10-K 1 kwk1231201210-k.htm 10-K KWK 12.31.2012 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
 
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
OR
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number:    001-14837
QUICKSILVER RESOURCES INC.
(Exact name of registrant as specified in its charter)
Delaware
  
75-2756163
(State or other jurisdiction of
incorporation or organization)
  
(I.R.S. Employer
Identification No.)
 
 
 
801 Cherry Street, Suite 3700, Unit 19, Fort Worth, Texas
  
76102
(Address of principal executive offices)
  
(Zip Code)
817-665-5000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
  
Name of each exchange on which registered
Common Stock, $0.01 par value per share
  
New York Stock Exchange
Preferred Share Purchase Rights,
$0.01 par value per share
  
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  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, 2012, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $651,534,373 based on the closing sale price of $5.42 as reported on the New York Stock Exchange.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
Class
  
Outstanding at February 28, 2013
Common Stock, $0.01 par value per share
  
176,568,548 shares
DOCUMENTS INCORPORATED BY REFERENCE
Document
  
Parts Into Which Incorporated
Proxy Statement for the Registrant’s
May 15, 2013 Annual Meeting of Stockholders
  
Part III



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

ABR” means alternate base rate
AOCI” means accumulated other comprehensive income
Bbl” or “Bbls” means barrel or barrels
Bbld” means barrel or barrels per day
Bcf” means billion cubic feet
Bcfe” means Bcf of natural gas equivalents
Boe” means Bbl equivalents, calculated as six Mcf of gas equaling one bbl of oil
Canada” means our oil and natural gas operations located principally in British Columbia and Alberta, Canada
C$” means Canadian dollars
DD&A” means Depletion, Depreciation and Accretion
GHG” means greenhouse gas
GPT” means gathering, processing and transportation expense
LIBOR” means London Interbank Offered Rate
MBbl” or “MBbls” means thousand barrels
MBoe” means thousand Bbl of oil equivalent
MMBtu” means million British Thermal Units, a measure of heating value, and is approximately equal to one Mcf of natural gas
Mcf” means thousand cubic feet
Mcfe” means Mcf natural gas equivalent, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
MMcf” means million cubic feet
MMcfd” means million cubic feet per day
MMcfe” means MMcf of natural gas equivalent
MMcfed” means MMcfe per day
NGL” or “NGLs” means natural gas liquids
NYMEX” means New York Mercantile Exchange
OCI” means other comprehensive income
Oil” includes crude oil and condensate
PUD means proved undeveloped reserve
RSU” means restricted stock unit
Tcfe” means trillion cubic feet of natural gas equivalents

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
Barnett Shale Asset” means our operations and our assets in the Barnett Shale located in the Fort Worth basin of North Texas
BBEP” means BreitBurn Energy Partners L.P.
BBEP Unit” means BBEP limited partner unit
CERCLA” means the Comprehensive Environmental Response, Compensation and Liability Act
CMLP” means Crestwood Midstream Partners LP
Combined Credit Agreements” means collectively our Amended and Restated U.S. Credit Facility and our Amended and Restated Canadian Credit Facility
Crestwood” means Crestwood Holdings LLC
Crestwood Transaction” means the sale to Crestwood of all our interests in KGS, including general partner interests and incentive distribution rights


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Eni” means either or both Eni Petroleum US LLC and Eni US Operating Co. Inc., which are subsidiaries of Eni SpA
Eni Production” means production attributable Eni’s working and royalty interests
Eni Transaction” means the 2009 conveyance to Eni of 27.5% of Quicksilver's interest in our Alliance Asset
EPA” means the U.S. Environmental Protection Agency
FASB” means the Financial Accounting Standards Board, which promulgates accounting standards in the U.S.
Fortune Creek” means Fortune Creek Gathering and Processing Partnership, a midstream partnership formed with KKR in December 2011 dedicated to the construction and operation of natural gas midstream services within the Horn River basin of northeast British Columbia
GAAP” means accounting principles generally accepted in the U.S.
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 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 Kohlberg Kravis Roberts & Co. L.P., with whom we formed Fortune Creek
Komie North Project” means the series of contracts with NGTL for the construction of a pipeline and meter station, which will serve our and others’ transportation needs in the Horn River basin
Lake Arlington Asset” means our natural gas leasehold interests in the Lake Arlington area of the Barnett Shale
Mercury” means Mercury Exploration Company, which is owned by members of the Darden family
NEB” means National Energy Board, an independent agency which regulates international and interprovincial aspects of the oil and gas industries in Canada and is accountable to Parliament through the Minister of Natural Resources Canada.
NGTL” means NOVA Gas Transmission Ltd., a subsidiary of TransCanada PipeLines Limited
Niobrara Asset” means our operations and our assets in the Niobrara formation in northwest Colorado, which we are jointly developing with SWEPI LP
OSHA” means Occupational Safety & Health Administration
SEC” means the U.S. Securities and Exchange Commission
Southern Alberta Asset” means our operations and our assets in the Southern Alberta basin of northern Wyoming and Montana, including our Cutbank field operations and assets
SWEPI” means SWEPI LP, a subsidiary of Royal Dutch Shell plc
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 three areas: Jeff Davis and Reeves Counties, Upton and Crockett Counties and Pecos County



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INDEX TO ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2012
 
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
 
 
 
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
 
 
 
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
 
 
 
ITEM 15.
 

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


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Forward-Looking Information
Certain statements contained in this Annual Report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
changes in general economic conditions;
fluctuations in natural gas, NGL and oil prices;
failure or delays in achieving expected production from exploration and development projects;
our ability to achieve anticipated cost savings and other spending reductions;
uncertainties inherent in estimates of natural gas, NGL and oil reserves and predicting natural gas, NGL and oil production and reservoir performance;
effects of hedging natural gas, NGL and oil prices;
fluctuations in the value of certain of our assets and liabilities;
competitive conditions in our industry;
actions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters, customers and counterparties;
changes in the availability and cost of capital;
delays in obtaining oilfield equipment and increases in drilling and other service costs;
delays in construction of transportation pipelines and gathering, processing and treating facilities;
operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;
failure or delay in completing strategic transactions;
the effects of existing or future litigation;
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
additional factors described elsewhere in this Annual Report.
This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict, and are subject to material uncertainties that may affect actual results and may be beyond our control. The forward-looking statements included in this Annual Report are made only as of the date of this Annual Report, and we undertake no obligation to update any of these forward-looking statements to reflect subsequent events or circumstances except to the extent required by applicable law.
All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.


