of the Company or any Subsidiary.

7

(n) Each grant will be evidenced by an Evidence of Award, which may contain such terms and provisions, consistent with the Plan, as the Committee may approve, including without limitation provisions relating to the Participant’s termination of employment or other termination of service by reason of retirement, death, disability or otherwise.

7. Appreciation Rights. The Committee may also from time to time authorize grants to any Participant of Appreciation Rights upon such terms and conditions as it may determine in accordance with this Section 7. Appreciation Rights may be granted in tandem with Stock Options or separate and apart from a grant of Stock Options. An Appreciation Right will be a right of the Participant to receive from the Company or a Subsidiary upon exercise an amount which will be determined by the Committee at the Date of Grant and will be expressed as a percentage of the Spread (not exceeding 100%) at the time of exercise. An Appreciation Right granted in tandem with a Stock Option may be exercised only by surrender of the related Stock Option. Each grant of an Appreciation Right may utilize any or all of the authorizations, and will be subject to all of the requirements, contained in the following provisions:

(a) Each grant will state whether it is made in tandem with Stock Options and, if not made in tandem with any Stock Options, will specify the number of shares of Common Stock in respect of which it is made.

(b) Each grant made in tandem with Stock Options will specify the Option Price and each grant not made in tandem with Stock Options will specify the Grant Price, which in either case will not be less than 100% of the Market Value per Share on the Date of Grant.

(c) Any grant may provide that the amount payable on exercise of an Appreciation Right may be paid (i) in cash or other consideration, (ii) in shares of Common Stock having an aggregate Market Value per Share equal to the Spread (or the designated percentage of the Spread) or (iii) in a combination thereof, as determined by the Committee in its discretion.

(d) Any grant may specify that the amount payable to the Participant on exercise of an Appreciation Right may not exceed a maximum amount specified by the Committee at the Date of Grant.

(e) Successive grants may be made to the same Participant whether or not any Appreciation Rights or other Awards previously granted to such Participant remain unexercised or outstanding.

(f) Each grant will specify the required period or periods of continuous service by the Participant with the Company or any Subsidiary that are necessary before the Appreciation Rights or installments thereof will become exercisable, and will provide that no Appreciation Rights may be exercised except at a time when the Spread is positive and, with respect to any grant made in tandem with Stock Options, when the related Stock Options are also exercisable.

8

(g) Any grant may specify the Management Objectives that must be achieved as a condition to the exercise of the Appreciation Rights.

(h) Any grant may provide for the earlier exercise of the Appreciation Rights in the event of a Change in Control or other similar transaction or event.

(i) On or after the Date of Grant, the Committee may provide for the payment to the Participant of dividend equivalents thereon in cash or Common Stock on a current, deferred or contingent basis.

(j) No Appreciation Right will be exercisable more than ten years from the Date of Grant.

(k) Any grant may provide for the effect on the Appreciation Rights or any shares of Common Stock issued, or other payment made, with respect to the Appreciation Rights of any conduct of the Participant determined by the Committee to be injurious, detrimental or prejudicial to any significant interest of the Company or any Subsidiary.

(l) Each grant will be evidenced by an Evidence of Award, which may contain such terms and provisions, consistent with the Plan, as the Committee may approve, including without limitation provisions relating to the Participant’s termination of employment or other termination of service by reason of retirement, death, disability or otherwise.

8. Restricted Shares. The Committee may also from time to time authorize grants or sales to any Participant of Restricted Shares upon such terms and conditions as it may determine in accordance with this Section 8. Each grant or sale will constitute an immediate transfer of the ownership of shares of Common Stock to the Participant in consideration of the performance of services, entitling such Participant to voting and other ownership rights, but subject to the restrictions set forth in this Section 8. Each such grant or sale may utilize any or all of the authorizations, and will be subject to all of the requirements, contained in the following provisions:

(a) Each grant or sale may be made without additional consideration or in consideration of a payment by the Participant that is less than the Market Value per Share at the Date of Grant, except as may otherwise be required by the Delaware General Corporation Law or other applicable law.

(b) Each grant or sale may limit the Participant’s dividend rights during the period in which the shares of Restricted Shares are subject to any such restrictions.

(c) Each grant or sale will provide that the Restricted Shares will be subject, for a period to be determined by the Committee at the Date of Grant, to one or more restrictions, including without limitation a restriction that constitutes a “substantial risk of forfeiture” within the meaning of Section 83 of the Code and the regulations of the Internal Revenue Service under such section. Except as provided in Section 8(d), 8(e) or 12(d), the restrictions imposed on Restricted Shares will not terminate at a rate that is faster than 1/3rd of the Restricted Shares on each anniversary of the Date of Grant.

9

(d) Any grant or sale may specify the Management Objectives that, if achieved, will result in the termination or early termination of the restrictions applicable to the shares, provided that the Performance Period associated with such Management Objectives will be a period of no less than 12 calendar months.

(e) Any grant or sale may provide for the early termination of any such restrictions in the event of a Change in Control or other similar transaction or event or the Participant’s termination of employment or service by reason of death, disability, retirement or otherwise.

(f) Each grant or sale will provide that during the period for which such restriction or restrictions are to continue, the transferability of the Restricted Shares will be prohibited or restricted in a manner and to the extent prescribed by the Committee at the Date of Grant (which restrictions may include without limitation rights of repurchase or first refusal in favor of the Company or provisions subjecting the Restricted Shares to continuing restrictions in the hands of any transferee).

(g) Any grant or sale may provide for the effect on the Restricted Shares or any shares of Common Stock issued free of restrictions, or other payment made, with respect to the Restricted Shares of any conduct of the Participant determined by the Committee to be injurious, detrimental or prejudicial to any significant interest of the Company or any Subsidiary.

(h) Each grant or sale will be evidenced by an Evidence of Award, which may contain such terms and provisions, consistent with the Plan, as the Committee may approve, including without limitation provisions relating to the Participant’s termination of employment or other termination of service by reason of retirement, death, disability or otherwise.

9. Restricted Stock Units. The Committee may also from time to time authorize grants or sales to any Participant of Restricted Stock Units upon such terms and conditions as it may determine in accordance with this Section 9. Each grant or sale will constitute the agreement by the Company or a Subsidiary to deliver shares of Common Stock, cash or other consideration to the Participant in the future in consideration of the performance of services, subject to the fulfillment during the Deferral Period of such conditions as the Committee may specify. Each such grant or sale may utilize any or all of the authorizations, and will be subject to all of the requirements, contained in the following provisions:

(a) Each grant or sale may be made without additional consideration from the Participant or in consideration of a payment by the Participant that is less than the Market Value per Share on the Date of Grant, except as may otherwise be required by the Delaware General Corporation Law or other applicable law.

(b) Each grant or sale will provide that the Restricted Stock Units will be subject to a Deferral Period, which will be fixed by the Committee on the Date of Grant. Except as provided in Section 9(c) or 9(d), the Deferral Period will not terminate at a rate that is faster than 1/3rd of the Restricted Stock Units on each anniversary of the Date of Grant.

10

(c) Any grant or sale may specify the Management Objectives that, if achieved, will result in the termination or early termination of the Deferral Period, provided that the Performance Period associated with such Management Objectives will be a period of no less than 12 calendar months.

(d) Any grant or sale may provide for the earlier termination of the Deferral Period in the event of a Change in Control or other similar transaction or event or the Participant’s termination of employment or service by reason of death, disability, retirement or otherwise.

(e) During the Deferral Period, the Participant will not have any right to transfer any rights under the Restricted Stock Units, and will not have any rights of ownership in or any right to vote any shares of Common Stock that may be issued in settlement of Restricted Stock Units, but the Committee may on or after the Date of Grant authorize the payment of dividend equivalents on such shares in cash or Common Stock on a current, deferred or contingent basis.

(f) Any grant or sale may provide for the effect on the Restricted Stock Units or any shares of Common Stock issued free of restrictions, or other payment made, with respect to the Restricted Stock Units of any conduct of the Participant determined by the Committee to be injurious, detrimental or prejudicial to any significant interest of the Company or any Subsidiary.

(g) Each grant or sale will be evidenced by an Evidence of Award, which will contain such terms and provisions as the Committee may determine consistent with the Plan, including without limitation provisions relating to the Participant’s termination of employment or other termination of service by reason of retirement, death, disability or otherwise.

10. Performance Shares and Performance Units. The Committee may also from time to time authorize grants to any Participant of Performance Shares and Performance Units, which will become payable upon achievement of specified Management Objectives, upon such terms and conditions as it may determine in accordance with this Section 10. Each such grant may utilize any or all of the authorizations, and will be subject to all of the requirements, contained in the following provisions:

(a) Each grant will specify the number of Performance Shares or Performance Units to which it relates.

(b) The Performance Period with respect to each Performance Share and Performance Unit will be determined by the Committee at the time of grant and will be a period of no less than 12 calendar months.

(c) Each grant will specify the Management Objectives that, if achieved, will result in the payment of the Performance Shares or Performance Units.

11

(d) Each grant will specify the time and manner of payment of Performance Shares or Performance Units which have become payable, which payment may be made in (i) cash, (ii) shares of Common Stock having an aggregate Market Value per Share equal to the aggregate value of the Performance Shares or Performance Units which have become payable or (iii) any combination thereof, as determined by the Committee in its discretion at the time of payment.

(e) Any grant of Performance Shares may specify that the amount payable with respect thereto may not exceed a maximum specified by the Committee on the Date of Grant. Any grant of Performance Units may specify that the amount payable, or the number of shares of Common Stock issued, with respect to the Performance Units may not exceed maximums specified by the Committee on the Date of Grant.

(f) On or after the Date of Grant, the Committee may provide for the payment to the Participant of dividend equivalents on Performance Shares in cash or Common Stock on a current, deferred or contingent basis.

(g) Any grant may provide for the effect on the Performance Shares or Performance Units or any shares of Common Stock issued, or other payment made, with respect to the Performance Shares or Performance Units of any conduct of the Participant determined by the Committee to be injurious, detrimental or prejudicial to any significant interest of the Company or any Subsidiary.

(h) Each grant will be evidenced by an Evidence of Award, which will contain such terms and provisions as the Committee may determine consistent with the Plan, including without limitation provisions relating to the payment of the Performance Shares or Performance Units in the event of a Change in Control or other similar transaction or event and provisions relating to the Participant’s termination of employment or other termination of service by reason of retirement, death, disability or otherwise.

11. Senior Executive Plan Bonuses. The Committee may from time to time authorize the payment of annual incentive compensation to a Participant who is a Covered Employee, which incentive compensation will become payable upon achievement of specified Management Objectives. Subject to Section 5(d), Senior Executive Plan Bonuses will be payable upon such terms and conditions as the Committee may determine in accordance with the following provisions:

(a) No later than 90 days after the first day of the Company’s fiscal year, the Committee will specify the Management Objectives that, if achieved, will result in the payment of a Senior Executive Plan Bonus for such year.

(b) Following the close of the Company’s fiscal year, the Committee will certify in writing whether the specified Management Objectives have been achieved. Approved minutes of a meeting of the Committee at which such certification is made will be treated as written certification for this purpose. The Committee will also specify the time and manner of payment of a Senior Executive Plan Bonus which becomes payable,

12

which payment may be made in (i) cash or other consideration, (ii) shares of Common Stock having an aggregate Market Value per Share equal to the aggregate value of the Senior Executive Plan Bonus which has become payable or (iii) any combination thereof, as determined by the Committee in its discretion at the time of payment.

(c) If a Change in Control occurs during a Performance Period, the Senior Executive Plan Bonus payable to each Participant for the Performance Period will be determined at the highest level of achievement of the Management Objectives, without regard to actual performance and without proration for less than a full Performance Period. The Senior Executive Plan Bonus will be paid at such time following the Change in Control as the Committee determines in its discretion, but in no event later than 30 days after the date of an event which results in a Change in Control.

(d) Each grant may be evidenced by an Evidence of Award, which will contain such terms and provisions as the Committee may determine consistent with the Plan, including without limitation provisions relating to the Participant’s termination of employment by reason of retirement, death, disability or otherwise.

12. Awards to Eligible Directors.

(a) Each individual who first becomes an Eligible Director after December 31, 2008, on a date subsequent to the first business day of a calendar year will be granted (i) a number of Restricted Shares as of the date such individual becomes an Eligible Director equal to $49,500 (if the individual becomes an Eligible Director prior to July 1 of any year) or $24,750 (if the individual becomes an Eligible Director on or after July 1 of any year) divided by the Market Value per Share as of the date the individual first becomes an Eligible Director, and (ii) a Stock Option as of the date the individual first becomes an Eligible Director to purchase a number of shares of Common Stock equal to $49,500 (if the individual becomes an Eligible Director prior to July 1 of any year) or $24,750 (if the individual becomes an Eligible Director on or after July 1 of any year) divided by the Fair Value (as hereinafter defined). For purposes of this Section 12(a), an Eligible Director who ceases to be a member of the Board and thereafter becomes an Eligible Director again will be deemed to first become an Eligible Director on the date that such individual again becomes an Eligible Director.

(b) On the first business day of each calendar year beginning during the term of the Plan and after December 31, 2008, each individual who is an Eligible Director (i) will be granted as of such first business day a number of Restricted Shares equal to $49,500 divided by the Market Value per Share as of that date, (ii) will be granted as of such first business day a Stock Option to purchase a number of shares of Common Stock determined by dividing $49,500 by the Fair Value as of that date, and (iii) may elect to receive either an additional grant of Restricted Shares or a Stock Option to purchase shares of Common Stock in lieu of all or any portion of additional cash compensation of $106,000, provided that, in either case, the Eligible Director has elected in writing on or prior to the last day of the preceding calendar year to receive the Restricted Shares or the Stock Option described in this Section 12(b)(iii) in lieu of an equivalent amount of cash compensation from the Company. If applicable, the number of Restricted Shares to be

13

granted under Section 12(b)(iii) will be determined by dividing the amount of cash compensation the Restricted Shares are replacing by the Market Value per Share as of such first business day of the calendar year, and the number of shares covered by a Stock Option elected under Section 12(b)(iii) will be determined by dividing the amount of cash compensation the Stock Option is replacing by the Fair Value as of such first business day of the calendar year.

(c) For purposes of this Section 12, “Fair Value” means either the Black Scholes Value (described below) or the value of a Stock Option to purchase one share of Common Stock calculated using such other valuation methodology as may at the time of grant be used by the Company to value Stock Options for financial reporting purposes, in each case calculated as of the date of grant of the Stock Option. For this purpose, “Black Scholes Value” means the value of a Stock Option to purchase one share of Common Stock calculated using the Black Scholes option value model. Unless otherwise provided by the Board prior to the applicable date of grant, the Black Scholes option valuation for a Stock Option to be granted on any date will be based on the following assumptions:

(i) the then current price of a share of Common Stock is equal to the Market Value per Share of Common Stock as of the date of grant of the Stock Option;

(ii) the per share Option Price is equal to the Market Value per Share of Common Stock as of the date of grant of the Stock Option;

(iii) the time until expiration of the Stock Option is equal to the actual time until expiration of the Stock Option (determined without regard to the provisions of Sections 12(e)(vii) and 12(e)(viii));

(iv) the risk-free interest rate is the asked yield rate, as of the business day preceding the date of grant of the Stock Option and as reported in the Wall Street Journal, for the U.S. Treasury Note or Bond having a maturity date that is closest to the date that is five years after the date of grant of the Stock Option;

(v) the volatility of the price of the Common Stock is calculated based on the closing price of a share of Common Stock on the last trading day of each month for each of the 60 months preceding the month in which the date of grant of the Stock Option occurs; and

(vi) the dividend yield on the Common Stock equals the rate determined by dividing the product of four and the most recent quarterly dividend on the Common Stock as of the date of grant of the Stock Option by the Market Value per Share of Common Stock as of the date of grant of the Stock Option.

