Attached files

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EX-32.1 - CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 - QUICKSILVER RESOURCES INCd291270dex321.htm
EX-10.9 - INCENTIVE STOCK OPTION AGREEMENT - QUICKSILVER RESOURCES INCd291270dex109.htm
EX-99.2 - REPORT OF LAROCHE PETROLEUM CONSULTANTS - QUICKSILVER RESOURCES INCd291270dex992.htm
EX-4.14 - ELEVENTH SUPPLEMENTAL INDENTURE - QUICKSILVER RESOURCES INCd291270dex414.htm
EX-23.3 - CONSENT OF LAROCHE PETROLEUM CONSULTANTS - QUICKSILVER RESOURCES INCd291270dex233.htm
EX-31.2 - CERTIFICATION PURSUANT TO SECTION 302 - QUICKSILVER RESOURCES INCd291270dex312.htm
EX-21.1 - SUBSIDIARIES OF THE REGISTRANT - QUICKSILVER RESOURCES INCd291270dex211.htm
EX-4.15 - TWELFTH SUPPLEMENTAL INDENTURE - QUICKSILVER RESOURCES INCd291270dex415.htm
EX-23.2 - CONSENT OF SCHLUMBERGER DATA AND CONSULTING - QUICKSILVER RESOURCES INCd291270dex232.htm
EX-23.1 - CONSENT OF DELOITTE & TOUCHE LLP - QUICKSILVER RESOURCES INCd291270dex231.htm
EX-99.1 - REPORT OF SCHLUMBERGER DATA AND CONSULTING SERVICES - QUICKSILVER RESOURCES INCd291270dex991.htm
EX-4.12 - NINTH SUPPLEMENTAL INDENTURE - QUICKSILVER RESOURCES INCd291270dex412.htm
EX-31.1 - CERTIFICATION PURSUANT TO SECTION 302 - QUICKSILVER RESOURCES INCd291270dex311.htm
EX-4.13 - TENTH SUPPLEMENTAL INDENTURE - QUICKSILVER RESOURCES INCd291270dex413.htm
EX-10.4 - FOURTH AMENDED AND RESTATED 2006 EQUITY PLAN - QUICKSILVER RESOURCES INCd291270dex104.htm
EX-10.17 - DESCRIPTION OF 2011 CASH BONUSES - QUICKSILVER RESOURCES INCd291270dex1017.htm
EX-10.54 - AMENDED AND RESTATED GAS GATHERING AGREEMENT - QUICKSILVER RESOURCES INCd291270dex1054.htm
EX-10.56 - SECOND AMENDMENT TO GAS GATHERING AGREEMENT - QUICKSILVER RESOURCES INCd291270dex1056.htm
EX-10.55 - FIRST AMENDMENT TO GAS GATHERING AGREEMENT - QUICKSILVER RESOURCES INCd291270dex1055.htm
EX-10.10 - FORM OF NONQUALIFIED SOTCK OPTION AGREEMENT - 2006 EQUITY PLAN - QUICKSILVER RESOURCES INCd291270dex1010.htm
Table of Contents

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


Table of Contents

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

 

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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


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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


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Forward-Looking Information

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

 

  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.

 

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Table of Contents

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.

 

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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

 

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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

 

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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

 

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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.

 

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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

 

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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.

 

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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.

 

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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.

 

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  (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.

 

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ACQUISITION, EXPLORATION AND DEVELOPMENT CAPITAL EXPENDITURES

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

 

     U.S.      Canada      Consolidated  
     (In thousands)  

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.

 

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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.

 

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SAFETY REGULATION

We are subject to a number of federal, state, provincial and local laws and regulations, whose purpose is to protect the health and safety of workers, both generally and within our industry. Regulations overseen by OSHA, the EPA 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.

 

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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.

 

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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

 

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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.

 

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ITEM 1A.       Risk Factors

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

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.

 

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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.

 

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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

 

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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

 

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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;

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water obtained for drilling purposes;

  Ÿ  

drilling permits and bonds;

  Ÿ  

reports concerning operations;

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spacing of wells;

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disposal wells;

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unitization and pooling of properties; and

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taxation.

 

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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

 

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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;

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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;

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selling assets;

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restructuring or refinancing debt; or

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reorganizing our capital structure.

 

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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

 

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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.

 

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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”)

 

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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.

 

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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.

 

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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.

 

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PART II.

 

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

Market Information

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

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

 

       HIGH               LOW    

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

 

LOGO

 

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Issuer Purchases of Equity Securities

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

 

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ITEM 6. Selected Financial Data

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

 

     Years Ended December 31,  
     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.

 

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following Management’s Discussion and Analysis (“MD&A”) is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Annual Report. 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

 

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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.

 

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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   
 

 

 

      

 

 

      

 

 

      

 

 

      

 

 

      

 

 

      

 

 

      

 

 

 

 

 

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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   
 

 

 

     

 

 

     

 

 

     

 

 

     

 

 

      

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

      

 

 

 

 

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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.

 

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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

 

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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

 

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