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PART I

ITEM 1.
Business
GENERAL
We are an independent oil and gas company engaged primarily in the acquisition, exploration, development and production of onshore oil and gas in North America and are based in Fort Worth, Texas. We focus primarily on unconventional reservoirs where hydrocarbons may be found in challenging geological conditions, such as fractured shales and coalbeds. Our producing oil and 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 1.5 Tcfe at December 31, 2012. Our three core areas include:
Barnett Shale;
Horn River; and
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 oil exploration opportunities in North America, most notably in the following regions:
Midland and Delaware basins in West Texas;
Sand Wash Basin in northwest Colorado.
Our current exploration opportunities will provide growth in years to come and our new ventures team actively studies other basins in North America which, assuming favorable market conditions, 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 28, 2013, members of the Darden family and entities controlled by them beneficially owned approximately 30% of our outstanding common stock.
STRATEGIC TRANSACTIONS IN THE LAST FIVE YEARS
On December 28, 2012, we entered into an agreement with SWEPI LP to jointly develop our oil and gas interests in the Niobrara formation of the Sand Wash Basin and to establish an Area of Mutual Interest (“AMI”) covering in excess of 850,000 acres. Each party assigned to the other a 50% working interest in the majority of its combined acreage so that each party owns a 50% interest in more than 320,000 acres and has the right to a 50% interest in any acquisition within the AMI. SWEPI paid us an equalization payment for 50% of the acreage contributed by us in excess of the acreage that SWEPI contributed. SWEPI is the operator of the majority of the jointly owned lands. This relationship is strategic to the development of the Niobrara Asset as it created contiguous acreage blocks, which will lead to a more orderly and cost-effective development of the basin.
In February 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 amended the registration statement in May to include financial statements for 2011 and to address comments received from the SEC and again in June to include financial statements for the first quarter of 2012 and to address further comments received from the SEC. In July 2012, we were informed that the SEC had no further comments. During the fourth quarter of 2012 we recognized an expense for the deferred filing fees associated with this offering since the transaction has been dormant since June 2012. This accounting treatment does not preclude us from updating the registration document at a later date and we will continue to monitor market conditions to assess the timing of an offering, which may be influenced by a joint venture covering our Barnett Shale Asset.
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 yield reduced costs for treating and transporting gas to sales markets.
In October 2010, we sold all of our interests in KGS, a Barnett Shale midstream subsidiary, 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 for consideration of an earn-out on these assets.


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In May 2010, we acquired an additional 25% working interest in our Lake Arlington Asset which represented 125 Bcf of proved reserves, for $62 million in cash and 3.6 million BBEP Units. Throughout 2010 and 2011, through this and other transactions, we continued to sell our BBEP Units. We have owned no BBEP Units since 2011.
In January 2010, we completed the sale of certain of our midstream assets to KGS for $95 million. KGS funded the purchase primarily with proceeds from an equity offering to the public.
In June 2009, we completed the Eni Transaction in which we sold 121 Bcf of proved reserves to Eni for $280 million. 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.
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:
Strive to achieve and then to maintain a prudent capital structure to ensure financial flexibility:  We believe that a flexible financial structure would enable us to capitalize on opportunities and to limit our financial risk. Accordingly, in 2013 we intend to pursue the monetization of selected assets to improve our liquidity and to reduce our debt. We also expect to access the capital markets to begin extending the maturity of our senior notes. Our capital program has been reduced to the level of estimated cash inflows. We believe that these efforts will provide financial flexibility.
Focus on core areas of repeatable, low-risk development:  We believe that development activity in areas where we have acquired a contiguous acreage position allows us to efficiently deploy our resources, manage our costs and leverage our technical expertise. Additionally, we search for new acreage positions that are not only contiguous from a surface perspective, which is more efficient for drilling, but are also contiguous from a resource perspective, which results in a more profitable asset when developed.
Pursue disciplined organic growth opportunities: We generally spend about 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 established significant expertise and a demonstrated history of identifying, developing and producing fractured shales and coal beds. 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 may build additional midstream infrastructure to secure affordable gathering, processing and transportation costs. Finally, we move the project to the full development stage. We have historically monetized some of our mature assets to provide financial flexibility to pursue future projects.
In order to increase the predictability of the prices we receive for our natural gas and NGL production, we hedge the commodity price of a substantial portion of our expected production with financial derivatives. We regularly review the credit-worthiness of our derivative counterparties, and our derivative program is spread among numerous financial institutions, all of whom participated in our credit facilities at the time of entering into the derivative. We have entered into long-term derivatives to provide predictability over longer periods.
BUSINESS STRENGTHS
High-quality asset base with long reserve life:  Our proved reserves totaled approximately 1.5 Tcfe as of December 31, 2012, of which 88.0% were developed. Our Barnett Shale Asset accounts for approximately 81% of our proved reserves and approximately 18% are located in our Horseshoe Canyon Asset and our Horn River Asset. These areas have a history of proven well performance and have the established and emerging infrastructure necessary to deliver our production to sales markets. We believe our reserves are characterized by long lives and predictable well production profiles. Based on our annualized fourth quarter 2012 average production from all of our properties, our implied reserve life (proved reserves divided by annualized fourth quarter 2012 production) was 11.7 years and our implied proved developed reserve life (proved developed reserves


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divided by annualized fourth quarter 2012 production) was 10.3 years. As of December 31, 2012, almost 97% of our proved reserves were attributable to properties we operate.
Multi-year inventory of developmental drilling projects:  As of December 31, 2012, we owned leases covering more than 569,000 net acres in our three core areas, of which 65% were classified as held by production. Within our Barnett Shale Asset alone, we have identified drilling locations that provide us greater than a 15-year inventory of drilling locations based on our three year historical drilling rate. Our drilling success rate has averaged more than 99% during the past three years. We use 3-D seismic data to enhance our ongoing drilling and development efforts as well as to identify 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 natural gas resources. As of December 31, 2012, we have successfully drilled and completed 12 gas wells in our Horn River Asset, and 98% of our licensed acreage has been validated. Our total proved reserves in our Horn River Asset are 105 Bcfe. We have also encountered oil in our Niobrara Asset across a 35-mile east-to-west line, and we have drilled two productive wells in our West Texas Asset.
Extensive technical experience and familiarity with developing and operating Barnett Shale properties and other unconventional resources.  We are one of the larger producers in the Barnett Shale. The development of the Barnett Shale helped pioneer unconventional shale development, and the Barnett Shale currently produces over 6.2 Bcf of natural gas per day with over 16,000 wells drilled since 2003, according to the Railroad Commission of Texas. Our staff of petroleum professionals, many of whom have significant engineering, geologic and other expertise, 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.
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 have gathering 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, 2012, we had total proved reserves of approximately 1.5 Tcfe, of which 76% is natural gas and 23% is NGLs. For 2012, we had total production of 132 Bcfe or 360 MMcfed. In the last five years, our reserves have declined at an approximate compound annual decline rate of 1%, and our production has grown at an approximate compound annual growth rate of 11%.
We believe the development of our leasehold interests in our core areas, and our exploration activities in our Niobrara Asset and West Texas Asset will give us the flexibility over the next several years to further grow reserves and production. Although not a part of our plans for 2013, 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 2013 capital program and our projected production levels can be found in Item 7 of this Annual Report.
Barnett Shale
Over 81% of our total proved reserves and over 76% of our total average daily production in 2012 were in our Barnett Shale Asset. In the fourth quarter of 2012, our net production from our wells in our Barnett Shale Asset was 247.1 MMcfed. We expect approximately two-thirds of our 2013 production to come from our Barnett Shale Asset.
At December 31, 2012, we had approximately 127,000 net acres in the Barnett Shale of which approximately 60% 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 2012, sales of NGLs represented 24% of our Barnett Shale Asset production.
During 2012, we drilled 22 (20.5 net) wells and completed 45 (33.0 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, 2012, we had drilled a total of 1,052 (879.9 net) wells in our Barnett Shale Asset since we began exploration and