(d) Each grant of Restricted Shares to an Eligible Director may utilize any or all of the authorizations, and will be subject to all of the requirements, contained in the following provisions:

14

(i) At the time of grant of Restricted Shares to an Eligible Director, either (A) a stock certificate evidencing the shares of Common Stock granted will be registered in the Eligible Director’s name to be held by the Company for his or her account or (B) an appropriate entry evidencing the Eligible Director’s ownership of the shares of Common Stock granted will be made in the stock ownership records or other books and records maintained by or on behalf of the Company. The Eligible Director will have the entire beneficial ownership interest in, and all rights and privileges of a stockholder as to, such Restricted Shares, including the right to vote such Restricted Shares and, unless the Board will determine otherwise, the right to receive dividends thereon, subject to the following: (1) subject to Section 12(d)(iii), the Eligible Director will not be entitled to delivery of any stock certificate evidencing such Restricted Shares until the expiration of the restriction period described in Section 12(d)(ii); (2) none of the Restricted Shares may be sold, transferred, assigned, pledged, or otherwise encumbered or disposed of during the restriction period; and (3) all of the Restricted Shares will be forfeited and all rights of the Eligible Director to the Restricted Shares will terminate without further obligation on the part of the Company unless the Eligible Director remains as a member of the Board for the entire restriction period, except as provided by Section 12(d)(iii). Any shares of Common Stock or other securities or property received as a result of a transaction described in Section 14 will be subject to the same restrictions as such Restricted Shares.

(ii) Each grant of Restricted Shares under Section 12(a) or 12(b)(i) will become nonforfeitable and the restrictions described in Section 12(d)(i) will expire as to 1/3rd of the total number of shares subject thereto on each of the first three anniversaries of the date of grant of Restricted Shares; provided, in each case, that the Eligible Director who received the Restricted Shares has remained a member of the Board through each such anniversary date. Each grant of Restricted Shares under Section 12(b)(iii) will become nonforfeitable and the restrictions described in Section 12(d)(i) will expire as to the total number of shares subject thereto on the first anniversary of the date of grant of Restricted Shares; provided, in each case, that the Eligible Director who received the Restricted Shares has remained a member of the Board through such anniversary date.

(iii) Except as provided in an Evidence of Award, upon an Eligible Director’s ceasing to be a member of the Board prior to the end of a restriction period for any reason, the Eligible Director will immediately forfeit all Restricted Shares then subject to the restrictions of Section 12(d)(i), unless the Board, in its discretion, allows the Eligible Director to retain any or all of the Restricted Shares then subject to such restrictions, in which case the restriction period applicable to the retained shares will immediately expire and all restrictions applicable to the retained shares will immediately lapse.

15

(iv) At the end of the restriction period, or at such earlier time as provided for in Section 12(d)(iii) or as the Board, in its sole discretion, may otherwise determine, all restrictions applicable to the Restricted Shares will lapse and, if the Restricted Shares are evidenced by a stock certificate, a stock certificate evidencing a number of shares of Common Stock equal to the number of Restricted Shares, free of all restrictions, will be delivered to the Eligible Director.

(e) Each grant of Stock Options to an Eligible Director may utilize any or all of the authorizations, and will be subject to all the requirements, contained in the following provisions:

(i) Each grant will specify the Option Price, which will equal 100% of the Market Value per Share on the Date of Grant.

(ii) Each Stock Option will be exercisable only to the extent that it is vested. Each Stock Option granted under Section 12(a) or 12(b)(ii) will vest as to 1/3rd of the total number of shares of Common Stock subject thereto (rounded up to the nearest whole share) on each of the first three anniversaries of the date of grant of the Stock Option; provided, in each case, that the Eligible Director who received the Stock Option has remained a member of the Board through each such anniversary date. Except as may otherwise be provided in the agreement evidencing the Stock Option or as determined by the Board, each Stock Option granted under Section 12(b)(iii) will vest as to 1/12th of the total number of shares of Common Stock subject thereto (rounded up to the nearest whole share) on the last day of the first full calendar month following the date of grant of the Stock Option, as to 1/12th of the total number of shares subject thereto (rounded up to the nearest whole share) on the last day of each of the 10 succeeding calendar months, and as to the balance of the shares of Common Stock subject thereto on the last day of the calendar month preceding the one-year anniversary of the date of grant of the Stock Option; provided, in each case, that the Eligible Director who received the Stock Option has remained a member of the Board through the respective vesting date.

(iii) No Stock Option will be exercisable more than ten years from the Date of Grant.

(iv) Each Stock Option granted to an Eligible Director will be a nonqualified stock option and will not be an “incentive stock option” within the meaning of Section 422 of the Code.

(v) Each grant will specify whether the Option Price will be payable (i) in cash or by check acceptable to the Company, (ii) by the actual or constructive transfer to the Company of shares of Common Stock owned by the Eligible Director and having an aggregate Market Value per Share at the date of exercise equal to the aggregate Option Price, (iii) by authorizing the Company to withhold a number of shares of Common Stock otherwise issuable to the Eligible Director having an aggregate Market Value per Share on the date of exercise equal to the aggregate Option Price, (iv) by a combination of such methods of

16

payment or (v) by any other method of payment approved by the Board; provided, however, that the payment methods described in clauses (ii) and (iii) will not be available at any time that the Company is prohibited from purchasing or acquiring such shares of Common Stock.

(vi) During an Eligible Director’s lifetime, the Stock Option may be exercised only by the Eligible Director. Stock Options will not be transferable, except for exercise by the Eligible Director’s legal representatives or heirs; provided, however, that an Eligible Director may, with prior approval from the Board (or its designee), transfer an exercisable Stock Option to (A) a member or members of the Eligible Director’s immediate family, (B) a trust, the beneficiaries of which consist exclusively of members of the Eligible Director’s immediate family, (C) a partnership, the partners of which consist exclusively of members of the Eligible Director’s immediate family, or (D) any similar entity created for the exclusive benefit of members of the Eligible Director’s immediate family; provided that no such transfer may be made in connection with a divorce or marital dissolution proceeding. The Board or its designee must approve the form of any transfer of a Stock Option to or for the benefit of any immediate family member or members before such transfer will be recognized as valid hereunder. For purposes of the preceding sentence, any remote, contingent interest of persons other than a member of the Eligible Director’s immediate family will be disregarded. For purposes of this Section 12(e)(vi), immediate family means an Eligible Director’s spouse, children and grandchildren, including step and adopted children and grandchildren, but shall not include a former spouse.

(vii) Upon an Eligible Director’s ceasing to be a member of the Board for any reason other than death, each Stock Option of such Eligible Director will be exercisable only as to those shares of Common Stock which were then subject to the exercise of such Stock Option. The Stock Option will expire: (A) unless exercised, five years after the Eligible Director’s retirement from the Board if the Eligible Director retires at or after age 55 with at least five years of service on the Board; (B) unless exercised, five years after the date the Eligible Director’s service on the Board is terminated due to the Eligible Director’s total and permanent disability; (C) upon the Eligible Director’s service on the Board being terminated for cause pursuant to Section 141(k) of the Delaware General Corporation Law (or any successor provision); or (D) unless exercised, three months after the date of such termination. In no event, however, will any Stock Option be exercisable pursuant to this Section 12(e)(vii) after the tenth anniversary of the Date of Grant or after any earlier termination in accordance with the terms of the agreement evidencing the Stock Option.

(viii) Upon the death of an Eligible Director during his or her term of service on the Board, a Stock Option will be exercisable only as to those shares of Common Stock which were subject to the exercise of the Stock Option at the time of his or her death. The Stock Option will expire, unless exercised by the Eligible Director’s legal representatives or heirs, five years after the date of death. In no event, however, will any Stock Option be exercisable pursuant to this Section 12(e)(viii) after the tenth anniversary of the Date of Grant or after any earlier termination in accordance with the terms of the agreement evidencing the Stock Option.

17

(ix) Except as otherwise determined by the Board, the vesting schedule applicable to a Stock Option requires continued service through each applicable vesting date as a condition to the vesting of the applicable installment of the Stock Option. Service for only a portion of a vesting period, even if substantial, will not entitle the Eligible Director to any proportionate vesting or avoid or mitigate a termination of rights and benefits upon or following a termination of service as a Board member as provided in Section 12(e)(vii) or 12(e)(viii).

13. Transferability. Except as provided in Section 12(e)(vi) or as otherwise authorized by the Committee, no Award may be sold, pledged, assigned or transferred in any manner other than by will or the laws of descent and distribution; provided, however, that a Participant who is an officer of the Company may, with the prior approval of the Committee, transfer a Stock Option that is not intended to be an “incentive stock option” (within the meaning of Section 422 of the Code) to family members of the Participant, including to trusts in which family members of the Participant own more than 50% of the beneficial interests, to foundations in which family members of the Participant or the Participant controls the management of assets and to other entities in which more than 50% of the voting interests are owned by family members of the Participant or the Participant; provided further that no such transfer may be made in connection with a divorce or marital dissolution proceeding. For purposes of this Section 13, family member shall not include a former spouse. Except as otherwise authorized by the Committee, no Stock Option or Appreciation Right granted to a Participant will be exercisable during the Participant’s lifetime by any person other than the Participant or the Participant’s guardian or legal representative or any permitted transferee.

14. Adjustments.

(a) The Committee will make or provide for such adjustments in (i) the maximum number of shares of Common Stock specified in Sections 4 and 5, (ii) the number of shares of Common Stock covered by outstanding Stock Options, Appreciation Rights, Performance Shares and Restricted Stock Units granted under the Plan, (iii) the Option Price or Grant Price applicable to any Stock Options and Appreciation Rights, and (iv) the kind of shares covered by any such Awards (including shares of another issuer), as is equitably required to prevent dilution or enlargement of the rights of Participants that otherwise would result from (x) any stock dividend, stock split, combination or exchange of shares, recapitalization or other change in the capital structure of the Company, or (y) any merger, consolidation, separation, spin-off, split-off, spin-out, split-up, reorganization, partial or complete liquidation or other distribution of assets, issuance of rights or warrants to purchase securities, or (z) any other corporate transaction or event having an effect similar to any of the foregoing. In the event of any such transaction or event, the Committee, in its discretion, may provide in substitution for any or all outstanding Awards such alternative consideration as it, in good faith, may determine to be equitable in the circumstances and may require in connection with such substitution the surrender of all Awards so replaced.

18

(b) The Committee may accelerate the payment of, or vesting with respect to, any Award under the Plan upon the occurrence of a transaction or event described in this Section 14; provided, however, that in the case of any Award that constitutes a deferral of compensation within the meaning of Section 409A of the Code, the Committee will not accelerate the payment of the Award unless it determines in good faith that such transaction or event satisfies the requirements of a change in control event under guidance issued by the Secretary of the Treasury under Section 409A of the Code.

15. Fractional Shares. Neither the Company nor any Subsidiary will be required to deliver any fractional share of Common Stock pursuant to the Plan. The Committee may provide for the elimination of fractions or for the settlement of fractions in cash.

16. Withholding Taxes. To the extent that the Company or a Subsidiary is required to withhold federal, state, local or foreign taxes in connection with any payment made or benefit realized by a Participant or other person under the Plan, and the amounts available to the Company or the Subsidiary for such withholding are insufficient, it will be a condition to the receipt of such payment or the realization of such benefit that the Participant or such other person make arrangements satisfactory to the Company for payment of the balance of such taxes required to be withheld. If a Participant’s Award is to be paid in the form of shares of Common Stock and the Participant fails to make arrangements for the payment of tax, the Company or the Subsidiary may withhold shares of Common Stock having a value equal to the amount required to be withheld. In addition, if permitted by the Committee, the Participant or such other person may elect to have any withholding obligation of the Company or the Subsidiary satisfied with shares of Common Stock that would otherwise be transferred to the Participant or such other person in payment of the Participant’s Award. However, without the consent of the Committee, shares of Common Stock will not be withheld in excess of the minimum number of shares required to satisfy the withholding obligation of the Company or the Subsidiary.

17. Administration of the Plan.

(a) Unless the administration of the Plan has been expressly assumed by the Board pursuant to a resolution of the Board, the Plan will be administered by the Committee, which at all times will consist of three or more Directors appointed by the Board, all of whom are intended (i) to meet all applicable independence requirements of the New York Stock Exchange or the principal national securities exchange or principal market on or in which the Common Stock is traded and (ii) to qualify as “non-employee directors” as defined in Rule 16b-3 and as “outside directors” as defined in regulations adopted under Section 162(m) of the Code, as such terms may be amended from time to time; provided, however, that the failure of a member of the Committee to so qualify will not invalidate any Award granted under the Plan. Notwithstanding the foregoing, the provisions of Section 12 will be administered by the Board. A majority of the Committee will constitute a quorum, and the action of the members of the Committee present at any meeting at which a quorum is present, or acts unanimously approved in writing, will be the acts of the Committee.

19

(b) The Committee has the full authority and discretion to administer the Plan and to take any action that is necessary or advisable in connection with the administration of the Plan, including without limitation the authority and discretion to interpret and construe any provision of the Plan or of any agreement, notification or document evidencing an Award. The interpretation and construction by the Committee of any such provision and any determination by the Committee pursuant to any provision of the Plan or of any such agreement, notification or document will be final and conclusive. No member of the Committee will be liable for any such action or determination made in good faith.

(c) To the extent permitted by applicable law, the Committee may delegate its authority under the Plan to a subcommittee of the Committee, to one or more committees of the Board or to one or more executive officers of the Company; provided, however, that no delegation may be made of authority to take an action which is required by Rule 16b-3 to be taken by “non-employee directors” in order that the Plan and transactions thereunder meet the requirements of such Rule.

(d) It is the Company’s intention that any Award granted under the Plan that constitutes a deferral of compensation within the meaning of Section 409A of the Code and the guidance issued by the Secretary of the Treasury under Section 409A satisfy the requirements of Section 409A. In granting such an Award, the Committee will use its best efforts to exercise its authority under the Plan with respect to the terms of such Award in a manner that the Committee determines in good faith will cause the Award to comply with Section 409A and thereby avoid the imposition of penalty taxes and interest upon the Participant receiving the Award. Notwithstanding any provision of the Plan or an Evidence of Award to the contrary, (i) if the Company makes a good faith determination that a payment of an Award (A) constitutes a deferral of compensation for purposes of Section 409A of the Code, (B) is made to a Participant by reason of his or her “separation from service” (within the meaning of Section 409A of the Code) and (C) at the time such payment would otherwise be made the Participant is a “specified employee” (within the meaning of Section 409A of the Code), the payment will be delayed until the first day of the seventh month following the date of such separation from service, and (ii) if a Change in Control would be the date of payment of an Award that is determined to constitute a deferral of compensation, but the Change in Control does not constitute a change in the ownership or effective control of the Company, or in the ownership of a substantial portion of the assets of the Company (within the meaning of Section 409A of the Code), then the date of payment will be determined without regard to the occurrence of the Change in Control.

(e) With respect to the administration of the provisions of Section 12 or if the administration of the Plan is assumed by the Board pursuant to Section 17(a), the Board will have the same authority, power, duties, responsibilities and discretion given to the Committee under the terms of the Plan.

18. Amendments and Other Matters.

(a) The Plan may be amended from time to time by the Board or, with respect to those provisions of the Plan other than Section 12, the Committee; provided, however, that the Plan may not be amended without further approval by the stockholders of the Company if such amendment would result in the Plan no longer satisfying any applicable requirements of the New York Stock Exchange (or the principal national securities exchange on which the Common Stock is traded), Rule 16b-3 or Section 162(m) of the Code.

20

(b) Neither the Committee nor the Board will authorize the amendment of any outstanding Stock Option to reduce the Option Price without the further approval of the stockholders of the Company. Furthermore, no Stock Option will be cancelled and replaced with Stock Options having a lower Option Price without further approval of the stockholders of the Company. The provisions of this Section 18(b) are intended to prohibit the repricing of “underwater” Stock Options and will not be construed to prohibit the adjustments provided for in Section 14.

(c) The Plan may be terminated at any time by action of the Board. The termination of the Plan will not adversely affect the terms of any outstanding Award.

(d) The Company will not be required to issue, and neither the Company nor a Subsidiary will be required to transfer, shares of Common Stock under the Plan prior to (i) the obtaining of any approval from any governmental agency which the Company, in its sole discretion, determines to be necessary or advisable, (ii) the admission of such shares to listing on any stock exchange on which the Common Stock may then be listed, and (iii) the completion of any registration or other qualification of such shares under any state or Federal law or rulings or regulations of any governmental body which the Company, in its sole discretion, determines to be necessary or advisable.

(e) The Plan does not confer upon any Participant any right with respect to continuance of employment or other service with the Company or any Subsidiary, nor will it interfere in any way with any right the Company or any Subsidiary would otherwise have to terminate such Participant’s employment or other service at any time.

(f) If the Committee determines, with the advice of legal counsel, that any provision of the Plan would prevent the payment of any Award intended to qualify as performance-based compensation within the meaning of Section 162(m) of the Code from so qualifying, such Plan provision will be invalid and cease to have any effect without affecting the validity or effectiveness of any other provision of the Plan.

(g) No Participant will have any of the rights of a stockholder with respect to shares of Common Stock subject to an Award prior to the date as of which he or she is actually recorded as the holder of such shares upon the stock records of the Company.

19. Governing Law. The Plan, all Awards and all actions taken under the Plan and the Awards will be governed in all respects in accordance with the laws of the State of Delaware, including without limitation, the Delaware statute of limitations, but without giving effect to the principles of conflicts of laws of such State.

21

EX-10.9

Exhibit 10.9

QUICKSILVER RESOURCES INC.

INCENTIVE STOCK OPTION AGREEMENT

Participant:
Number of Shares:
Date of Grant:
Exercise Price:
Expiration Date:
Type of Option:	Incentive stock option

1. Under the terms and conditions of the Quicksilver Resources Inc. Fourth Amended and Restated 2006 Equity Plan (the “Plan”), a copy of which is attached hereto and incorporated herein by reference, Quicksilver Resources Inc., a Delaware corporation (the “Company”), grants to the individual whose name is set forth above (the “Participant”) an option to purchase the number of shares of the Company’s Common Stock, par value $0.01 per share (“Common Stock”), set forth above at the price per share set forth above (the “Option”). Terms not defined in this Agreement have the meanings set forth in the Plan.

2. The Option will be for a term commencing on the Date of Grant set forth above and ending at 5:00 p.m. Central Time on the Expiration Date set forth above. During the term hereof, the Option will become vested and exercisable in accordance with the schedule set forth below (provided that in no event will the Participant be entitled to acquire a fraction of a share of Common Stock pursuant to the Option):

Portion of Option Exercisable	On and After
[1/3	First Anniversary of Date of Grant]
[1/3	Second Anniversary of Date of Grant]
[1/3	Third Anniversary of Date of Grant]

In the event of a Change in Control while the Participant is employed by the Company or a Subsidiary or in the event that the Participant terminates employment with the Company and its Subsidiaries by reason of retirement at or after the age of 62 and completion of five years of service, disability (as determined by the Committee in good faith) or death, any nonvested portion of the Option will become 100% vested and exercisable and the Option will expire one day prior to the fifth anniversary of such retirement, disability or death.

If the Participant terminates employment with the Company and its Subsidiaries for any reason other than such retirement, disability or death, any nonvested portion of the Option will be forfeited immediately and the Option will expire on the date that is three months after the Participant’s date of termination of employment; provided, however, that if the Participant dies within three months after the date on which he or she terminates employment (other than due to discharge for “cause”), the Option will expire one day prior to the fifth anniversary of such death.

Notwithstanding the foregoing, if the Participant is discharged by the Company or a Subsidiary for “cause” (as defined below), the right to exercise the Option will terminate immediately upon such discharge. “Cause” means willful or gross misconduct or willful failure by the Participant to perform his or her employment responsibilities in the best interests of the Company and its Subsidiaries (including, without limitation, breach by the Participant of any provision of any employment, nondisclosure, non-competition or other similar agreement between the Participant and the Company or a Subsidiary), as determined by the Company, which determination will be conclusive. The Participant will be considered to have been discharged “for cause” if the Company determines, within 30 days after the Participant’s resignation, that discharge for cause was warranted.

Notwithstanding any other provision of the Plan or this Agreement to the contrary, the Option will expire and may not be exercised after the Expiration Date set forth above.

3. The exercise price for shares purchased by the Participant may be paid (i) in cash or personal check acceptable to the Company, (ii) by the transfer to the Company of shares of Common Stock having a value on the date of exercise equal to the aggregate exercise price, (iii) with the consent of the Committee, by authorizing the Company to withhold a number of shares having a value on the date of exercise equal to the aggregate exercise price or (iv) by a combination of the foregoing methods.

4. The Participant will have none of the rights of a stockholder of the Company with respect to any shares of Common Stock underlying the Option until such time that the Participant has been determined to be a stockholder of record by the Company’s transfer agent or one or more certificates of shares of Common Stock are delivered to the Participant upon due exercise of the option. Further, nothing herein will confer upon Participant any right to remain in the employ of the Company or a Subsidiary.

5. The Participant hereby accepts and agrees to be bound by all the terms and conditions of the Plan and this Agreement. Any amendment to the Plan will be deemed to be an amendment to this Agreement to the extent that the Plan amendment is applicable hereto; provided, however, that no amendment will adversely affect the rights of the Participant under this Agreement without the Participant’s consent.

ACCEPTED:

Signature of Participant

2

EX-10.10

Exhibit 10.10

QUICKSILVER RESOURCES INC.

NONQUALIFIED STOCK OPTION AGREEMENT

Participant:
Number of Shares:
Date of Grant:
Exercise Price:
Expiration Date:
Type of Option:	Nonqualified stock option

1. Under the terms and conditions of the Quicksilver Resources Inc. Fourth Amended and Restated 2006 Equity Plan (the “Plan”), a copy of which is attached hereto and incorporated herein by reference, Quicksilver Resources Inc., a Delaware corporation (the “Company”), grants to the individual whose name is set forth above (the “Participant”) an option to purchase the number of shares of the Company’s Common Stock, par value $0.01 per share (“Common Stock”), set forth above at the price per share set forth above (the “Option”). Terms not defined in this Agreement have the meanings set forth in the Plan.

2. The Option will be for a term commencing on the Date of Grant set forth above and ending at 5:00 p.m. Central Time on the Expiration Date set forth above. During the term hereof, the Option will become vested and exercisable in accordance with the schedule set forth below (provided that in no event will the Participant be entitled to acquire a fraction of a share of Common Stock pursuant to the Option):

Portion of Option Exercisable	On and After
[1/3	First Anniversary of Date of Grant]
[1/3	Second Anniversary of Date of Grant]
[1/3	Third Anniversary of Date of Grant]

In the event of a Change in Control while the Participant is employed by the Company or a Subsidiary or in the event that the Participant terminates employment with the Company and its Subsidiaries by reason of retirement at or after the age of 62 and completion of five years of service, disability (as determined by the Committee in good faith) or death, any nonvested portion of the Option will become 100% vested and exercisable and the Option will expire one day prior to the fifth anniversary of such retirement, disability or death.

If the Participant terminates employment with the Company and its Subsidiaries for any reason other than such retirement, disability or death, any nonvested portion of the Option will be forfeited immediately and the Option will expire on the date that is three months after the Participant’s date of termination of employment; provided, however, that if the Participant dies within three months after the date on which he or she terminates employment (other than due to discharge for “cause”), the Option will expire one day prior to the fifth anniversary of such death.

Notwithstanding the foregoing, if the Participant is discharged by the Company or a Subsidiary for “cause” (as defined below), the right to exercise the Option will terminate immediately upon such discharge. “Cause” means willful or gross misconduct or willful failure by the Participant to perform his or her employment responsibilities in the best interests of the Company and its Subsidiaries (including, without limitation, breach by the Participant of any provision of any employment, nondisclosure, non-competition or other similar agreement between the Participant and the Company or a Subsidiary), as determined by the Company, which determination will be conclusive. The Participant will be considered to have been discharged “for cause” if the Company determines, within 30 days after the Participant’s resignation, that discharge for cause was warranted.

Notwithstanding any other provision of the Plan or this Agreement to the contrary, the Option will expire and may not be exercised after the Expiration Date set forth above.

3. The exercise price for shares purchased by the Participant may be paid (i) in cash or personal check acceptable to the Company, (ii) by the transfer to the Company of shares of Common Stock having a value on the date of exercise equal to the aggregate exercise price, (iii) with the consent of the Committee, by authorizing the Company to withhold a number of shares having a value on the date of exercise equal to the aggregate exercise price or (iv) by a combination of the foregoing methods.

4. The Participant will have none of the rights of a stockholder of the Company with respect to any shares of Common Stock underlying the Option until such time that the Participant has been determined to be a stockholder of record by the Company’s transfer agent or one or more certificates of shares of Common Stock are delivered to the Participant upon due exercise of the option. Further, nothing herein will confer upon Participant any right to remain in the employ of the Company or a Subsidiary.

5. The Participant hereby accepts and agrees to be bound by all the terms and conditions of the Plan and this Agreement. Any amendment to the Plan will be deemed to be an amendment to this Agreement to the extent that the Plan amendment is applicable hereto; provided, however, that no amendment will adversely affect the rights of the Participant under this Agreement without the Participant’s consent.

ACCEPTED:

Signature of Participant

2

EX-10.17

Exhibit 10.17

QUICKSILVER RESOURCES INC.

Description of 2011 Cash Bonuses

After considering the contributions made to multiple projects by Mr. Philip W. Cook and Mr. John C. Cirone during 2011, the Compensation Committee of the Board of Directors of Quicksilver Resources Inc. approved payment of a one-time cash bonus payable on December 30, 2011 to the following executive officers:

Name	Amount
Philip W. Cook	$	75,000
John C. Cirone	$	60,000

EX-10.54

Exhibit 10.54

AMENDED AND RESTATED

GAS GATHERING AGREEMENT

BETWEEN

COWTOWN PIPELINE L.P. (“GATHERER”)

AND

QUICKSILVER RESOURCES INC. (“PRODUCER”)

Lake Arlington Gathering System, Tarrant County, Texas

Effective Date September 1, 2008

TABLE OF CONTENTS

1. Definitions	3
2. Dedication of Contract Area	6
3. Reservations of Parties	7
4. Receipt Point(s) and Delivery Point(s)	7
5. System Operations; Imbalances	8
6. Quantity; Nominations and Dispatching	9
7. Quality	10
8. Tests	12
9. Measurement and Meter Testing	12
10. Allocation of Gains, Fuel and Loss	15
11. Fees	16
12. Accounting, Payments and Credit Assurances	16
13. Warranty	18
14. Taxes	18
15. Indemnity	19
16. Force Majeure	20
17. Unprofitable Operations and Rights of Termination	21
18. Term	22
19. Regulatory Bodies	22
20. Disputes	22
21. Notices and Payments	23
22. Right to Process the Gas	23
23. Assignment	24
24. Miscellaneous	24

EXHIBIT A: CONTRACT AREA

EXHIBIT B: RECEIPT POINTS AND DELIVERY POINTS

AMENDED AND RESTATED GAS GATHERING AGREEMENT

THIS AMENDED AND RESTATED GAS GATHERING AGREEMENT (the “Agreement”) is made and entered into as of the 18th day of August, 2008, effective as to Gas received commencing September 1, 2008 (the “Effective Date”), by and among COWTOWN PIPELINE L.P., a Texas limited partnership (“Gatherer”), and QUICKSILVER RESOURCES INC. (“Producer”), a Delaware corporation. Gatherer and Producer are sometimes individually referred to herein as a “Party” and collectively as the “Parties.”

WITNESSETH, THAT:

WHEREAS, Producer is in the business of producing gas and owns or controls Gas production from one or more wells on the lands within the Contract Area and desires for Gatherer to gather such Gas for redelivery to Producer or Producer’s Transporter;

WHEREAS, Gatherer is in the business of providing natural gas gathering services along its Gathering System and desires to receive, gather and deliver such Gas to Producer or Producer’s Transporter, subject to the terms and conditions herein; and

WHEREAS, the Parties entered into that certain Gas Gathering Agreement dated effective October 1, 2007 (the “Prior Gathering Agreement”) and now desire to amend and restate the terms as evidenced by this Agreement;

NOW, THEREFORE, for good and valuable consideration the adequacy, receipt and sufficiency of which are hereby set forth and acknowledged, and for all of the representations, warranties and mutual covenants set forth herein, Gatherer and Producer agree to amend and restate the Prior Gathering Agreement as follows:

1. Definitions

1.1. For the purpose of this Agreement, the following terms and expressions used herein are defined as follows:

a. “Btu” shall mean one British thermal unit, which is the quantity of heat required to raise one pound avoirdupois of pure water from 58.5 degrees Fahrenheit to 59.5 degrees Fahrenheit at a constant pressure of 14.73 pounds per square inch absolute.