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development operations in 2003. At December 31, 2012, we did not and currently do not have drilling rigs operating in our Barnett Shale Asset, but expect to utilize a rig in the basin in 2013 on a periodic basis.
West Texas
During 2012, 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. Our leases total 125,000 acres across Reeves, Pecos, Jeff Davis, Upton and Crockett Counties. We drilled and completed our first short-lateral well in Pecos County in August 2012, which targeted the Third Bone Springs formation, and we drilled and completed another short-lateral well in Upton County in December 2012, which targeted the Wolfcamp formation. Total proved reserves in our West Texas Asset are 0.6 Bcfe at December 31, 2012.
Niobrara
We hold approximately 167,000 primarily non-operated net acres in the Sand Wash basin, which we believe are prospective for oil from the Niobrara formation. We are currently conducting exploratory activities and have eight producing wells as of December 31, 2012. During 2012, we drilled and completed three vertical wells using a variety of stimulation methods and drilled one well. Jointly with SWEPI, we plan to participate in up to an additional eight wells in 2013, after which we plan to advance to the development stage, pending continued positive well results. Total proved reserves in our Niobrara Asset are 0.5 Bcfe at December 31, 2012.
Horn River
We hold approximately 129,000 net acres in our Horn River Asset. During August 2012, we completed an eight-well pad, with projected flow rates from each well between 23 MMcfd and 34 MMcfd at very high flowing pressures. We believe the results from these wells, the continuous nature of the pay sections as shown in 3-D seismic and the pay mapping from the six exploration wells drilled on the northern part of our acreage are indicative of the continuity of the formation throughout our acreage position.
As of December 31, 2012, we had eight wells producing and four wells capable of production that were temporarily shut-in. Production was curtailed from the new eight-well pad since August 2012 due to a delay in commissioning of a third-party's treating facility and due to limitations of surface equipment. In December 2012, we secured temporary alternative treating and transportation and increased gross production to 100 MMcfd within 15 days. We do not have a firm date for when the new treating facility, at which we have firm capacity, will be commissioned, but we believe we have sufficient treating and transportation capacity in the interim to meet our needs. Our total proved reserves in our Horn River Asset were 104.8 Bcfe as of December 31, 2012, all of which were natural gas and developed.
On January 30, 2013, the Canadian NEB issued its report recommending against approval of NGTL's Komie North Project, which included a 75-mile pipeline that would connect NGTL's Alberta system to a meter station planned to be constructed on our acreage in the Horn River Basin. We believe the NEB's recommendation against the Komie North Project will be adopted by the federal authority. The NEB concluded that the evidence presented at this time did not justify a 36-inch line as proposed; however, its recommendation notwithstanding, the NEB emphasized its belief in the long-term prospects for development of the Horn River Basin. We believe NGTL will undertake efforts to secure additional producer support for this pipeline.
The company had previously provided $30 million in letters of credit, which were reduced to $14 million during March 2013. We expect future financial assurances upon a revised application would be reduced proportionately relative to additional producer support. Also, we expect the application may be delayed by up to two years. Likewise, Quicksilver is planning to defer drilling in the Horn River Basin until 2014 and may recommend that Fortune Creek defer construction of a natural gas treating facility until at least 2016 to coincide with the revised timelines for the Komie North Project. Our agreements with NGTL will continue to require us to deliver up to 1 Tcf of production over a 10-year period and are expected to be amended to reflect the updated project time line. Our requirements may be reduced by delivery of volumes from third-party producers.
Our ability to sell gas at the Station 2 and AECO hubs has not been impacted by the NEB's recommendation, as our acreage is served by existing treating facilities and pipelines which today can accommodate in excess of 1 billion cubic feet per day. Due to the pace of development in the basin by all producers, discounted excess capacity is available in the region to meet Quicksilver's needs.
Horseshoe Canyon
At December 31, 2012, our Horseshoe Canyon Asset proved reserves were 162.0 Bcfe, substantially all of which was natural gas. As of December 31, 2012, we had 40,526 (30,116 net) undeveloped acres in our Horseshoe Canyon Asset. During 2012 we spent $0.7 million for drilling and completion in our Horseshoe Canyon Asset, largely funded by cash flows its from operations. No substantial drilling or completion activity is anticipated for 2013.


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Rockies
The Rockies area includes our Southern Alberta Asset which is located in the Cut Bank field in Montana. We have approximately 143,000 net acres in the Southern Alberta basin, 73% of which is held by production. At December 31, 2012, proved reserves from these properties were 15.5 Bcfe, of which 90% was oil or NGLs. Additionally, we hold assets within the Greater Green River Basin prospective for natural gas. We have approximately 39,514 net acres located in northwest Colorado and southern Wyoming. No proved reserves are currently recognized in this area.

OIL AND NATURAL GAS RESERVES
Our proved reserve estimates and related disclosures for 2012, 2011 and 2010 are presented in compliance with SEC rules and regulations. The information with respect to our proved reserves and related disclosures has been prepared by Schlumberger PetroTechnical Services (“Schlumberger”) and LaRoche Petroleum Consultants, Ltd. (“LaRoche”), our independent reserve engineers for U.S. and Canada, respectively.
The process of estimating our proved reserves is complex. In order to prepare these estimates, we have developed, maintained and monitored internal processes and controls for estimating and recording proved reserves in compliance with the rules and regulations of the SEC. Compliance with 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 - Chief Reservoir Engineer, is responsible for the preparation and maintenance of our engineering data and review of our proved reserve estimates with Schlumberger and LaRoche. Mr. 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 in 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 over 40 years of engineering experience in the oil and gas industry. Mr. Daniel earned a Bachelor of Science degree in Petroleum Engineering from University of Texas and has prepared reserves estimates for his employers throughout his career. He has prepared and overseen preparation of reports for public filings for LaRoche for the past 16 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 repeatability. Proved developed reserves are expected to be recovered


10


through existing wells with existing equipment and operating methods. Proved undeveloped reserves are expected to be recovered from new wells on undrilled acreage. Proved reserves for undrilled wells are estimated only where it can be demonstrated that there is continuity of production from the existing productive formation. To achieve reasonable certainty of our proved reserve estimates, our reservoir engineering team assumes continued use of technologies with demonstrated success of yielding expected results, including the use of drilling results, well performance, well logs, seismic data, geologic maps, well stimulation techniques, well test data, and reservoir simulation modeling.
The proved reserve data we disclose are estimates and are subject to inherent uncertainties. The determination of our proved reserves is based on estimates that are highly complex and interpretive. Reserve engineering is a subjective process that depends upon the quality of available data and on engineering and geological interpretation and judgment. Although we believe our proved reserve estimates are reasonable, reserve estimates are imprecise and are expected to change as additional information becomes available. Additional information regarding risks associated with estimating our proved reserves may be found in Item 1A of this Annual Report.
The following table summarizes our proved reserves.
 
Proved Developed Reserves
 
Proved Undeveloped Reserves
 
Total Proved Reserves
 
For the Years Ended December 31,
 
For the Years Ended December 31,
 
For the Years Ended December 31,
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
Natural gas (MMcf)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
725,361

 
1,244,187

 
1,312,777

 
122,687

 
584,717

 
628,946

 
848,048

 
1,828,904

 
1,941,723

Canada
266,783

 
299,371

 
242,941

 

 
31,260

 
22,947

 
266,783

 
330,631

 
265,888

Total
992,144

 
1,543,558

 
1,555,718

 
122,687

 
615,977

 
651,893

 
1,114,831

 
2,159,535

 
2,207,611

NGL (MBbl)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
47,284

 
60,902

 
64,908

 
8,890

 
41,243

 
47,536

 
56,174

 
102,145

 
112,444

Canada
10

 
11

 
12

 

 

 

 
10

 
11

 
12

Total
47,294

 
60,913

 
64,920

 
8,890

 
41,243

 
47,536

 
56,184

 
102,156

 
112,456

Oil (MBbl)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
2,416

 
2,545

 
2,775

 
113

 
490

 
533

 
2,529

 
3,035

 
3,308

Canada

 

 

 

 

 

 

 

 