Gathering Agreement 3

b. “Component” shall mean those hydrocarbon and non-hydrocarbon molecular constituents which are definable by industry standards and procedures. Such Components as used in this Agreement shall be:

N2 - Nitrogen

CO₂ - Carbon Dioxide

H2S - Hydrogen Sulfide

C1 - Methane

C2 - Ethane

C3 - Propane

iC4 - Iso-butane

nC4 - Normal Butane

iC5 - Iso-pentane

nC5 - Normal Pentane

C6+ - Hexanes and Heavier Compounds

c. “Contract Area” shall mean that area as outlined on Exhibit A which is attached hereto and made a part hereof for all purposes and which may be amended from time to time.

d. “CPI Adjustment” shall mean that percentage equal to the percentage increase between:

(i) the seasonally unadjusted consumer Price Index for All Urban Consumers (all items), U.S. city Average (1982-84 =100), as published by the U.S. Department of Labor, Bureau of Labor Statistics (“CPI-U”) for the month of December of the second year prior to the Escalation Date; and

(ii) the seasonally unadjusted CPI-U for the month of December immediately preceding the Escalation Date.

e. “Day” shall mean a period of twenty-four (24) consecutive hours beginning and ending at seven o’clock a.m. Central Standard Time.

f. “Delivery Points” shall mean the point(s) of interconnect between the Gathering System and the Transporter receiving Producer’s Gas, which point(s) are shown on Exhibit B which is attached hereto and made a part hereof for all purposes.

g. “Effective Date” has the meaning set forth in the opening paragraph of this Agreement.

h. “Electrical Power” shall mean the electricity consumed in the operation of, and purchased from a utility or like entity which serves, the Gathering System and any of the related field facilities.

i. “Escalation Date” shall mean the January 1^st following the Effective Date and each January 1^st thereafter during the Term.

j. “Fuel and Loss” shall mean the gas volumes and/or Electrical Power used or consumed in the operation of the Gathering

Gathering Agreement 4

System, which shall include, but shall in no way be limited to, (i) fuel or Electrical Power used for dehydration, compression, conditioning, blending, treating, or recompression, (ii) gas needed for line pack, (iii) gas vented during operations, (iv) lost and unaccounted for gas, and (v) any Liquefiable Hydrocarbons that become separated from the gas while the gas is in the Gathering System.

k. “Gas” shall mean natural gas which is owned or controlled by Producer and produced from wells drilled on lands within the Contract Area, including casinghead gas produced with crude oil, gas from gas wells produced in association with crude oil (associated gas), and gas from condensate wells (non-associated gas), and shall include any inerts or impurities contained therein.

l. “Gathering System” shall mean, but shall in no way be limited to, the gas gathering pipelines, fuel gas pipelines, dehydration facilities, compression facilities, junctions, heaters, meters, separators, electric power lines, communications cables, roads, and other related facilities and equipment, including the rights to the lands located thereon, necessary to gather and transport gas from the Gathering System’s Receipt Point(s) to the Delivery Point(s), from the inlet flange of the pipeline metering facility installed at the Receipt Point(s) up to the upstream flange of the metering facility at the Delivery Point(s), and shall include any expansion of the Gathering System as provided in Paragraph 4.4.

m. “Liquefiable Hydrocarbons” shall mean ethane, propane, iso-butanes, normal butanes, iso-pentanes, normal pentanes, hexanes and heavier hydrocarbons, and incidental methane, or any mixtures thereof, which may be recovered or extracted in the Gathering System.

n. “MCF” shall mean 1,000 standard cubic feet of gas.

o. “MMBtu” shall mean 1,000,000 Btu’s.

p. “MMCF” shall mean 1,000,000 standard cubic feet of gas.

q. “MMCFD” shall mean 1,000,000 standard cubic feet of gas per day.

r. “Month,” “billing month,” “period,” and “accounting period” shall mean the period beginning at seven o’clock a.m. on the first day of a calendar month and ending at seven o’clock a.m. on the first day of the next succeeding calendar month.

s. “Person” means any natural person, corporation, limited liability company, partnership, joint venture, association, cooperative, or other entity.

Gathering Agreement 5

t. “psia” shall mean pounds per square inch absolute.

u. “psig” shall mean pounds per square inch gauge.

v. “Receipt Points” shall mean the inlet flange of Gatherer’s metering facilities located at or near each of Producer’s wells located within the Contract Area or such other point as may be mutually agreed upon by the Parties. The Gathering System’s Receipt Point(s) are listed on Exhibit B to this Agreement which is attached hereto and made a part hereof for all purposes and which may be amended from time to time to reflect the addition or deletion of a Receipt Point.

w. “SCF” or “standard cubic foot of gas” shall mean the amount of Gas necessary to fill a cubic foot of space when the Gas is at a pressure of 14.65 pounds per square inch absolute and a temperature of 60 degrees Fahrenheit.

x. “Term” shall have the meaning set forth in Section 18.

y. “Total Delivered Quantities” shall have the meaning set forth in Section 10.1.

z. “Transporter” shall mean the receiving pipeline(s) downstream of the Gathering System into which the Gas gathered hereunder is to be delivered at the Delivery Point(s).

2. Dedication of Contract Area

2.1. Subject to the terms and provisions hereof, Producer dedicates and agrees to deliver or cause to be delivered to Gatherer at Gatherer’s Receipt Point(s) the total volume of Gas owned or controlled by Producer lawfully produced from wells now or hereafter drilled on the lands within the Contract Area or lands pooled therewith excluding Gas reserved or utilized by Producer in accordance with the terms of Section 3. Any transfer by Producer of its right, title, or interest in the Gas to a third party, whether by farmout, contract, or otherwise, shall be made specifically subject to this Agreement. Producer will notify any person to whom Producer transfers all or a portion of its right, title, or interest in the Gas that such Gas is dedicated pursuant to the terms of this Agreement to be gathered by Gatherer, and Producer shall obtain such third party’s agreement to continue delivering such Gas to Gatherer during the term of and in accordance with this Agreement. Producer will notify Gatherer of any such transfer within 10 days of the effective date. Failure of Producer to so notify Gatherer will not impair Gatherer’s rights under this Agreement.

2.2. Gas shall be delivered to the Receipt Point(s) after standard mechanical separation by Producer for the removal of free water and free liquid hydrocarbons, but shall not otherwise be processed by Producer for the removal of Liquefiable Hydrocarbons.

Gathering Agreement 6

2.3. Gatherer agrees that subject to the provisions hereof, it will receive Gas from the Receipt Point(s) and will cause the redelivery of such Gas to Producer or Producer’s Transporter at the Delivery Point(s).

3. Reservations of Parties

3.1. Producer reserves all liquid hydrocarbons, oil, or condensate removed by Producer by means of mechanical gas-liquid separators (including heater-treaters), drips, and/or lines from the Gas prior to delivery to Gatherer. If mechanical cooling is performed by Producer to meet the temperature specifications of this Agreement, Producer shall not reduce the temperature of the Gas below 120 degrees Fahrenheit.

3.2. Producer reserves all Gas that may be required for cycling, repressuring, pressure maintenance, and gas lift operations with respect to gas reservoirs on the premises committed hereunder; provided, however, that the Gas used in such operations shall be subject to the terms of this Agreement (to the extent that such Gas can be economically saved) and delivered Gatherer following the cessation of such operations.

3.3. Producer reserves that amount of Gas which is required for above ground development and operation within the Contract Area.

3.4. Producer expressly reserves the right to deliver or furnish to Producer’s lessor such Gas as required to satisfy the terms of Producer’s oil and gas leases.

4. Receipt Point(s) and Delivery Point(s)

4.1. Producer shall be responsible for all arrangements and, at its own expense, shall construct, equip, maintain, and operate all facilities (including, but not limited to, all necessary separation, dehydration, and/or compression equipment), necessary to deliver the Gas to Gatherer at the Receipt Point(s) at such pressure as is required and sufficient to enter the Gathering System, but not to exceed 1,200 psig.

4.2. After the Effective Date, Gatherer may, but shall have no obligation to, provide additional compression which was not taken into consideration in the determination of the Gathering Fee provided in this Agreement. In such event, the fee for such additional compression shall be agreed upon by the Parties but Producer agrees that the compression fee payable by Producer shall never be less than Gatherer’s actual cost to perform such compression service. In addition, Producer will provide its pro rata share of Fuel, as more particularly described below in Section 10, as well as the cost, if any, for any Electrical Power, required for operating such compression equipment and any related facilities.

Gathering Agreement 7

4.3. Gatherer, at Producer’s expense, shall install, construct and equip all meters and facilities necessary to measure the Gas at the Receipt Point(s). Gatherer, at its own expense, shall maintain and operate such meters throughout the Term of this Agreement.

4.4. Gatherer, in its sole and absolute discretion, may decline to construct a Gathering System expansion if it determines that it would not be profitable to do so. In such event, Producer may construct a Gathering System expansion at its sole cost and expense. The Gathering System expansion must meet all of Gatherer’s specifications, and Gatherer will be responsible for the meter station and connection to the existing Gathering System. Gatherer may, at its election, but within two years (2) of the initial delivery of production from the Gathering System expansion, acquire the ownership of the Gathering System expansion installed by the Producer by reimbursing Producer for the actual cost of the Gathering System expansion with no allowance for inflation or depreciation. In such event, Producer agrees to execute all assignments or contracts deemed necessary to accomplish the transfer to Gatherer of title to the Gathering System expansion, including rights-of-way and easements. In the event neither Gatherer nor Producer elect to construct the necessary Gathering System expansion to connect additional wells to the existing Gathering System, then this Agreement shall terminate as to the Gas produced by Producer from such additional well or wells.

4.5. Gatherer hereby agrees to deliver the Gas to Producer or Producer’s nominated Transporter, less Producer’s pro rata share of Fuel and Loss, at the Delivery Point(s).

5. System Operations; Imbalances

5.1. Gatherer shall retain full operational control of the Gathering System and shall at all times be entitled to schedule deliveries and to operate its facilities in a manner consistent with safe and prudent operating practices under the conditions which may exist from time to time. Accordingly, Gatherer may interrupt the gathering of Gas as necessary to test, alter, modify, enlarge, expand, maintain or repair any facility or property comprising any part of or appurtenant to the Gathering System. It is understood and agreed by the Parties that in order for Gatherer to maintain efficiency in the Gathering System, it will be necessary to maintain a uniform rate of flow of Gas to the Gathering system from all sources during each twenty-four (24) hour period. Therefore, Producer agrees that it will cooperate with Gatherer in regulating the flow rate of the Gas and in establishing a producing schedule to deliver on a best efforts basis the Gas at a uniform and continuous flow rate. In the event that Gatherer enters into an operational balancing agreement with Producer’s Transporter or any other third party pipeline, Producer hereby agrees to be bound by the terms set forth therein.

Gathering Agreement 8

5.2. It is acknowledged that, because of dispatching and other causes, certain imbalances may occur between the MMBtu’s of Gas delivered hereunder by Gatherer to or for the account of Producer at the Delivery Point(s) and the MMBtu’s of Gas received from or on behalf of Producer at the Receipt Point(s). Such imbalances, if any, shall be eliminated as soon as practical after each such occurrence; provided, however, Gatherer shall not be required to eliminate any imbalance during any month in which the value of the Gas received or delivered, as determined by Gatherer, is not representative of the market value of natural gas when the imbalance occurred. Any imbalance remaining following the termination of this Agreement shall be eliminated during the month following the month in which termination occurs or as soon as practicable thereafter. Producer authorizes the operator of each well in the Contract Area to be its agent for the purpose of providing Gatherer with instructions to adjust allocations of Gas attributable to that well for gas balancing purposes. Producer represents that it has the right to make any such adjustments and that such adjustments are correct. Gatherer may adjust the Gas allocated to that well in accordance with these instructions but gatherer is not obligated to do so at any time. Gatherer shall notify Producer of any such allocation change implemented by Gatherer at the Producer’s operator’s instructions.

5.3. The Parties acknowledge that the Gathering System is connected to the facilities of Transporter and other pipelines and, as a result, Gatherer shall be, from time to time, subject to certain requirements imposed by those pipelines. Accordingly, Gatherer shall have the right under this Agreement to require Producer to comply with the same third party pipeline requirements with which gatherer must comply. PRODUCER AGREES TO INDEMNIFY, DEFEND, AND HOLD GATHERER HARMLESS FROM PRODUCER’S FAILURE TO COMPLY WITH TRANSPORTER’S OR SUCH OTHER THIRD PARTY PIPELINE REQUIREMENTS.

6. Quantity; Nominations and Dispatching

6.1. Subject to Gathering System capacity, Gatherer shall gather that volume of Gas legally allowed to be produced which is attributable to the interest owned or controlled by Producer in wells drilled on lands within the Contract Area or lands pooled therewith; provided, Producer or Producer’s Transporter or nominee will accept the Gas redelivered on Producer’s behalf at the Delivery Point(s). Gatherer may, from time to time, find it necessary to shut off entirely or restrict the flow of gas to the Gathering System notwithstanding anything herein to the contrary and, in such event, Gatherer shall not be liable to Producer for the resulting effect thereof. Gatherer shall provide Producer prior notice of any shut down due to routine maintenance and shall prudently work to minimize the amount of such downtime.

6.2. Producer shall make all nominations to Transporter in accordance with Transporter’s nomination procedures, and shall make any and all other arrangements necessary for transporter to receive Producer’s Gas at the

Gathering Agreement 9

Delivery Point(s). Producer shall nominate to Gatherer in writing, not less than three (3) business Days prior to the first day of each Month during the term of the Agreement, the daily quantity of Gas (expressed in MCF’s and MMBtu’s) that Producer shall deliver to Gatherer at the Receipt Point(s) for gathering during such Month and that Producer or Producer’s Transporter or nominee shall accept at the Delivery Point(s). As between Producer and Gatherer, Producer shall be solely responsible for imbalances, penalties, cash-out payments, or other consequences of any failure to submit timely and proper nominations in accordance with the requirements of the Transporter or the failure to deliver or receive quantities of Gas in accordance with said nominations.

6.3. Gatherer and Producer shall designate a dispatcher(s) who shall be continuously on call for nomination purposes, and shall notify each other in writing of such dispatcher(s) and their telephone number(s).

6.4. Producer’s dispatcher shall notify Gatherer’s dispatcher(s) in advance of any anticipated decrease in delivery rate below the daily nominated quantity. Producer’s dispatcher(s) must obtain the prior written approval from Gatherer’s dispatcher(s) for any delivery rate in excess of the daily quantity rate. Gatherer’s dispatcher(s) shall notify Producer’s dispatcher(s) of any anticipated inability to receive the Gas at a delivery rate less than (a) the daily nominated quantity rate; or (b) a previously orally authorized delivery rate in excess of the daily nominated quantity rate.

6.5. The quantity of Gas delivered by Producer at each Receipt Point hereunder during a month shall be determined in accordance with the allocation procedures set forth in Section 10 below.

7. Quality

7.1. Gatherer shall not be obligated to receive, gather, or redeliver (as the case may be) Gas delivered by or on behalf of Producer hereunder that fails to meet the quality specifications of (i) the Transporter at any of the Delivery Point(s), or (ii) the following specifications:

a. The Gas must be commercial in quality and free from any foreign materials such as dirt, dust, iron particles, crude oil, dark condensate, free water, and other impurities; and substances which may be injurious to pipelines or which may interfere with the gathering, processing, transmission, or commercial utilization of said Gas;

b. The Gas shall not contain more than seven (7) pounds of water vapor per MMCF;

c. The Gas delivered hereunder shall not exceed a temperature of one hundred forty (140) degrees Fahrenheit, nor have a hydrocarbon dewpoint below forty (40) degrees Fahrenheit, at the Receipt Point(s);

Gathering Agreement 10

d. The Gas delivered hereunder shall not contain more than:

(i) One-fourth grain of hydrogen sulfide, or five grains of total sulfur, or one grain mercaptan per one hundred (100) cubic feet;

(ii) one part per million by volume of oxygen;

(iii) that percent by volume of carbon dioxide which would result in the failure of the Residue Gas to meet the specifications of any Transporter at any of the Delivery Points, but in no event more than two percent by volume;

(iv) two percent by volume of nitrogen; or

(v) three percent by volume of a combined total of inerts, including, but not limited to, carbon dioxide and nitrogen Components.

e. No diluents such as carbon dioxide, air, or nitrogen shall be added to the Gas;

f. The Gas shall contain no carbon monoxide, halogens, or unsaturated hydrocarbons, and no more than 0.1 parts per million of hydrogen; and

g. The Gas shall have a total heating value of not less than 950 Btu’s nor more than 1050 Btu’s per cubic foot and 2 GPM ethane and heavier hydrocarbons.