Total
2,416

 
2,545

 
2,775

 
113

 
490

 
533

 
2,529

 
3,035

 
3,308

Total (MMcfe)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
1,023,562

 
1,624,866

 
1,718,875

 
176,703

 
835,118

 
917,357

 
1,200,265

 
2,459,984

 
2,636,232

Canada
266,845

 
299,437

 
243,017

 

 
31,260

 
22,947

 
266,845

 
330,697

 
265,964

Total
1,290,407

 
1,924,303

 
1,961,892

 
176,703

 
866,378

 
940,304

 
1,467,110

 
2,790,681

 
2,902,196


 
Years Ended December 31,
 
2012
 
2011
 
2010
Representative prices for reserve estimation purposes:
 
 
 
 
 
Natural gas – Henry Hub, per MMBtu
$
2.76

 
$
4.12

 
$
4.38

Natural gas – AECO, per MMBtu
2.35

 
3.65

 
4.08

Oil – WTI Cushing, per Bbl
94.71

 
95.71

 
79.43

Standardized measure of discounted future net
 cash flows (1) (in millions)
$
715.1

 
$
1,734.9

 
$
1,786.4

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

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


11


PROVED UNDEVELOPED RESERVES
Our 2012 drilling and completion activities related to our proved undeveloped locations as of December 31, 2011 were as follows:
 
 
For the Year Ended December 31, 2012
 
Drilled
 
Completed
 
Producing
 
Gross  
 
Net  
 
Gross  
 
Net  
 
Gross  
 
Net  
Barnett Shale
19.0

 
17.5

 
13.0

 
11.8

 
13.0

 
11.8

Horn River
2.0

 
2.0

 
2.0

 
2.0

 
2.0

 
2.0

Total
21.0

 
19.5

 
15.0

 
13.8

 
15.0

 
13.8


Costs incurred in 2012 relating to the drilling and completion activities related to our proved undeveloped locations as of December 31, 2011 were $61.9 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 $2.5 million depending on factors such as the area, the depth and lateral length of each well, number of stages of fracture stimulation and its distance to central facilities. On each multi-well drilling pad, we drill all the wells prior to initiation of completion activities. As a result, we maintain an inventory of drilled wells awaiting completion.
The following table summarizes our proved undeveloped reserves activity during the year ended December 31, 2012 (in Mmcfe):
Beginning proved undeveloped reserves
866,378

Extensions and discoveries
42,518

Transfers to proved developed
(96,263
)
Revisions of previous estimates
(635,930
)
Ending proved undeveloped reserves
176,703

Proved undeveloped reserves decreased approximately 580 Mmcfe primarily because we reduced our multi-year drilling program as a result of economic conditions, which introduced the effects of the five-year limitation on undeveloped wells primarily in our Barnett Shale Asset. Transfers to proved developed reserves of 73 Bcfe and 23 Bcfe occurred in our Barnett Shale Asset and Horn River Asset, respectively.
As of December 31, 2012, we had total proved undeveloped reserves of 176.7 Bcfe in our Barnett Shale Asset on 60 well locations, all of which are scheduled for development before the end of 2017.
We estimate that our proved undeveloped well locations will be developed on the following timeline:
2013
5

2014
34

2015
13

2016
5

2017
3

Total
60


During 2013, we expect to spend $6.5 million to drill, complete and tie-in wells on proved locations. Estimated future development costs on proved locations as of December 31, 2012 are projected to be $82.2 million for 2014, $38.5 million for 2015, $17.3 million for 2016, and $12.4 million for 2017.
At December 31, 2012, none of our inventory of proved undeveloped drilling locations has been recognized as proved reserves for five years or longer.
DEVELOPMENT AND EXPLORATION ACTIVITIES AT YEAR END
At December 31, 2012, we had no drilling rigs operating in our Barnett Shale Asset and no completion work was in progress. In the U.S. we had 29 (27.2 net) wells awaiting completion or tie-in to sales lines.


12


No drilling rigs were operating in our Horn River Asset at December 31, 2012. There are currently 6 (6.0 net) wells drilled and awaiting completion that have no proved reserves assigned. These wells were drilled to preserve acreage and will not be completed until the gathering infrastructure is extended into these areas. Additionally, 129 (100.3 net) wells in our Horseshoe Canyon Asset were awaiting completion or tie-in to sales lines at December 31, 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,
 
2012
 
2011
 
2010
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development:
 
 
 
 
 
 
 
 
 
 
 
U.S.
 
 
 
 
 
 
 
 
 
 
 
Productive (1)
22

 
20.5

 
61

 
49.6

 
97

 
80.5

Non-productive

 

 

 

 
2

 
1.5

Canada
 
 
 
 
 
 
 
 
 
 
 
Productive (2)
2

 
2.0

 
18

 
14.9

 
18

 
9.9

Non-productive

 

 

 

 

 

Total
24

 
22.5

 
79

 
64.5

 
117

 
91.9

Exploratory:
 
 
 
 
 
 
 
 
 
 
 
U.S.
 
 
 
 
 
 
 
 
 
 
 
Productive
8

 
5.7

 
8

 
6.0

 

 

Non-productive

 

 

 

 

 

Canada
 
 
 
 
 
 
 
 
 
 
 
Productive
2

 
2.0

 
4

 
4.0

 
2

 
2.0

Non-productive

 

 

 

 

 

Total
10

 
7.7

 
12

 
10.0

 
2

 
2.0

Total:
 
 
 
 
 
 
 
 
 
 
 
Productive
34

 
30.2

 
91

 
74.5

 
117

 
92.4

Non-productive

 

 

 

 
2

 
1.5

Total
34

 
30.2

 
91

 
74.5

 
119

 
93.9

(1)
U.S. development drilling includes non-operated drilling of 2 wells (0.0 net), 4 wells (0.0 net) and 3 wells (0.4 net) for 2012, 2011 and 2010, respectively.
(2)
Canadian development drilling includes non-operated drilling of 2 wells (1.0 net) and 7 wells (0.4 net) for 2011 and 2010, 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. We will fund any shortfall with cash which could be between $5 million and $10 million in 2013 depending on the timing of the commissioning of the third-party gas treating facility and our production levels.


13


Our prospective obligations under existing agreements are summarized below:
 
Total
 
2013
 
2014
 
2015
 
2016
 
2017
 
Thereafter
 
 
 
 
 
 
 
(In Mmcfe)
 
 
 
 
 
 
Gathering
 
 
 
 
 
 
 
 
 
 
 
 
 
Barnett Shale
29,650

 
9,125

 
9,125

 
9,125

 
2,275

 

 

Horn River
1,066,728

 
73,427

 
77,491

 
73,545

 
163,416

 
162,970

 
515,879

Processing, Treating and Fractionation
 
 
 
 
 
 
 
 
 
 
 
 
 
Barnett Shale
39,420

 
39,420

 

 

 

 

 

Horn River
194,460

 
34,000

 
37,045

 
37,045

 
37,146

 
37,045

 
12,179

Transportation
 
 
 
 
 
 
 
 
 
 
 
 
 
Barnett Shale
465,737

 
102,507

 
82,467

 
80,607

 
73,813

 
71,296

 
55,047

Horseshoe Canyon
16,608

 
11,996

 
3,861

 
738

 
13

 

 

Horn River
1,104,297

 
16,315

 
19,862

 
35,177

 
56,553

 
41,265

 
935,125


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 $0.71 to $0.87 per Mcf of gathered volume, subject to annual inflationary increases. Processing fees are fixed at $0.70 per Mcf, and are also subject to annual inflationary increases. We are not obligated to guarantee CMLP any minimum volume (accordingly the above table of commitments does not include amounts which flow to CMLP).
We sell natural gas, NGLs and oil to a variety of customers, including utilities, major oil and natural gas companies or their affiliates, industrial companies, large trading and energy marketing companies and other users of petroleum products. Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. Accordingly, the loss of any single purchaser would not materially affect our revenue. During 2012, Targa Liquids Marketing and Trade and Lone Star NGL Product Services LLC, the largest purchasers of our production, accounted for 21% and 15%, respectively, of our cash collected for natural gas, NGL and oil sales.