In the event of any conflict as between a Transporter’s specifications and those appearing above in this Section 7.1, the more stringent or restrictive specifications shall be satisfied.

7.2. If any of the Gas delivered by Producer hereunder should fail to meet the quality specifications set forth in Section 7.1 (including those required by a Transporter), Gatherer may elect to either (i) accept and gather such Gas, (ii) accept, but treat and/or condition such Gas prior to gathering at an additional cost, or (iii) refuse to accept such Gas. The acceptance of Gas not meeting the quality specifications set forth in Section 7.1 shall not be deemed a waiver of Gatherer’s right to reject such Gas at any later time, and Gatherer shall be entitled, at any time and from time to time, to decline to accept proffered deliveries of Gas not meeting the quality specifications set forth herein.

7.3. If Gatherer elects to accept but treat and/or condition the non-conforming Gas prior to gathering, Gatherer shall advise the Producer of such election and associated fees. Producer shall then have a maximum of thirty (30) days to advise Gatherer if it will treat and/or condition such non-conforming Gas

Gathering Agreement 11

and the cost associated with such treatment. If Producer does not elect to treat and/or condition such non-conforming Gas or fails to make such election within the specified time period, then Gatherer shall have the right to (i) proceed with gathering such non-conforming Gas and Producer shall pay to Gatherer all costs associated with such actions, or (ii) reject and release such non-conforming Gas from the terms of this Agreement.

8. Tests

8.1. Producer and Gatherer do hereby agree as follows:

a. Gatherer shall procure or cause to be procured a sample of Gas at each Receipt Point and Delivery Point, respectively, and analyze the samples by chromatographic analysis to determine the Component content (mole percent), specific gravity, and the Btu content thereof.

b. Tests provided above shall be made by Gatherer using its own equipment or by an independent testing service at least once in each six month period, or more frequently in its sole discretion. All such tests shall be made in accordance with approved engineering practices. Representatives of Producer shall be entitled to witness such tests, and Producer shall give advance written notice to Gatherer in the event that it exercises such right.

8.2. Physical constants required for making calculations hereunder shall be taken from the Gas Processors Association Physical Constants Publication No. 2145-03 (as amended from time to time). Physical constants for the hexanes and heavier hydrocarbons portion of hydrocarbon mixtures shall be assumed to be the same as the physical constants for hexane. The heat content per gallon of each liquid hydrocarbon Component shall be determined by multiplying the cubic feet per gallon of such liquid hydrocarbon Component by the heat content per cubic foot thereof.

9. Measurement and Meter Testing

9.1. The unit of volume for measurement of Gas delivered hereunder shall be one thousand (1,000) cubic feet of Gas (or MCF) at a base temperature of 60 degrees Fahrenheit and at an absolute pressure of 14.65 psia and saturated with water vapor. All fundamental constants, observations, records, and procedures involved in determining the quantity of Gas delivered hereunder shall be in accordance with the standards prescribed in Report Nos. 3 and 8, of the American Gas Association, as amended or supplemented from time to time, respectively. It is agreed that for the purpose of measurement and computations hereunder, the atmospheric pressure shall be assumed to be 14.7 psia regardless of the atmospheric pressure at which the Gas is measured and that the Gas obeys the Ideal Gas Laws as to variations of volume with pressure and specific gravity, including the deviation from Boyle’s law, shall all be made by

Gathering Agreement 12

Gatherer in accordance with applicable rules, regulations, and orders. It is also agreed that the Gatherer may apply a uniform correction factor for water vapor if they deem necessary in their sole and absolute discretion.

9.2. Gatherer shall install, maintain, and operate, or cause to be maintained and operated, a measuring station located at each Receipt Point and Delivery Point. Said measuring station(s) shall be so equipped with orifice meters, recording gauges, or other types of meter or meters of standard make and design commonly acceptable in the industry, and of suitable size and design, as to accomplish the accurate measurement of Gas delivered hereunder. The changing and integration of the charts (if utilized for measurement purposes hereunder) and calibrating and adjusting of meters shall be done by Gatherer. Gatherer shall have the right to utilize electronic gas measuring equipment should it so desire.

9.3. Producer may, at its option and expense, install check meters for checking Gatherer’s metering equipment at each Receipt Point; and the same shall be so installed as not to interfere with the operation of the Gathering System.

9.4. The temperature of the Gas flowing through the meter shall be determined by the continuous use of a recording thermometer or device installed by Gatherer, so that it will properly record the temperature of the Gas flowing through the meter.

9.5. The specific gravity of the Gas flowing through the meter shall be determined by methods commonly accepted in the industry. Specific gravities so determined will be used in calculating Gas deliveries until the next specific gravity test is made.

9.6. Each Party shall have the right to be present at the time of any installation, reading, sampling, cleaning, changing, repair, inspection, testing, calibration, or adjustment done in connection with the other Party’s measuring equipment used in measuring deliveries hereunder. The records from such measuring equipment shall remain the property of their owner, but upon request, each will submit to the other its records and charts, together with calculations therefrom subject to return within thirty (30) days after receipt thereof. If meters utilizing charts are used to measure Gas hereunder, then the charts shall be kept on file for a period of two (2) years, or such longer period as may be required by law. In addition, any other measurement data shall also be kept for the same time period. Each Party, during each of the first three production months, and after that at least semi-annually, or more often if necessary, shall calibrate the meters and instruments installed by it or cause the same to be calibrated. Gatherer shall give Producer ten (10) days notice in advance of such tests so that the latter may, at its election, be present in person or by its representative to observe adjustments, if any are made.

Gathering Agreement 13

9.7. If the metering equipment is found to be inaccurate by two percent (2%) or more, registration thereof and any payment based upon such registration shall be corrected at the rate of such inaccuracy for any period of inaccuracy which is definitely known or agreed upon, or if not known or agreed upon, then for a period extending back one-half of the time elapsed since the last day of the calibration. Unless conclusively determined that Gatherer’s measurement equipment is inaccurate by two percent (2%) or more, Gatherer’s measurement shall be deemed to be correct for all purposes hereunder, and no adjustment shall be made to the previous volumes. Following any test, any metering equipment found to be inaccurate to any degree shall be adjusted immediately to measure accurately. If for any reason any meter is out of service or out of repair so that the quantity of Gas delivered through such meter cannot be ascertained or computed from the readings thereof, the quantity of Gas so delivered during such period shall be estimated and agreed upon by the Parties hereto upon the basis of the best available data using the first of the following methods which is feasible:

a. By using the registration of any check measuring equipment of Producer, if installed and registering accurately;

b. By correcting the error if the percentage of error is ascertainable by calibration, test, or mathematical calculation; or

c. By estimating the quantity of deliveries during preceding periods under similar conditions when the meter was registering accurately.

9.8. If Producer shall notify Gatherer, or if Gatherer shall notify Producer, at any time that a special test of any Receipt Point meter is desired, the Parties shall cooperate to secure an immediate verification of the accuracy of such meter and joint observation of any adjustments. All tests of Gatherer’s measuring equipment at any Receipt Point shall be made at Gatherer’s expense, except that the Producer shall bear the expense of tests made at its request if the inaccuracy found is less than two percent (2%). Expense as used in this Paragraph 9.8 shall be limited to actual costs of Gatherer as the result of testing and shall not include any costs incurred by Producer as the result of witnessing said testing.

9.9. If during any month less than 1,000 MCF of Gas is delivered to a Receipt Point, (except for reasons of Force Majeure), then Gatherer shall charge a meter fee applicable to any such Receipt Point equal to four hundred dollars ($400.00). Such fee shall be invoiced to Producer and payable thirty (30) days after receipt of such invoice.

9.10. The Parties hereto recognize and acknowledge that technological advances may occur over the term of this Agreement which may render certain measurement devices obsolete, or less accurate, or less efficient than that which

Gathering Agreement 14

may be available. In such event, Gatherer may, with Producer’s approval, substitute or utilize such available measurement equipment in lieu of any measurement equipment described above in this Section 9.

9.11. If for any reason the Gas is delivered to Gatherer at a Receipt Point with pulsations that affect the accuracy of the measurement, Producer shall be responsible for installing necessary pulsation dampeners, or other devices, to eliminate or reduce the pulsations to an acceptable level determined by Gatherer

10. Allocation of Gains, Fuel and Loss

10.1. Gatherer shall use generally industry care in transporting Producer’s Gas from the Point of Receipt to the Delivery Point(s) for Producer’s account or sale. However, the Parties understand and agree that certain volumetric gains and losses in the Gas will occur and shall be shared by and among Producer and other third parties whose gas is transported by Gatherer, in the proportion that each Person who delivers gas into the Gathering System bears to the total gas received at the respective Receipt Point. In determining the quantity of Gas delivered by Producer at each Receipt Point hereunder during a month, Gatherer shall allocate to Producer at each such Receipt Point a percentage of the total quantities (expressed in MMBtu’s) reported for such Month by the Transporter at the Delivery Point(s) (the “Total Delivered Quantities”) equal to 100% of such Total Delivered Quantities times a fraction, the numerator of which is the number of MMBtu’s of Gas delivered by Producer during such Month at said Receipt Point, and the denominator of which is the number of MMBtu’s of all gas delivered into the Gathering System from all receipt points, minus Producer’s applicable Fuel and Loss.

10.2. Producer’s pro rata share of such Fuel and Loss shall equal the product of the total Fuel and Loss utilized, consumed or incurred by the Gathering System, multiplied by a fraction, the numerator of which is Producer’s MMBtu’s of Gas metered into the Gathering System at the Receipt Point(s) and the denominator of which is the total number of MMBtu’s of gas metered into the Gathering System upstream of the Receipt Point(s).

10.3. In the event Electrical Power is utilized in the operation of the Gathering System, Producer’s pro rata share shall equal the product of the total dollar amount paid for such Electrical Power multiplied by a fraction, the numerator of which is the number of Producer’s MMBtu’s of Gas metered into the Gathering System upstream of the Receipt Point(s) and the denominator of which is the total number of MMBtu’s of gas metered into the Gathering System upstream of the Receipt Point(s), to be invoiced to Producer and paid to Gatherer in accordance with Section 12 below.

Gathering Agreement 15

11. Fees

11.1. Producer shall pay to Gatherer sixty-two cents ($0.62) per each MMBtu of its Gas metered at the Receipt Point(s) pursuant to this Agreement (the “Gathering Fee”).

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

12. Accounting, Payments and Credit Assurances

12.1. Gatherer shall furnish to Producer on or before the twenty-fifth (25^th) day of each month a report or statement disclosing information necessary to enable Producer to make reasonable and accurate statistical and accounting entries upon its books concerning all phases of this Agreement related to the preceding month, including any statement of the Gas delivered for Producer’s account to its Transporter, the total volume of Gas in MCF and in MMBtu measured at the Receipt Point(s), Producer’s pro rata share of Fuel and Loss and the cost billed to Gatherer for Electrical Power, if any, and the amounts due Gatherer for the services provided hereunder. Producer shall remit the amounts due Gatherer within thirty (30) days after the receipt of Gatherer’s statement. PRODUCER SHALL INDEMNIFY AND HOLD GATHERER HARMLESS FROM ANY AND ALL CHARGES, PENALTIES, COSTS AND EXPENSES OF WHATEVER KIND OR NATURE ARISING FROM PRODUCER’S FAILURE TO PAY SUCH PAYMENTS, INCLUDING COSTS AND EXPENSES OF ANY LITIGATION AND REASONABLE ATTORNEYS’ FEES ASSOCIATED THEREWITH. Unpaid amounts due shall accrue interest at the lesser of a rate equal to one and one half percent (1.5%) per month or the maximum rate permitted by law, until the balance is paid in full.

12.2. Each Party shall have the right during reasonable hours to examine books, records, charts, and original test data of the other Party to the extent necessary to verify the accuracy of any statement, charge, credit, computation, test, or delivery made pursuant to any provision hereof. If any such examination reveals any inaccuracy in any such statement, charge, credit, computation, test, or delivery, the necessary adjustment shall be promptly made without interest or penalty. Neither Party will have any right to recoup or recover prior overpayments or under payments that result from error that occur in spite of good faith performance if the amounts involved do not exceed fifty dollars ($50.00) per month per Receipt Point.

12.3. Producer shall be responsible for the payment of all royalties due on the Gas. Producer shall indemnify and hold Gatherer harmless from any and all claims, actions, causes of action, damages, liability, or obligations arising out of or in any way related to the payment of the lessor’s royalty or any other burden or encumbrance affecting the Gas.

Gathering Agreement 16

12.4. Notwithstanding any change in ownership of Producer’s properties, Gatherer shall never be required to make payments or to give notices required under the provisions of this agreement to more than one party, and, in the event that Producer’s properties shall ever be owned by more than one party, Gatherer may withhold (without interest) further payments and notices until all of the owners of Producer’s properties have designated one party to act for them in all respects relating to said properties and this agreement, including the rendering of bills, the submission of charts, and the receipt of payments and notices hereunder.

12.5. All accounting records and documents directly related to this Agreement prepared by any Party hereto shall be retained for a period of not less than two years following the end of the calendar year of their origination. The Parties further agree that all matters relating to the accounting hereunder for any calendar year shall be considered correct and not subject to further audit or legal challenge after two years following the end of the calendar year.

12.6. Producer must maintain such creditworthiness as Gatherer shall reasonably require. Gatherer’s creditworthiness requirements shall be substantially similar to those requirements set forth below:

a. Producer will be deemed creditworthy if (i) its long-term unsecured debt securities are rated at least BBB- by Standard & Poor’s Corporation (“S&P”) and at least Baa3 by Moody’s Investor Service (“Moody’s”) (provided, however, that if the Producer’s rating is at BBB- or Baa3 and the short-term or long-term outlook is Negative, Gatherer may require further analysis as discussed below); and (ii) the sum of all fees under the Agreement is less than 15% of Producer’s tangible net worth. The term “tangible net worth” shall mean for a corporation the sum of the capital stock, paid-in capital in excess of par or stated value, and other free and clear equity reserve accounts less goodwill, patents, unamortized loan costs or restructuring costs, and other intangible assets. Only actual tangible assets are to be included in Gatherer’s assessment of creditworthiness. In comparing the overall value of a Producer’s agreement to tangible net worth for credit evaluation purposes, Gatherer will compare the net present value of the fee obligations under this Agreement to Producer’s current tangible net worth.

b. If Producer does not meet the criteria described above, then Producer may request that Gatherer evaluate its creditworthiness based upon the level of service requested relative to the Producer’s current and future ability to meet its obligations. Further, if Producer’s creditworthiness does not meet any of the foregoing criteria Producer will be considered creditworthy if Producer maintains and delivers to Gatherer an irrevocable guaranty of payment in form acceptable to Gatherer, or an irrevocable letter of credit from a financial institution rated at least A- by S&P or at least A3 by Moody’s, in a form acceptable to Gatherer, in either

Gathering Agreement 17

case of the Guaranty or the letter of credit in an amount satisfactory to Gatherer. The obligation to maintain such credit assurance shall extend until such time as Producer is deemed creditworthy as defined herein. Producer shall provide the Guaranty or the letter of credit within twenty (2) days of written notice by Gatherer.

c. The creditworthiness requirements set forth in this Section 12.6 shall apply to any permitted assignment (in whole or in part), and to any permitted permanent release, as applicable, of this Agreement. Gatherer shall apply consistent evaluation practices to all similarly situated producers to determine Producer’s financial ability to perform the payment obligations due to Gatherer. These creditworthiness requirements shall apply to any assignment (in whole or in part) of this Agreement, or to any permanent release of this Agreement.