ACQUISITION, EXPLORATION AND DEVELOPMENT CAPITAL EXPENDITURES
The following table summarizes our acquisition, exploration and development costs incurred:
 
 
U.S.
 
Canada
 
Consolidated
 
 
 
 
 
 
 
(In thousands)
2012
 
 
 
 
 
Proved acreage
$

 
$

 
$

Unproved acreage
23,711

 
5,612

 
29,323

Development costs
131,926

 
178,808

 
310,734

Exploration costs
35,244

 
8,304

 
43,548

Total
$
190,881

 
$
192,724

 
$
383,605

2011
 
 
 
 
 
Proved acreage
$

 
$

 
$

Unproved acreage
145,099

 

 
145,099

Development costs
304,373

 
90,361

 
394,734

Exploration costs
37,673

 
41,338

 
79,011

Total
$
487,145

 
$
131,699

 
$
618,844

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



14


PRODUCTIVE OIL AND GAS WELLS
The following table summarizes productive wells:
 
 
As of December 31, 2012
 
Natural Gas
 
Oil
 
Gross
 
Net
 
Gross
 
Net
U.S.
1,031

 
839.2

 
220

 
210.9

Canada
2,884

 
1,411.1

 
4

 
1.1

Total
3,915

 
2,250.3

 
224

 
212.0


OIL AND GAS ACREAGE
Our principal oil and gas properties consist of non-producing and producing oil and gas leases and mineral acreage, including reserves of natural gas and oil in place. Developed acres are defined as acreage allocated to wells that are producing or capable of producing. Undeveloped acres are acres on which wells are not to a point that would permit the production of commercial reserves or acreage which has not yet been allocated to any wells, regardless of whether such acreage contains proved reserves. Gross acres are the total number of acres in which we have a working interest. Net acres are the sum of our fractional interests owned in the gross acres.
The following table indicates our interest in developed and undeveloped acreage:
 
 
As of December 31, 2012
 
Developed Acreage
 
Undeveloped Acreage
 
Gross
 
Net
 
Gross
 
Net
Barnett Shale
86,188

 
76,109

 
69,365

 
50,982

West Texas (1)
2,712

 
2,513

 
216,621

 
162,699

Niobrara
6,259

 
2,327

 
449,666

 
164,691

Other U.S.
120,264

 
109,370

 
114,046

 
91,958

U.S.
215,423

 
190,319

 
849,698

 
470,330

Horseshoe Canyon
459,721

 
282,728

 
40,526

 
30,116

Horn River Basin
12,864

 
12,246

 
127,556

 
116,863

Canada
472,585

 
294,974

 
168,082

 
146,979

Total
688,008

 
485,293

 
1,017,780

 
617,309

(1) 
Includes 77,194 gross (41,115 net) undeveloped acres located in Presidio County which we believe is not prospective for the Bone Springs or Wolfcamp formations.
The following table summarizes information regarding the total number of net undeveloped acres as of December 31, 2012:
 
 
 
2013 Expirations
 
2014 Expirations
 
2015 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
50,982

 
7,502

 
102

 
5,899

 
426

 
5,237

 
523

West Texas
162,699

 
5,459

 

 
64,325

 
38,598

 
48,702

 
4,516

Niobrara
164,691

 
60,157

 
15,776

 
38,718

 
28,429

 
24,010

 
5,669

Other U.S.
91,958

 
12,723

 

 
15,036

 

 
3,352

 

Canada
146,979

 
6,997

 
386

 
4,258

 

 
3,063

 

Total
617,309

 
92,838

 
16,264

 
128,236

 
67,453

 
84,364

 
10,708


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



15


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.
SAFETY REGULATION
We are subject to a number of federal, state, provincial and local laws and regulations, whose purpose is to protect the health and safety of workers, both generally and within our industry. Regulations overseen by OSHA, the EPA, Human Resources and Skills Development Canada, Environment Canada and other agencies require, among other matters, that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We are also subject to safety regulations which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.
ENVIRONMENTAL MATTERS
We are subject to stringent and complex federal, state, provincial and local environmental laws, regulations and permits, including those relating to the generation, storage, handling, use, disposal, gathering, transmission and remediation of natural gas, NGLs, oil and hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife, habitat, water and wetlands protection; the storage, use, treatment and disposal of water, including processed water; and the placement, operation and reclamation of wells. In particular, many of these requirements are intended to help preserve water resources and regulate those aspects of our operations that could potentially impact surface water or groundwater. If we violate these requirements, or fail to obtain and maintain the necessary permits, we could be subject to sanctions, including the imposition of fines and penalties, as well as potential orders enjoining future operations or delays or other impediments in obtaining or renewing permits. Pursuant to such laws, regulations and permits, we may be subject to operational restrictions and have made and expect to continue to make capital and other compliance expenditures.
We could be liable for any environmental contamination at our or our predecessors' currently or formerly owned, leased or operated properties or third-party waste disposal sites. Certain environmental laws, including CERCLA, more commonly known as Superfund, impose joint and several strict liability for releases of hazardous substances at such properties or sites, without regard to fault or the legality of the original conduct. In addition to potentially significant investigation and remediation costs, environmental contamination can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.
Environmental laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. For example, various federal, state, provincial and local initiatives have been implemented or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. In particular, the EPA has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of wastewater from certain gas production operations. In addition, certain states and Canadian provinces in which we operate, including Colorado, Montana, Texas, Wyoming, British Columbia and Alberta, have adopted, or are considering adopting, regulations that have imposed, or could impose, more stringent permitting, transparency, disposal and well construction requirements. States and Canadian provinces in which we operate, including Texas, Colorado, Montana, Wyoming and British Columbia require public disclosure of chemicals in fluids used in the hydraulic fracturing process. Local ordinances or other regulations also may regulate, restrict or prohibit the performance of well drilling in general and hydraulic fracturing in particular, and may require baseline water well sampling. In October 2012, the Colorado Oil and Gas Conservation Commission proposed a requirement to conduct