13. Warranty

13.1. PRODUCER warrants the title to all Gas and all components thereof which shall be delivered by Producer to Gatherer hereunder, the right to enter into this Agreement with reference to such Gas, and that such Gas is free from all liens and adverse claims; and AGREES, IF NOTIFIED THEREOF BY GATHERER, TO INDEMNIFY, DEFEND AND HOLD GATHERER HARMLESS FROM AND AGAINST ANY AND ALL SUITS, ACTIONS, LOSSES, DEBTS, ACCOUNTS, DAMAGES, COSTS AND EXPENSES ARISING FROM OR OUT OF ANY ADVERSE CLAIM AS TO PRODUCER’S TITLE, INCLUDING BUT NOT LIMITED TO , ANY ADVERSE CLAIMS BROUGHT BY OR THROUGH A MINERAL INTEREST OR ROYALTY OWNER, TO OR AGAINST THE GAS. Producer agrees to make settlement for all royalties, overriding royalty interests, and/or production payments due and payable on the Gas delivered to Gatherer hereunder, any components of the Gas extracted or saved therefrom, and the sale and disposition of the Gas to the thereof, all in accordance with the terms of the leases from which gas processed hereunder is produced, applicable instruments of title, and all amendments thereto.

13.2. If Producer’s title to the Gas is questioned, Gatherer may withhold payments of proceeds due hereunder without interest up to the amount of the claim until title is free from such questions or until Producer furnishes a bond satisfactory to Gatherer conditioned to save Gatherer harmless, or other surety satisfactory to Gatherer.

14. Taxes

14.1. Producer shall pay or cause to be paid all production, severance and ad valorem taxes, assessments, and other charges levied or assessed against the Gas gathered hereunder, and all taxes and statutory charges levied or assessed against any of Producer’s properties, facilities, or operations.

Gathering Agreement 18

Producer shall reimburse Gatherer to the extent of any severance or other such taxes paid by Gatherer on behalf of Producer.

14.2. Gatherer shall pay all taxes and statutory charges levied or assessed against the Gathering System and operations concerning such system.

15. Indemnity

15.1. As between the Parties, and as to liability, if any, accruing to either Party hereto or to any third party, Producer shall be solely liable for and in control and possession of the Gas deliverable hereunder until the Gas is delivered to Gatherer at the Receipt Point(s). Gatherer shall be solely liable for and in control and possession of the Gas deliverable hereunder until the gas is delivered to Producer or to the Transporter on Producer’s behalf at the Delivery Point(s), whereupon Producer shall again be in control and possession thereof and bear the risk of loss of the Gas delivered to Transporter.

15.2. PRODUCER SHALL BE AFFORDED ACCESS TO GATHERER’S PROPERTY AND THE FACILITIES TO THE EXTENT NECESSARY TO CARRY OUT ITS RIGHTS AND OBLIGATIONS UNDER THIS AGREEMENT, AND PRODUCER SHALL FULLY OBSERVE AND COMPLY WITH ALL OF GATHERER’S SAFETY PRACTICES AND PROCEDURES WHILE ON THE PREMISES. PRODUCER HEREBY AGREES TO INDEMNIFY, HOLD HARMLESS, PROTECT, DEFEND, AND DISCHARGE GATHERER AND ITS AFFILIATED COMPANIES, PARTNERS, SUCCESSORS, ASSIGNS, OFFICERS, DIRECTORS, SHAREHOLDERS, EMPLOYEES AND AGENTS FOR, FROM AND AGAINST ANY AND ALL JUDGMENTS, EXECUTIONS, CAUSES OF ACTION, DEMANDS, RIGHTS, SUITS, DEBTS AND SUMS OF MONEY, ACCOUNTINGS, DUES, PENALTIES, FINES, CLAIMS (INCLUDING, WITHOUT LIMITATION, CLAIMS FOR CONTRIBUTION), LIABILITIES, LOSSES, COSTS, DAMAGES AND EXPENSES (INCLUDING COURT COSTS, REASONABLE COSTS OF INVESTIGATION, DEFENSE AND ATTORNEY’S FEES) FOR THE INJURY TO OR DEATH OF ANY PERSON (INCLUDING, WITHOUT LIMITATION, EACH OF PRODUCER’S AND GATHERER’S EMPLOYEES, AGENTS AND CONTRACTORS) OR PROPERTY DAMAGE OF ANY NATURE, KIND OR DESCRIPTION OR ANY OTHER CLAIM OF ANY NATURE, KIND OR DESCRIPTION BROUGHT BY ANY PERSON OR ENTITY, WHETHER LEGAL OR EQUITABLE, WHICH ARISES OUT OF, RESULTS FROM OR IS IN ANY WAY RELATED TO (I) PRODUCER’S OWNERSHIP AND CONTROL OF THE GAS PRIOR TO THE TIME THAT THE GAS PASSES THROUGH THE GATHERING SYSTEM RECEIPT POINT(S) AND AFTER THE RESIDUE GAS PASSES THROUGH THE DELIVERY POINT(S), (II) PRODUCER’S OWNERSHIP AND OPERATION OF THE WELLS LOCATED WITHIN THE CONTRACT AREA AND ANY FACILITIES OR EQUIPMENT INSTALLED OR MAINTAINED BY PRODUCER UPSTREAM OF THE GATHERING SYSTEM RECEIPT POINT, REGARDLESS OF WHETHER SUCH WAS REQUIRED BY THE TERMS OF THIS AGREEMENT, (III) THE

Gathering Agreement 19

PERFORMANCE OF ANY OBLIGATIONS, RIGHTS OR DUTIES HEREUNDER, (IV) PRODUCER’S BREACH OF THIS AGREEMENT, OR (V) ANY VIOLATION OF THE LAW, REGARDLESS OF GATHERER’S SOLE, CONCURRENT OR COMPARATIVE NEGLIGENCE.

GATHERER HEREBY AGREES TO INDEMNIFY, HOLD HARMLESS, PROTECT, DEFEND AND DISCHARGE PRODUCER AND ITS AFFILIATED COMPANIES, PARTNERS, SUCCESSORS, ASSIGNS, OFFICERS, DIRECTORS, SHAREHOLDERS, EMPLOYEES AND AGENTS, FOR, FROM AND AGAINST ANY AND ALL JUDGMENTS, EXECUTIONS, CAUSES OF ACTION, DEMANDS, RIGHTS, SUITS, DEBTS AND SUMS OF MONEY, ACCOUNTINGS, DUES, PENALTIES, FINES, CLAIMS (INCLUDING, WITHOUT LIMITATION, CLAIMS FOR CONTRIBUTION), LIABILITIES, LOSSES, COSTS, DAMAGES AND EXPENSES (INCLUDING COURT COSTS, REASONABLE COSTS OR INVESTIGATION, DEFENSE AND ATTORNEY’S FEES) OF ANY NATURE, KIND OR DESCRIPTION BROUGHT BY ANY PERSON OR ENTITY, WHETHER LEGAL OR EQUITABLE, WHICH ARISE OUT OF, RESULT FROM OR ARE IN ANY WAY RELATED TO (I) GATHERER’S OWNERSHIP AND CONTROL OF THE GAS AFTER THE GAS PASSES THROUGH THE GATHERING SYSTEM RECEIPT POINTS TO THE TIME THAT THE GAS PASSES TO THE DELIVERY POINT(S), (II) GATHERER’S OWNERSHIP AND OPERATION OF THE GATHERING SYSTEM, (III) THE SERVICES PROVIDED BY GATHERER PURSUANT TO THIS AGREEMENT, (IV) GATHERER’S BREACH OF THIS AGREEMENT, OR (V) ANY VIOLATION OF THE LAW, REGARDLESS OF PRODUCER’S SOLE, CONCURRENT OR COMPARATIVE NEGLIGENCE.

THE INDEMNIFICATION RIGHTS HEREIN SHALL BE CUMULATIVE OF, AND IN ADDITION TO, ANY AND ALL OTHER RIGHTS, REMEDIES OR RECOURSE OF THE PARTIES AND SHALL SURVIVE ANY EXPIRATION OR TERMINATION OF THIS AGREEMENT. TO THE EXTENT AND ONLY TO THE EXTENT THE FOREGOING INDEMNIFICATION RIGHTS ARE BY LAW, EITHER INAPPLICABLE OR NOT ENFORCEABLE, PRODUCER, AND GATHERER SHALL EACH BE RESPONSIBLE FOR THE RESULTS OF ITS OWN ACTIONS AND FOR THE ACTIONS OF THOSE PERSONS AND ENTITIES OVER WHICH IT EXERCISES CONTROL.

16. Force Majeure

In the event any Party is rendered unable, either wholly or in part, by force majeure to carry out its obligations under this Agreement, other than the obligation to make payments due hereunder, it is agreed that on such Party giving notice and full particulars of such inability by telephone and in writing to the other Parties as soon as possible after the occurrence of the cause relied on, then the obligations of the Party giving such notice, so far as they are affected by such force majeure, shall be suspended during the continuance of any inability so caused, but for no longer period, and such cause shall, as far as possible, be remedied with all reasonable dispatch. The

Gathering Agreement 20

term “force majeure” as employed herein shall mean any act or event which wholly or partially prevents or delays the performance of obligations arising under this Agreement if such act or event is not reasonably within the control of and not caused by the fault or negligence of the Party claiming force majeure and which by the exercise of due diligence such Party is unable to prevent or overcome, including, without limitation, by the following enumeration: acts of God; strikes; lockouts; or other industrial disturbances; acts of the public enemy; wars; blockades; insurrections; riots; epidemics; landslides; lightning; earthquakes; fires; storms; floods; washouts; arrests and restraints of governments and people; civil disturbances; explosion, breakage, or accidents to machinery, plant facilities, or lines of pipe; the necessity for making repairs to or alterations of machinery, plant facilities, or lines of pipe; freezing of wells or lines of pipe; partial or entire failure of wells; and the inability of either Producer or Gatherer to acquire, or the delays on the part of either Producer or Gatherer in acquiring, at reasonable cost and after the exercise of reasonable diligence: (a) any servitude, rights-of-way grants, permits, or licenses; (b) any materials or supplies for the construction or maintenance of facilities; and (c) any permits or permissions from any governmental agency if such are required. It is understood and agreed that the settlement of strikes or lockouts shall be entirely within the discretion of the Party having the difficulty and that the above requirements that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes or lockouts by acceding to the demands of the opposing party when such course is inadvisable in the sole discretion of the Party having the difficulty.

17. Unprofitable Operations and Rights of Termination

17.1. If, in the sole and absolute opinion of Gatherer, (a) the gathering of Gas from any well or wells or any Receipt Point(s), or (b) the delivery of Gas to any Delivery Point(s), under this Agreement, is or becomes uneconomical due to its volume, quality, government regulations, or for any other cause, Gatherer shall not be obligated to gather or may cease gathering the Gas so long as such condition exists. Gatherer agrees that in its determination of uneconomical gathering, the same criteria shall be used for the Gas as for all other gas being gathered through the Gathering System. In the event that Gatherer refuses to gather the Gas, Producer may dispose of the Gas not gathered as it sees fit; provided that Gatherer at any time thereafter shall have the right to gather all of the Gas refused, if refused for reason or reasons resulting from an act of Producer or lack of action on the part of Producer, conditioned upon Gatherer giving Producer at least two (2) months’ notice of its election so to do.

17.2. Nothing herein shall be construed to require Producer to drill any well or to continue to operate any well which a prudent operator would not in like circumstances drill or continue to operate.

17.3. It is agreed that Gatherer shall not be obligated to expand the Gathering System in order to provide capacity hereunder.

Gathering Agreement 21

18. Term

This terms of this Agreement shall be effective from the Effective Date and, subject to the other provisions hereof, shall continue in full force and effect until August 10, 2017 (the “Primary Term”) and shall be automatically renewed for one (1) year periods thereafter unless on or before ninety (90) days prior to the expiration of the Primary Term or the expiration of a one (1) year renewal period a Party hereto provides written notice of termination (the “Term”).

19. Regulatory Bodies

This Agreement and the provisions hereof shall be subject to all valid applicable federal, state, and local laws, order, rules, and regulations. Producer and Gatherer have entered into this Agreement with the understanding, and in reliance on the fact, that this Agreement and/or performance of this Agreement are not and will not be subject to the jurisdiction or regulation of the Federal Energy Regulatory Commission (“FERC”). If this Agreement and/or performance of this Agreement becomes subject to such jurisdiction and/or regulation, this Agreement shall automatically terminate unless Producer and Gatherer agree, in writing, within thirty (30) days of the effective date of the attachment of any such jurisdiction and/or regulation, that this Agreement shall continue after such effective date.

20. Disputes

20.1. Should a dispute arise between the Parties, the Parties shall promptly seek to resolve any such dispute by negotiations among the senior executives of the Parties who have the authority to settle such dispute (“Senior Executives”) prior to the initiation of any lawsuit. The Senior Executives shall meet at a mutually acceptable time and place within fifteen (15) days and thereafter as often as they reasonably deem necessary to exchange relevant information and to attempt to resolve the dispute. All negotiations and communications pursuant to this Section shall be treated and maintained by the Parties as confidential information and shall be treated as compromise and settlement negotiations for purposes of the federal and state Rules of Evidence. If the matter has not been resolved within thirty (30) days after the initial meeting of the Senior Executives, or such longer period as may be mutually agreed upon, either Party may initiate a lawsuit.

20.2. In any suit filed by a Party hereto to resolve a dispute arising under this Agreement or related to the services provided hereunder, each Party hereby covenants and agrees to take all steps necessary to waive a trial by jury.

Gathering Agreement 22

21. Notices and Payments

Any notice, request, demand, statement, or bill provided for in this Agreement shall be in writing and delivered by hand, mail, or facsimile. All such written communications shall be effective upon receipt by the other party at the address of the parties hereto as follow:

Producer
Statements:	Quicksilver Resources Inc.
	777 West Rosedale Street
	Fort Worth, Texas 76104 Attn: Revenue Accounting
Payments:	Quicksilver Resources Inc.
	777 West Rosedale Street
	Fort Worth, Texas 76104 Attn: Accounting
Contractual:	Quicksilver Resources Inc.
	777 West Rosedale Street
	Fort Worth, Texas 76104 Attn: Marketing
Gatherer
Statements:	Cowtown Pipeline L.P.
	777 West Rosedale Street
	Fort Worth, TX 76104 Attn: Revenue Accounting
Payments:	Cowtown Pipeline L.P.
	777 West Rosedale Street
	Fort Worth, TX 76104 Attn: Accounting
Contractual:	Cowtown Pipeline L.P.
	777 West Rosedale Street
	Fort Worth, TX 76104 Attn: Marketing

Any of the Parties may designate a further or different address by giving written notice to the other Parties.