16


baseline water quality sampling prior to and following certain drilling operations. 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. This increased scrutiny has led to heightened enforcement of existing regulations as well as the imposition of new air emission measures. In April 2012, the EPA issued new 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.
Greenhouse gas (“GHG”) emission regulation is also becoming more stringent. We are currently required to implement a GHG recordkeeping and reporting program due to issuance of the EPA's subpart W regulation, which requires significant effort to quantify sources at all of our production sites and requires us to report our GHG emissions from operations. Our operations in British Columbia are subject to similar GHG reporting requirements. In addition, regulatory authorities are considering, or have developed, energy or emission measures to reduce GHG emissions. For example, the EPA has begun regulating GHG emissions from stationary sources pursuant to the Prevention of Significant Deterioration and Title V provisions of the federal Clean Air Act, as a result of which we might be required to obtain permits to construct, modify or operate facilities on account of, and implement emission control measures for, our GHG emissions. In British Columbia, we are subject to a carbon tax on our purchase or use of virtually all carbon-based fuels (including natural gas), which is payable at the time such fuel is purchased or otherwise used. Any limitation, or further regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could restrict our operations and subject us to significant costs, including those relating to emission credits, pollution control equipment, monitoring and reporting. Although there is still significant uncertainty surrounding the scope, timing and effect of GHG regulation, any such regulation could have a material adverse impact on our business, financial condition, reputation and operating performance.
In addition, to the extent climate change results in more severe weather, our operations may be disrupted. For example, storms in the Gulf of Mexico could damage downstream pipeline infrastructure causing a decrease in takeaway capacity and potentially requiring us to curtail production. In addition, warmer temperatures might shorten the time during the winter months when we can access certain remote production areas resulting in decreased exploration and production activity.
AVAILABILITY OF REPORTS AND CORPORATE GOVERNANCE DOCUMENTS
Our website is located at www.qrinc.com, and our investor relations website is located at investors.qrinc.com. The following filings are available through our investor relations website as soon as we electronically file or furnish such material to the SEC:
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.
All such postings and filings are available on our investor relations website free of charge. The SEC's web site, www.sec.gov, contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.
We use our investor relations website as a routine channel for distribution of important information, including news releases, analyst presentations, and financial information, as a means of disclosing material non-public information and for complying with our disclosure obligations under Regulation FD. Additionally, we provide notifications of news or announcements as part of our investor relations website. Investors and others can receive notifications of new information posted on our investor relations website in real time by signing up for email alerts and RSS feeds. Accordingly, investors should monitor this portion of our website in addition to following press releases, SEC filings and public conference calls and webcasts. Further, charters for the committees of our Board and our Corporate Governance Guidelines and Code of Business Conduct and Ethics can be found on our website under the heading “Corporate Governance.” Our website and the information contained therein or connected thereto shall not be deemed to be incorporated into this Annual Report on Form 10-K or in any other report or document we file with the SEC, and any references to our websites are intended to be inactive textual references only.
EMPLOYEES
As of February 28, 2013, we had 417 employees, none of whom have collective bargaining agreements.



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EXECUTIVE OFFICERS OF THE REGISTRANT
The following information is provided with respect to our executive officers as of February 28, 2013.
Name
 
Age
 
Position(s)
Thomas F. Darden
 
59
 
Director, Chairman of the Board
Glenn Darden
 
57
 
Director, President and Chief Executive Officer
Anne Darden Self
 
55
 
Director, Vice President - Human Resources
John C. Cirone
 
63
 
Executive Vice President, General Counsel and Secretary
John C. Regan
 
43
 
Senior Vice President - Chief Financial Officer and Chief Accounting Officer
Stan Page
 
55
 
Senior Vice President - U.S. Operations
Chris M. Mundy
 
40
 
Vice President - Chief Reservoir Engineer
John D. Rushford
 
53
 
Senior Vice President and Chief Operating Officer of Quicksilver Resources Canada Inc.

Officers are elected by our Board of Directors and hold office at the pleasure of the Board until their successors are elected and qualified. Thomas F. Darden, Glenn Darden and Anne Darden Self are siblings. 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. Mr. Darden was previously employed by Mercury Exploration Company for 22 years in various executive level positions. 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.
GLENN DARDEN has served on our Board of Directors since December 1997 and became our Chief Executive Officer in December 1999. He served as our Vice President until he was elected President and Chief Operating Officer in March 1999. Prior to that time, he served with Mercury for 18 years, the last five as Executive Vice President. Mr. Darden previously worked as a geologist for Mitchell Energy Company LP (subsequently merged with Devon Energy). He served as a director of Crestwood Gas Services GP LLC, the general partner of Crestwood Gas Services LP (formerly known as Quicksilver Gas Services LP), from March 2007 to October 2010.
ANNE DARDEN SELF has served on our Board of Directors since August 1999, and became our Vice President - Human Resources in July 2000. She is also currently President of Mercury, where she has worked since 1992. From 1988 to 1991, she was employed by Banc PLUS Savings Association in Houston, Texas, initially as Marketing Director and for three years thereafter as Vice President of Human Resources. She worked from 1987 to 1988 as an Account Executive for NW Ayer Advertising Agency. Prior to 1987, she spent several years in real estate management.
JOHN C. 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 was also named as our Secretary in May 2012, and he 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.
JOHN C. REGAN became our Senior Vice President - Chief Financial Officer and Chief Accounting Officer in April 2012, after serving as our Vice President and Chief Accounting Officer since September 2007. He also served as our Controller from September 2007 to August 2012. Mr. Regan is a Certified Public Accountant with more than 20 years of combined public accounting, corporate finance and financial reporting experience. Mr. Regan joined us from Flowserve Corporation where he held various management positions of increasing responsibility from 2002 to 2007, including Vice President of Finance for the Flow Control Division and Director of Financial Reporting. He was also a senior manager specializing in the energy industry in the audit practice of PricewaterhouseCoopers LLP, where he was employed from 1994 to 2002.
STAN PAGE became our Senior Vice President - U.S. Operations in June 2010, after serving as our Vice President - U.S. Operations since October 2007. Mr. Page joined us from BP America (formerly known as Amoco Production Company) where he held various management positions of increasing responsibility from 1979 to 2007, including Operations Center Manager for East Texas Operations from 2005 to 2007.
CHRIS M. MUNDY became our Vice President - Chief Reservoir Engineer in June 2012, after serving as our Vice President - Engineering responsible for corporate reserves from August 2010 to May 2012, 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


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

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, including our financial maintenance covenants. Among other things, the amount we can borrow under our Combined Credit Agreements is subject to periodic redetermination based in part on expected future prices. Lower prices may also reduce the amount of natural gas, NGLs and oil that we can economically produce.
Prices for our production fluctuate widely, particularly as evidenced by price movements between 2008 and 2012. Among the factors that can cause these fluctuations are:
domestic and foreign demand for oil, natural gas and NGLs;
the level and locations of domestic and foreign oil and natural gas supplies;
the quality, price and availability of alternative fuels;
the quantity of natural gas in storage;
weather conditions;
domestic and foreign governmental regulations, including environmental regulations;
impact of trade organizations, such as the Organization of Petroleum Exporting Countries, or OPEC;
political conditions in oil and natural gas producing regions;
localized supply and demand fundamentals and transportation availability;
technological advances affecting energy consumption;
speculation by investors in oil and natural gas; and
worldwide economic conditions.
Due to the volatility of commodity prices and the inability to control the factors that influence them, we cannot predict future pricing levels. A decrease in commodity prices without an offsetting significant increase in production or cash received from our derivatives program could have a material adverse impact on our business activities, financial condition and results of operations.
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 present value of the estimated cash flows from the underlying oil and gas reserves discounted at 10%. We recognized impairment to the carrying value of our oil and gas properties which is discussed in Item 7 of this Annual Report. We 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 and the estimated production. Actual future production, commodity prices, revenue, taxes, development expenditures, operating expenses and our estimated quantities of recoverable proved reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of proved reserves and the estimated production presented in our filings with the SEC. In addition, we may adjust estimates of production and estimates of proved reserves to reflect production history, results of exploration and development, prevailing commodity prices and other factors that may be beyond our control.
At December 31, 2012, 12% 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 of our reserves may not occur as scheduled or actual results of that development may not be as estimated prior to drilling.
The present value of future net cash flows disclosed in Item 8 of this Annual Report is not necessarily the fair value of our proved reserves. In accordance with SEC requirements, the discounted future net cash flows from proved reserves for 2012 are based upon prices determined on an unweighted average of the preceding 12-month first-day-of-the-month prices adjusted for local differentials and operating and development costs as of period end. Actual future prices and costs may be materially higher or lower than the prices and costs used in our estimates, which are calculated in accordance with SEC requirements. Any changes in consumption by natural gas, NGL and oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the costs from the development and production of our oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is specified by the SEC for calculating discounted future net cash flows, may not reflect current conditions. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general would affect the appropriateness of the 10% discount factor in arriving at the actual fair value of our proved reserves.
All of our producing properties and operations are located in a small number of geographic areas, making us vulnerable to risks associated with operating in limited geographic areas.
Our Barnett Shale Asset, Horseshoe Canyon Asset and Horn River Asset account for 76%, 15% and 8% of our 2012 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.
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