22. Right to Process the Gas

Producer agrees that Gatherer shall have the right to process, or cause to be processed, blend, or cause to be blended, the Gas delivered hereunder for the extraction of natural gas liquids and other valuable components, to the extent that Gatherer or its affiliates constructs, acquires or otherwise obtains access to facilities capable of processing such Gas. Upon written notice to Producer that Gatherer is ready and willing to exercise this right, the Parties will proceed to negotiate in good faith the terms and fees for the processing of the Gas at any such facility.

Gathering Agreement 23

23. Assignment

This Agreement shall be binding upon and inure to the benefit of the heirs, executors, administrators, successors, and assigns of the respective Parties hereto, but no transfer of or succession to the interest of any Party hereunder, either wholly or partially, shall affect or bind the other Parties until it shall have been furnished with the original instrument or with the proper proof that the claimant is legally entitled to such interest.

24. Miscellaneous

24.1. No waiver by any Party of any one or more defaults in the performance of any provision of this Agreement shall operate or be construed as a waiver of any default or future defaults, whether of a like or different character.

24.2. No modifications of the terms and provisions of the Agreement shall be made except by the execution of written agreements. This Agreement contains the entire agreement between the Parties and there are no oral promises, agreements, or warranties affecting it.

24.3. The descriptive headings of the provisions of these general provisions are formulated and used for convenience only and shall not be deemed to affect the meaning or construction of any such provisions.

24.4. This Agreement supersedes and replaces the Prior Gathering Agreement, and any other contract(s) or agreements(s) which may exist between the Parties covering the gathering or processing of the Gas dedicated hereunder, .

24.5. Nothing in this Agreement is intended to create a partnership or joint venture under state law or to render the Parties hereto jointly and severally liable to any third party. Each of the Parties elects to be excluded from the provisions of Subchapter K, Chapter 1 of Subtitle A, of the Internal Revenue Code of 1986 pursuant to the provisions of Article 761(a) of such code and from any similar provisions of state law. Gatherer shall timely file such evidence of this election as may be required under applicable law.

24.6. Should any section, paragraph, subparagraph, or other portion of this Agreement be found invalid as a matter of law in a duly authorized court, or by a duly authorized government agency, then only that portion of the Agreement shall be invalid. The remainder of the Agreement which shall not have been found invalid shall remain in full force and effect.

Gathering Agreement 24

24.7. THIS AGREEMENT, AND ALL QUESTIONS RELATING TO ITS VALIDITY, INTERPRETATION, PERFORMANCE, AND ENFORCEMENT (INCLUDING, WITHOUT LIMITATION, PROVISIONS CONCERNING LIMITATIONS OF ACTIONS) SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, NOTWITHSTANDING ANY CONFLICT-OF-LAWS DOCTRINES OF SUCH STATE OR OTHER JURISDICTION TO THE CONTRARY. ALL MATTERS LITIGATED BY OR BETWEEN THE PARTIES THAT INVOLVE THIS AGREEMENT, THE RELATIONSHIP OF THE PARTIES, OR ANY RELATED DOCUMENTS OR MATTERS HEREUNDER SHALL BE BROUGHT ONLY IN FORT WORTH, TARRANT COUNTY, TEXAS.

24.8. This Agreement was prepared jointly by the Parties hereunder and not by any Party to the exclusion of the other.

24.9. Producer recognizes and acknowledges Gatherer’s proprietary interest in this Agreement, and Producer agrees not to divulge any of the contents hereof to any other person, firm, corporation, or other entity. Producer agrees to be responsible for enforcing the confidentiality of this Agreement and agrees to take such action as necessary to prevent any disclosure by any of its agents or employees.

[SIGNATURE PAGE FOLLOWS]

Gathering Agreement 25

IN WITNESS WHEREOF, the Parties hereto have executed this Agreement in several originals as of the Effective Date.

PRODUCER
Quicksilver Resources Inc.
By:	/s/ Stan Page
	Stan Page Vice President – U. S. Operations
GATHERER
Cowtown Pipeline L.P., a Texas limited partnership
By:	Cowtown Pipeline Management, Inc., a Texas corporation, its general partner
	By:	/s/ Thomas F. Darden Thomas F. Darden Chairman of the Board

Gathering Agreement 26

EXHIBIT A

to the

AMENDED AND RESTATED GAS GATHERING AGREEMENT

This Exhibit A is attached to the Amended and Restated Gas Gathering Agreement (the “Agreement”) dated effective September 1, 2008 by and between Quicksilver Resources Inc., as Producer, and Cowtown Pipeline L.P., as Gatherer, and made a part thereof for all purposes. All defined terms used herein shall have the same meaning as set forth in the Agreement.

Contract Area

[Lands located in Tarrant County, Texas depicted on attached plat]

Gathering Agreement 27

EXHIBIT B

to the

AMENDED AND RESTATED GAS GATHERING AGREEMENT

This Exhibit B is attached to the Amended and Restated Gas Gathering Agreement (the “Agreement”) dated effective September 1, 2008 by and between Quicksilver Resources Inc., as Producer, and Cowtown Pipeline L.P., as Gatherer, and made a part thereof for all purposes. All defined terms used herein shall have the same meaning as set forth in the Agreement.

Gathering System Receipt Point(s)

Gathering System Receipt Point	Survey	Meter/CDP
Boswell-North 1-5 Boswell-South 6-9			TX 20426
Exelon North Exelon South Olcott-North			TX 20616
Olcott South Martin 820 Duke City of Arlington Lawhon #1 and #2 Fedex SE Freightline Louis Land Sun valley South Loop 820			TX 20673

Delivery Point(s) to Transporter

Delivery Point	Transporter	Meter
Handley Quicksilver	Energy Transfer Fuel, LP	#009783

Gathering Agreement 28

EX-10.55

Exhibit 10.55

FIRST AMENDMENT TO

AMENDED AND RESTATED GAS GATHERING AGREEMENT

[LAKE ARLINGTON]

This First Amendment to Amended and Restated Gas Gathering Agreement (this “Amendment”) is entered into as of September 29, 2009, between Quicksilver Resources Inc. (“Producer”), and Cowtown Pipeline Partners L.P. (“Gatherer”).

RECITALS

A. Producer and Gatherer, as assignor of Cowtown Pipeline L.P., are parties to that certain Amended and Restated Gas Gathering Agreement (the “Lake Arlington Agreement”), dated August 18, 2008 but effective as to deliveries commencing September 1, 2008 (the “Effective Date”), and covering the gathering of natural gas produced from Producer’s wells in the Lake Arlington area, Tarrant County, Texas.

B. Producer and Gatherer are also parties to that certain Sixth Amended and Restated Gas Gathering and Processing Agreement dated effective September 1, 2008 (the “Processing Agreement”), covering the gathering and processing of natural gas produced by Producer in eight counties in the Fort Worth Basin in Texas, including Tarrant County.

C. The parties intended for the Lake Arlington Agreement to be in lieu of and replace the Processing Agreement to the extent of the natural gas produced and gathered in the Lake Arlington area, and inadvertently omitted a sentence from Section 17.1 of the Lake Arlington Agreement (pertaining to unprofitable operations) that had previously been agreed upon by Gatherer and Producer as reflected in Section 19.1 of the Processing Agreement.

NOW, THEREFORE, in consideration of the mutual premises and benefits herein contained, Producer and Gatherer hereby amend and correct the Lake Arlington Agreement to add the following sentence to the end of Section 17.1, Unprofitable Operations and Rights of Termination:

“In the event that Gatherer refuses to gather the Gas for a period of sixty (60) consecutive days causing Producer’s well(s) to be shut-in, Producer shall have the option, exercised solely at its discretion, to terminate the Agreement in its entirety insofar and only insofar as it pertains to Gas produced from the affected well(s) by providing to Gatherer thirty (30) days’ advance written notice of such termination.”

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

EXECUTED as of the date first written above.

PRODUCER:		GATHERER:
		Cowtown Pipeline Partners L.P.
Quicksilver Resources Inc.		By:	Quicksilver Gas Services Operating GP LLC, its general partner
By:	/s/ Jeff Cook
Name:	Jeff Cook	By:	/s/ Thomas F. Darden
Its:	Executive Vice President	Name:	Thomas F. Darden
		Its:	President and CEO

First Amendment,

Lake Arlington Gathering Agreement

2

EX-10.56

Exhibit 10.56

Execution Version

SECOND AMENDMENT TO

GAS GATHERING AGREEMENT

This Second Amendment (this “Amendment”) to the Amended and Restated Gas Gathering Agreement dated as of October 1, 2010 (the “Effective Date”), by and between Quicksilver Resources Inc. (“Producer”) and Cowtown Pipeline Partners L.P. (“Gatherer”).

WHEREAS, Producer and Gatherer, as the assignee of Cowtown Pipeline L.P., are parties to the Amended and Restated Gas Gathering Agreement dated as of September 1, 2008, as amended by the First Amendment dated as of September 29, 2009 (the “Lake Arlington Agreement”);

WHEREAS, pursuant to the Purchase Agreement (the “Purchase Agreement”) dated as of July 22, 2010, as amended, by and among Producer, Crestwood Holdings LLC (f/k/a First Reserve Crestwood Holdings LLC), Cowtown Pipeline L.P. and Cowtown Gas Processing L.P., Producer has agreed to transfer its indirect ownership interests in Gatherer to Crestwood Holdings LLC; and

WHEREAS, in connection with the transactions contemplated by the Purchase Agreement, the parties hereto desire to enter into this Amendment in order to modify certain of the terms and conditions of the Lake Arlington Agreement as set forth below.

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

1. Paragraph 18 is amended by replacing the words “August 10, 2017” with “December 31, 2020”.

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

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

QUICKSILVER RESOURCES INC.
By:	/s/ Glenn Darden
	Name: Glenn Darden Title: President & Chief Executive Officer
COWTOWN PIPELINE PARTNERS L.P.
By:	Quicksilver Gas Services Operating GP LLC, its general partner
By:	Quicksilver Gas Services Operating LLC, its sole member
By:	Quicksilver Gas Services LP, its sole member
By:	Quicksilver Gas Services GP LLC, its general partner
By:
	Name:
	Title:

[Signature page to Lake Arlington GGA Amendment]

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

QUICKSILVER RESOURCES INC.
By:
	Name:
	Title:
COWTOWN PIPELINE PARTNERS L.P.
By:	Quicksilver Gas Services Operating
	GP LLC, its general partner
By:	Quicksilver Gas Services Operating
	LLC, its sole member
By:	Quicksilver Gas Services LP, its
	sole member
By:	Quicksilver Gas Services GP LLC,
	its general partner
By:	/s/ Robert G. Phillips
	Name: Robert G. Phillips
	Title: President

[Signature page to Lake Arlington GGA Amendment]

EX-21.1

Exhibit 21.1

SUBSIDIARIES OF THE REGISTRANT

NAME OF SUBSIDIARY	STATE/JURISDICTION OF INCORPORATION/ ORGANIZATION	NAME UNDER WHICH BUSINESS IS CONDUCTED
Quicksilver Resources Canada Inc.	Alberta	Quicksilver Resources Canada Inc.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-160046 on Form S-3 and Registration Statement Nos. 333-166208, 333-134430, 333-91526, 333-161235 and 333-116180 on Form S-8 of our reports dated April 15, 2012, relating to the consolidated financial statements of Quicksilver Resources Inc. and subsidiaries (which report includes an explanatory paragraph relating to the adoption of Accounting Standards Update No. 2010-3, “Oil and Gas Reserve Estimation and Disclosures”), and the effectiveness of Quicksilver Resources Inc. and subsidiaries’ internal control over financial reporting (which report expresses an adverse opinion on the effectiveness of Quicksilver Resources Inc. and subsidiaries’ internal control because of a material weakness), appearing in this Annual Report on Form 10-K of Quicksilver Resources Inc. and subsidiaries for the year ended December 31, 2011.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas

April 15, 2012

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

Data & Consulting Services Division of Schlumberger Technology Corporation consents to: (i) the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Quicksilver Resources Inc. (the “Company”) for the year ended 31 December 2011 (the “Annual Report”); (ii) the use in the Annual Report of information contained in our reports setting forth the estimate of net revenue from the Company’s proved oil and gas reserves as of 31 December 2011, 2010 and 2009 and our summary report filed as Exhibit 99.1 to the Annual Report; and (iii) the incorporation by reference into the Company’s Registration Statement No. 333-160046 on Form S-3 and Registration Statement Nos. 333-91526, 333-161235, 333-116180, 333-134430 and 333-166208 on Form S-8 of all references to our firm including the information and summary report referenced in (ii) above.

DATA & CONSULTING SERVICES DIVISION OF SCHLUMBERGER TECHNOLOGY CORPORATION
By:	/s/ Charles M. Boyer
	Charles M. Boyer II, P.G., C.P.G., C.C.G. Advisor—Unconventional Reservoirs Pittsburgh GPE Manager

5 March 2012

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

LaRoche Petroleum Consultants, Ltd. consents to: (i) the references to our firm in the form and context in which they appear in the Annual Report on Form 10-K of Quicksilver Resources Inc. (the “Company”) for the year ended December 31, 2011 (the “Annual Report”); (ii) the use in the Annual Report of information contained in our reports setting forth the estimate of net revenue from the Company’s proved oil and gas reserves as of December 31, 2011, 2010 and 2009 and our summary report filed as Exhibit 99.2 to the Annual Report; and (iii) the incorporation by reference into the Company’s Registration Statement No. 333-160046 on Form S-3 and Registration Statement Nos. 333-91526, 333-161235, 333-116180, 333-134430 and 333-166208 on Form S-8 of all references to our firm including the information and summary report referenced in (ii) above.

LAROCHE PETROLEUM CONSULTANTS, LTD.
By:	/s/ Stephen W. Daniel
	Stephen W. Daniel Partner

April 11, 2012

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Glenn Darden, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: April 15, 2012

/s/    Glenn Darden        

Glenn Darden

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Philip Cook, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: April 15, 2012

/s/    Philip Cook        

Philip Cook

Executive Vice President – Chief Financial Officer

EX-32.1

Exhibit 32.1

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

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, in connection with the Annual Report on Form 10-K of Quicksilver Resources Inc. (the “Company”) for the year ended December 31, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Philip Cook, Executive Vice President – Chief Financial Officer of the Company, and Glenn Darden, President and Chief Executive Officer of the Company, each certifies that, to his knowledge:

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

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

Date: April 15, 2012

By:	/s/ Philip Cook	By:	/s/ Glenn Darden
	Philip Cook Executive Vice President – Chief Financial Officer		Glenn Darden President and Chief Executive Officer

EX-99.1

Exhibit 99.1

Data & Consulting Services Division of Schlumberger Technology Corporation
Two Robinson Plaza, Suite 200 Pittsburgh, PA 15205 Tel: 412-787-5403 Fax: 412-787-2906

22 February 2012

Quicksilver Resources, Inc.

801 Cherry Street

Suite 3700, Unit 19

Fort Worth, Texas 76102

Dear Gentlemen:

At the request of Quicksilver Resources, Inc. (QRI), through their letter of engagement, Data & Consulting Services (DCS) Division of Schlumberger Technology Corporation has evaluated the proved reserves of certain QRI oil and gas interests located in the United States (U.S.) as of 31 December 2011. The evaluated properties are located in Colorado, Montana, Texas, and Wyoming. This report was completed as of the date of this letter and has been prepared using constant prices and costs and conforms to our understanding of the U.S. Securities and Exchange Commission (SEC) guidelines and applicable financial accounting rules. All prices, costs, and cash flow estimates are expressed in U.S. dollars (US$). It is our understanding that the properties evaluated by DCS comprise one hundred percent (100%) of QRI’s proved reserves located in the U.S. and comprise approximately 88% of QRI’s total proved reserves. We believe that the assumptions, data, methods, and procedures used in preparing this report are appropriate for the purpose of this report. The Lead Evaluator for this evaluation was Charles M. Boyer II, PG, CPG, and his qualifications, independence, objectivity, and confidentiality meet the requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Table 1 summarizes the estimates of the net reserves and future net revenue, as of 31 December 2011, for the QRI US evaluated properties. Unescalated prices and costs were used for all properties contained in this evaluation.

Table 1

Estimated Net Reserves And Income

Certain U.S. Proved Oil And Gas Interests

Unescalated Prices And Costs

Quicksilver Resources, Inc.

As Of 31 December 2011

	Proved Producing Reserves		Proved Nonproducing Reserves		Proved Undeveloped Reserves		Total Proved Reserves
Remaining Net Reserves
Oil – MMbbls		2.076		0.468		0.490		3.035
Gas – Bscf		1,003.190		240.998		584.717		1,828.904
NGL – MMbbls		59.019		1.883		41.243		102.145
Income Data (MM$)
Future Net Revenue		6,571.545		975.944		4,099.513		11,647.002
Deductions
Operating Expense		2,716.303		389.769		1,555.952		4,662.024
Production Taxes		485.634		68.315		280.273		834.222
Investment		1.527		82.349		950.895		1,034.771
Abandonment		77.283		1.819		11.768		90.870
Future Net Cashflow		3,290.797		433.692		1,300.625		5,025.114
Discounted PV @ 10% (MM$)		1,579.379		169.395		193.501		1,942.275

Data & Consulting Services Division of Schlumberger Technology Corporation   22 February, 2012 Page 2

Note: Proved producing reserves include Inactive and Salt Water Disposal well costs.

Values in the tables of this report may not add up arithmetically due to rounding procedure in the computer software program used to prepare the economic projections. All hydrocarbon liquids are reported as 42 gallon barrels. Gas volumes are reported at the standard pressure and temperature bases of the area where the gas is sold.

We are independent with respect to QRI as provided in the SEC regulations. Neither the employment of nor the compensation received by DCS was contingent upon the values estimated for the properties included in this report.

Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. The reserves included in this report include only proved reserves and do not include probable or possible reserves. QRI has an active exploration and development program to develop their interests in certain tracts not classified as proved at this time. Future drilling may result in the reclassification of additional volumes to the proved reserve category. However, changes in the regulatory requirements for oil and gas operations may impact future development plans and the ability of the company to recover the estimated proved undeveloped reserves. The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.

Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality and quantity of data available and of the engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision. A portion of these reserves are for undeveloped locations and producing or non-producing wells that lack sufficient production history to utilize conventional performance-based reserve estimates. In these cases, the reserves are based on volumetric estimates and recovery efficiencies along with analogies to similar producing areas. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. As additional production and pressure data becomes available, these estimates may be revised up or down. Actual future prices may vary significantly from the prices used in this evaluation; therefore, future hydrocarbon volumes recovered and the income received from these volumes may vary significantly from those estimated in this report. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

Standard geological and engineering methods generally accepted by the petroleum industry were used in the estimation of QRI’s reserves. Deterministic methods were used for all reserves included in this report. The appropriate combination of conventional decline curve analysis (DCA), production data analysis, volumetrics, and type curves were used to estimate the remaining reserves in the various producing areas. Volumetric calculations were based on data and maps provided by QRI. Comparisons were made to similar properties for which more complete data were available for areas of new development.

All prices used in preparation of this report were based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December 2011. The resulting Henry Hub gas price used was $4.120/MMBtu and the resulting West Texas Intermediate oil price used was $95.71/Bbl. The prices were adjusted for local differentials, gravity and Btu where applicable. These adjustments are made for each well based on the differences between the actual product prices received by well and the reference prices over a twelve month period. The resulting average prices in this evaluation are $3.59/Mscf for gas, $86.16/Bbl for oil and $47.21/BBl for NGL. The average prices were calculated using the total net future revenue by product prior to taxes and expenses divided by the total net reserves by product. As required by SEC guidelines, all pricing was held constant for the life of the projects (no escalation).

Data & Consulting Services Division of Schlumberger Technology Corporation   22 February, 2012 Page 3

Operating costs used in this report were based on values reported by QRI and reviewed by DCS. Well costs include direct expenses, allocated general and administrative overhead (G&A), production taxes, marketing, transportation, and compression charges. QRI’s estimates for capital costs for all non-producing and undeveloped wells are included in the evaluation. QRI has indicated to us that they have the ability and intent to implement their capital expenditure program as scheduled. Operating costs and capital costs were held constant for the life of the projects (no escalation).

Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and gas adjusted for commodity price basis differential and gathering/ transportation expense. Future net income (cashflow) is future net revenue less net lease operating expenses, state severance or production taxes, operating/development capital expenses and net salvage. Future net income (cashflow) for nonoperated wells includes those general and administrative (G&A) deductions charged by the operator for a particular well or project on a monthly basis; operated well G&A deductions include only those expenses estimated as necessary to continue production activities. Future plugging, abandonment, and salvage costs are included at the economic life of each well or unit. No provisions for State or Federal income taxes have been made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis.

In the conduct of our evaluation, we have not independently verified the accuracy and completeness of information and data furnished by QRI with respect to ownership interests, historical gas production, costs of operation and development, product prices, payout balances, and agreements relating to current and future operations and sales of production. If in the course of our examination something came to our attention which brought into question the validity or sufficiency of any of the information or data provided by QRI, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or independently verified such information or data.

In our opinion the above-described estimates of QRI’s proved reserves and supporting data are, in the aggregate, reasonable. It is also our opinion that the above-described estimates of QRI’s proved reserves conform to the definitions of proved oil and gas reserves promulgated by the SEC. These reserves definitions are provided at the conclusion of this letter.

All data used in this study were obtained from QRI, public industry information sources, or the non-confidential files of DCS. A field inspection of the properties was not made in connection with the preparation of this report. The potential environmental liabilities attendant to ownership and/or operation of the properties have not been addressed in this report. Abandonment and clean-up costs and possible salvage value of the equipment were considered in this report.

In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation, or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.

Data & Consulting Services Division of Schlumberger Technology Corporation   22 February, 2012 Page 4

Data and worksheets used in the preparation of this evaluation will be maintained in our files in Pittsburgh and will be available for inspection by anyone having proper authorization from QRI.

Sincerely yours,

/s/ Denise L. Delozier	/s/ Charles M. Boyer II, PG, CPG
Denise L. Delozier	Charles M. Boyer II, PG, CPG
Senior Engineer	Advisor - Unconventional Reservoirs
	Pittsburgh GPE Manager
/s/ Walter K. Sawyer, PE
Walter K. Sawyer, PE
Principal Consultant

EX-99.2

Exhibit 99.2

January 30, 2012

Mr. Chris Mundy

Quicksilver Resources Canada, Inc.

Suite 3700, Unit 19

801 Cherry Street

Fort Worth, Texas 76102

Dear Mr. Mundy:

At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has estimated the proved reserves and future cash flow, as of December 31, 2011, to the Quicksilver Resources Canada, Inc. (QRCI) interest in certain properties located in Alberta and British Columbia, Canada. QRCI is a wholly owned subsidiary of Quicksilver Resources, Inc. (Quicksilver). The work in this report was completed as of January 27, 2012. This report was prepared to provide Quicksilver with Securities and Exchange Commission (SEC) compliant reserve estimates. It is our understanding that the properties evaluated by LPC comprise 100 percent (100%) of QRCI’s proved reserves located in Canada. We believe that the assumptions, data, methods, and procedures used in preparing this report, as set out below, are appropriate for the purpose of this report. This report has been prepared using constant prices and costs and conforms to our understanding of the SEC guidelines, reserves definitions, and applicable financial accounting rules. All prices, costs, and cash flow estimates are expressed in United States dollars (US$).

It is our understanding that LPC evaluated approximately 12.0 percent (12.0%) of Quicksilver’s total proved reserves, that additional properties were audited or estimated by other consultants, and that the total of the audited and estimated properties by all consultants constitutes one hundred percent (100%) of Quicksilver’s aggregate reserves as estimated and reported by Quicksilver.

Summarized below are LPC’s estimates of net reserves and future net cash flow. Future net revenue is after deducting estimated Crown and freehold royalties but prior to deducting freehold mineral taxes. Future net cash flow is after deducting freehold mineral taxes, operating expenses, future capital expenditures, and abandonment but before consideration of federal income taxes. The discounted cash flow values included in this report are intended to represent the time value of money and should not be construed to represent an estimate of fair market value. We estimate the net reserves and future net cash flow to the QRCI interest, as of December 31, 2011, to be:

	Net Proved Reserves and Net Cash Flow(1)
Category	Producing		Non-Producing		Undeveloped		Total(2)
Net Remaining Reserves
Oil - MBbl		0		0		0		0
Gas - MMcf		231,114		68,257		31,260		330,631
NGL - MBbl		11		0		0		11
Income Data (US M$)
Future Net Cash Flow (US M$)		358,347		64,676		22,177		445,200
Discounted PV @ 10% (US M$)		227,344		18,397		1,467		247,208

⁽¹⁾ Includes reserves and cash flow attributable to split-title properties. For proved developed producing, split-title cases contribute 6,009 MMcf of net gas reserves and M$7,019 of the PV discounted at 10%. For proved developed non- producing, the contribution is 3,533 MMcf of net gas reserves and M$1,857 of the PV discounted at 10%. For proved undeveloped, the contribution is 3,076 MMcf of net gas and -M$170 of the PV discounted at 10%

⁽²⁾ The total proved values above may or may not match those values on the total proved summary page that follows this letter due to rounding by the economics program

The oil reserves include crude oil and condensate. Oil and natural gas liquids (NGL) reserves are expressed in thousands of barrels (MBbl), which are equivalent to 42 United States gallons. Gas reserves are expressed in millions of standard cubic feet (MMcf) at the contract temperature and pressure bases.

The estimated reserves and future cash flow shown in this report are for proved developed producing reserves and, for certain properties, proved developed non-producing, and proved undeveloped reserves. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

Both gross and net gas reserves presented in this report are after shrinkage. All prices, revenues, expenses, and cash flows referenced in this report are in United States (US) dollars which have been converted from Canadian currency using the December 31, 2011 exchange rate of 0.9833 US$ to CAN$.

This report includes: (1) summary economic projections of reserves and cash flow for each reserve category and (2) one-line summaries of basic economic data and reserves for each field area evaluated.

Estimates of reserves for this report were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The reserves in this report have been estimated using deterministic methods. The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history. Recovery from various reservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir and well performance. In some instances, comparisons were made to similar properties for which more complete data were available. We have used all methods and procedures that we considered necessary under the circumstances to prepare this report. We have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting rather than engineering or geoscience.

The estimated reserves and future cash flow amounts in this report are related to hydrocarbon prices. Historical prices through December 2011 were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from the SEC prices. In addition, future changes in environmental and administrative regulations may significantly affect the ability of QRCI to produce oil and gas at the projected levels. Therefore, volumes of reserves actually recovered and amounts of cash flow actually received may differ significantly from the estimated quantities presented in this report.

Benchmark prices used in this report are based on the twelve-month unweighted arithmetic average of the first day of the month price for the period January through December 2011. Gas prices are referenced to an AECO price of US$3.65 per MMBtu, as published in the Platts Gas Daily, and are adjusted for energy content, transportation fees, and regional price differentials. Oil and NGL prices are referenced to a West Texas Intermediate (WTI) crude oil price of US$95.71 per barrel at Cushing Oklahoma, and are adjusted for gravity, crude quality, transportation fees, and regional price differentials. These reference prices are held constant in accordance with SEC guidelines. The weighted average prices after adjustments over the life of the properties are US$90.25 per barrel of oil, US$3.19 per mcf of gas, and US$76.31 per barrel of NGL.

Lease and well operating expenses are based on data obtained from QRCI. Expenses for the properties operated by QRCI include allocated overhead costs, direct lease and field level costs as well as compression costs and marketing expenses. Wells operated by others include all direct expenses as well as general and administrative costs and overhead costs allowed under the specific joint operating agreements. Lease and well operating costs are held constant in accordance with SEC guidelines.

Capital costs and timing of all investments have been provided by QRCI and are included as required for workovers, new development wells, and production equipment. QRCI has represented to us that they have the ability and intent to implement their capital expenditure program as scheduled. Estimates of the cost to plug and abandon the wells net of salvage value are included and scheduled at the end of the economic life of individual properties. These costs are held constant.

LPC has made no investigation of possible gas volume and value imbalances that may have resulted from the overdelivery or underdelivery to the QRCI interest. Our projections are based on the QRCI interest receiving its net revenue interest share of estimated future gross oil and gas production.

Technical information necessary for the preparation of the reserve estimates herein was furnished by QRCI or was obtained from provincial regulatory agencies and commercially available data sources. No special tests were obtained to assist in the preparation of this report. For the purpose of this report, the individual well test and production data as reported by the above sources were accepted as represented together with all other factual data presented by QRCI including the extent and character of the interest evaluated.

An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined by LPC. In addition, the costs associated with the continued operation of uneconomic properties are not reflected in the cash flows.

The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this report. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the projections presented herein.

The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations. A portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history to utilize performance-related reserve estimates. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. It may be necessary to revise these estimates up or down in the future as additional performance data become available. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions represent informed professional judgments only, not statements of fact.

The results of our third party study were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Quicksilver.

Quicksilver makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Quicksilver has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Quicksilver of the references to our name as well as to the references to our third party report for

Quicksilver which appears in the December 31, 2011 annual report on Form 10-K and/or 10-K/A of Quicksilver. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Quicksilver.

We have provided Quicksilver with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Quicksilver and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The technical persons responsible for preparing the reserve estimates presented herein 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. The technical person primarily responsible for overseeing the preparation of reserves estimates herein is Stephen W. Daniel. Mr. Daniel is a Professional Engineer licensed in the State of Texas who has forty years of engineering experience in the oil and gas industry. Mr. Daniel earned a Bachelor of Science degree in Petroleum Engineering from University of Texas and has prepared reserves estimates for his employers throughout his career. He has prepared and overseen preparation of reports for public filings for LPC for the past fifteen years. LPC is an independent firm of petroleum engineers, geologists, and geophysicists and is not employed on a contingent basis. Data pertinent to this report are maintained on file in our office.

Very truly yours,

LaRoche Petroleum Consultants, Ltd.

State of Texas Registration Number F-1360

/s/ Stephen W. Daniel

Stephen W. Daniel

Licensed Professional Engineer

State of Texas No. 58581

/s/ Joe A. Young

Joe A. Young

Licensed Professional Engineer

State of Texas No. 62866

SWD:lbm

11-910