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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 proceeds from issuances of debt and asset dispositions 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, maintain our leasehold acreage or maintain current production may be limited, resulting in decreased production and reserves over time. If our cash flow from operations is insufficient to satisfy our financing needs, we cannot be certain that additional financing will be available to us on acceptable terms or at all. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition or general economic conditions at the time of any such financing or offering. At December 31, 2012 we did not meet the interest coverage ratio related to our indentures which restricts our ability to incur additional debt although we can refinance our existing debt. We may need lender permission to access the capital markets and we may be unsuccessful in obtaining that permission. Even if we are successful in obtaining the necessary funds, the terms of such financings could have a material adverse effect on our business, results of operations and financial condition. If additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis. Drilling activity may be directed by our partners in certain areas and may result in us forfeiting acreage if we do not have sufficient capital resources to fund our portion of expenses.
Our business involves many hazards and operational risks.
Our operations are subject to many risks inherent in the oil and gas industry, including operating hazards such as well blowouts, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, treatment plant “downtime,” pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could cause us to experience substantial losses. The occurrence of a significant accident or other event could curtail our operations and have a material adverse effect on our business, financial condition and results of operations.
Liabilities and expenses not covered by our insurance could have a material adverse effect on our business, financial condition and results of operations.
As a result of operating hazards, regulatory risks and other uninsured risks, we could incur substantial liabilities to third parties or governmental entities. We maintain insurance against some, but not all, of such risks and losses in accordance with customary industry practice. We are not insured against all incidents, claims or damages that might occur, and pollution and environmental risks generally are not fully insurable. Any significant accident or event that is not insured at levels that may become payable could materially adversely affect our business, financial condition and results of operations. In addition, we may be unable to economically obtain or maintain the insurance that we desire, or may elect not to obtain or renew insurance if we believe that the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for all or some certain of our insurance policies could escalate further. In some instances, certain insurance could become unavailable or available only at reduced coverage levels. Any type of catastrophic event that is not covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
The failure to replace our proved reserves could adversely affect our business, financial condition, results of operations, production and cash flows.
Oil and gas reserves are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions or divestitures. Our proved reserves will generally decline as commodity prices decrease and as proved reserves are produced, except to the extent that we conduct successful exploration or development activities or acquire additional proved reserves. In order to maintain or increase proved reserves and production, we must continue our development drilling or undertake other replacement activities. Our planned exploration and development projects or any acquisition activities that we may undertake might not result in


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meaningful additional proved reserves, and we might not have continuing success drilling productive wells. Even in the event that our exploration and development projects do result in meaningful additional commercially viable proved reserves, midstream infrastructure for these proved reserves may not exist or may not be constructed, either of which could adversely impact our ability to benefit from those proved reserves. If our exploration and development efforts are unsuccessful, our leases covering acreage that is not already held by production could expire. If they do expire and if we are unable to renew the leases on acceptable terms, we will lose the right to conduct drilling activities and the resulting economic benefits associated therewith. If we are unable to develop or acquire additional proved reserves to replace our current and future production at economically acceptable terms, our business, financial condition and results of operations would be materially adversely affected. If we divest any of our producing assets our production and cash flows will be reduced. Drilling may occur at a rate directed by our partners in certain areas and may not be sufficient to grow production or reserves.
We cannot control the operations of gas gathering, treating, processing, liquids fractionation and transportation facilities we do not own or operate.
We deliver our production to market through gathering, treating, fractionation and transportation systems that we do not own or operate. The marketability of our production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. A portion of our production could be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, 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 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 economic hedging policy may not effectively mitigate the impact of commodity price volatility on our cash flows, and our economic hedging activities could result in losses or limit our ability to benefit from price increases. In addition, the commodity derivatives covering a significant portion our production expire in 2015 or earlier, and we may not be able to enter into commodity derivatives covering our production in future periods on favorable terms or at all.
To reduce our exposure to commodity price fluctuations, we have entered and intend to continue to enter into commodity derivatives covering our future production, which may limit the benefit we would receive from increases in commodity prices. These arrangements also expose us to risk of financial losses in some circumstances, including the following:
our production could be materially less than expected; or
the counterparties to the contracts could fail to perform their contractual obligations.
If our actual production and sales for any period are less than the production covered by commodity derivatives (including reduced production due to operational delays) or if we are unable to perform our exploration and development activities as planned, we might be required to satisfy a portion of our obligations under those commodity derivatives without the benefit of the cash flow from the sale of that production, which may materially impact our liquidity. Additionally, if market prices for our production exceed collar ceilings or swap prices, we would be required to make monthly cash payments, which could materially adversely affect our liquidity.
The price for natural gas set by our derivatives has been significantly higher than the prevailing price for natural gas over the past two years. We currently maintain a portfolio of commodity derivatives covering approximately 72% of our estimated production over the next three years. However, the commodity derivatives covering a significant portion of our production expire in 2015 or earlier, and we may not be able to enter into additional commodity derivatives covering our production in


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future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than our competitors who engage in hedging arrangements. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.
Our decision to cease accounting for our derivatives as hedges will mean that changes in their fair value will be recorded in earnings. This change, particularly on our multi-year derivatives, may create volatility to our reported earnings levels compared with our earnings had we continued to apply hedge accounting.
Delays in obtaining oil field equipment and increases in drilling and other service costs could adversely affect our ability to pursue our drilling program.
As commodity prices increase and exploration and development activity increases in established and emerging basins, demand and costs for drilling equipment, crews and associated supplies, equipment and services can increase significantly. We cannot be certain that in a higher commodity price environment we would be able to obtain necessary drilling equipment and supplies in a timely manner, on satisfactory terms or at all, and we could experience difficulty in obtaining, or there may be material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services. In addition, drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, including urban drilling, and possible title issues. As a result of increased activity levels, we have seen increases and supply limitations for the services we procure. Any such shortages or delays and price increases could adversely affect our ability to execute our drilling program.
Our activities are regulated by complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to various U.S. and Canadian federal, state, provincial and local government laws and regulations that could change in response to economic or political conditions. Matters that are typically regulated include:
discharge permits for drilling operations;
water obtained for drilling purposes;
drilling permits and bonds;
reports concerning operations;
spacing of wells;
operations and personnel safety;
waste disposal, including disposal wells;
air emissions limits and permitting;
hydraulic fracturing chemical disclosures;
unitization and pooling of properties; and
taxation.
From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity to conserve supplies of natural gas and oil. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, laws, regulations and tax requirements frequently are changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We cannot assure you that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, will not materially adversely affect our business, results of operations and financial condition.
We benefit from federal income tax provisions with respect to natural gas and oil exploration and development, and those provisions may be limited or repealed by future legislation.
The Obama administration's 2013 budget proposes to eliminate certain U.S. federal income tax benefits currently available to oil and gas exploration and production companies. These proposals include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the manufacturing deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. These changes are similar to proposals in prior years that were not enacted into law. It is unclear whether such changes will be enacted or how soon they would be effective if enacted. Enactment of these proposals or other similar changes in U.S. federal income tax law could eliminate or defer certain tax credits or deductions that are currently available with respect to our activities, and any such change could negatively affect our financial condition and results of operations. See also “-Our activities are regulated by complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.”


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We are subject to environmental laws, regulations and permits, including greenhouse gas requirements, which may expose us to significant costs, liabilities and obligations.
We are subject to stringent and complex U.S. and Canadian federal, state, provincial and local environmental laws, regulations and permits relating to, among other things, the generation, storage, handling, use, disposal, gathering, transmission and remediation of natural gas, NGLs, oil and hazardous materials; the emission and discharge of such materials to the ground, air and water; 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, including requirements to close pits. 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 and our predecessors' currently or formerly owned, leased or operated properties or third-party waste disposal sites. In addition to potentially significant investigation and remediation costs, such matters can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.
These laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. For example, federal and state regulators are becoming increasingly focused on air emissions from our industry, including volatile organic compound emissions. This increased scrutiny has led to heightened enforcement of existing regulations as well as the imposition of new air emission measures. With respect to GHG emissions, we are currently required to report annual GHG emissions from certain of our operations, and additional GHG emission related requirements have been implemented or are in various stages of development. Any current or future GHG or other air emission requirements could curtail our operations or otherwise result in operational delays, liabilities and increased compliance costs. In addition, to the extent climate change results in more severe weather, our or our customers' operations may be disrupted, which could curtail our exploration and production activity, increase operating costs and reduce product demand.
Our costs, liabilities and obligations relating to environmental matters could have a material adverse effect on our business, reputation, results of operations and financial condition.
Our hydraulic fracturing operations are subject to laws and regulations that could expose us to increased costs and additional operating restrictions and delays, and adversely affect production.
We rely and expect to continue to rely upon hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. Various federal, state, provincial and local initiatives have been implemented or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing. In particular, the EPA has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of wastewater from certain gas production operations. In April 2012, the EPA issued new air standards that require measures to reduce volatile organic compound emissions at new hydraulically fractured natural gas wells and existing wells that are re-fractured. Certain municipalities and states and Canadian provinces in which we operate, including Texas, Colorado, Montana, Wyoming, British Columbia and Alberta, have adopted, or are considering adopting, regulations that have imposed, or could impose, more stringent permitting, transparency, disposal and well construction requirements on hydraulic fracturing operations. For example the Railroad Commission of Texas and the Colorado Oil and Gas Conservation Commission require public disclosure of chemicals in fluids used in the hydraulic fracturing process. Similar regulations exist in British Columbia and Alberta. Local ordinances or other regulations also may regulate, restrict or prohibit the performance of well drilling in general and hydraulic fracturing in particular. In October 2012, the Colorado Oil and Gas Conservation Commission proposed a requirement to conduct baseline water quality sampling prior to and following certain drilling operations. Such laws and regulations may result in increased scrutiny or third-party claims, or otherwise result in operational delays, liabilities and increased costs. Baseline water sampling and studies are a regulatory requirement in British Columbia and Alberta.
Hydraulic fracturing can require significant quantities of water. Recently, Texas and northeastern British Columbia have been experiencing drought conditions. 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.


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The risks associated with our debt could adversely affect our business, financial condition and results of operations, and could cause our securityholders to experience a partial or total loss of their investment in us.
Subject to the limits and conditions contained in our various debt agreements, we may incur additional debt. Our ability to incur additional debt and to comply with the terms of our debt agreements is affected by a variety of factors, including commodity prices and their effects on the value of our proved reserves, financial condition, results of operations and cash flows. In addition, we expect our ability to borrow under our Combined Credit Agreements will depend on our borrowing base, which will be redetermined periodically and 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. The semi-annual redetermination of the Combined Credit Agreements is scheduled for April 2013. We expect a reduction in the borrowing base from $850 million to approximately $550 million. As of February 28, 2013 we had approximately $490 million outstanding under our Combined Credit Agreements, including letters of credit. While we believe that the remaining availability of approximately $60 million together with operating cash flow will be adequate to meet our liquidity needs for the remainder of 2013, the borrowing base could be reduced below $550 million during the April or autumn redetermination and that amount may be insufficient to meet our liquidity needs. 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 materially adverse effects on our business and on the value of our securities. For example, the provisions of our outstanding debt could:
make it more difficult for us to satisfy our obligations with respect to our debt;
require us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing the amount of our cash flow available for working capital, capital expenditures, acquisitions and other general corporate purposes;
require us to make principal payments if the quantity and value of our proved reserves are insufficient to support our level of borrowings;
limit our flexibility in planning for, or reacting to, changes in the oil and gas industry;
place us at a competitive disadvantage compared to our competitors who may have lower debt service obligations and greater financing flexibility than we do;
limit our financial flexibility, including our ability to borrow additional funds;
increase our interest expense on our variable rate borrowings if interest rates increase;
limit our ability to make capital expenditures to develop our properties;
increase our vulnerability to exchange risk associated with Canadian dollar denominated indebtedness;
increase our vulnerability to general adverse economic and industry conditions; and
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:
reducing or delaying capital expenditures;
seeking additional debt financing or equity capital;
selling assets;
restructuring or refinancing debt; or
reorganizing our capital structure.
We may be unable to implement any of these strategies on satisfactory terms, or at all, and our inability to do so could cause our securityholders to experience a partial or total loss of their investment in us.
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:
incur additional debt;
pay dividends on, or redeem or repurchase capital stock;
make certain investments;
incur or permit certain liens to exist;
enter into certain types of transactions with affiliates;
merge, consolidate or amalgamate with another company;


25


transfer or otherwise dispose of assets, including capital stock of subsidiaries; and
redeem subordinated debt.
Our debt agreements, among other things, require the maintenance of and compliance with financial and other 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. While we believe that we will be able to comply with these covenants through the end of 2013, we do not expect to exceed the required levels by a significant margin. Accordingly, even a modest decline in prices for natural gas and NGLs, our failure to achieve anticipated cost savings or the inaccuracy in any material respect of any of the other assumptions underlying our forecast could cause us to fail to comply with the covenants contained in the Combined Credit Agreements. In addition, absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing or significant reductions to our operating costs, we expect to need to seek additional covenant relief under the Combined Credit Agreements for 2014.
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 and our business, financial condition and results of operations could be adversely affected.
Parties with whom we do business may become unable or unwilling to timely perform their obligations to us.
We enter into contracts and transactions with various third parties, including contractors, suppliers, customers, lenders, joint venture and other partners, and counterparties to hedging arrangements, under which such third parties incur performance or payment obligations to us. Any delay or failure on the part of one or more of such third parties to perform their obligations to us could, depending upon the nature and magnitude of such failure or failures, have a material adverse effect on our business, financial condition and results of operations.
The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state, provincial and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations.
We have substantial financial and other commitments related to our development of a gathering, processing and transportation system for Horn River.
We agreed to provide NGTL with financial assurance in the form of a letter of credit to cover its costs related to the Komie North Project under our current agreement with NGTL which we expect may be amended based on the report of the NEB recommending against approval of the Komie North Project. Our financial exposure is staged in increments as the project is built and ultimately, the costs for the project could be C$296.8 million, including taxes, although we expect our exposure to be much lower if other producers commit to the project. 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 104.8 Bcfe of proved reserves in our Horn River Asset as of December 31, 2012. 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.
Upon formation of Fortune Creek, we committed to drilling and completion activities in our Horn River Asset through 2014, which are detailed in Note 16 to the consolidating financial statements included in Item 8 of this Annual Report. If we do


26


not incur these capital expenditures or are unable to negotiate a deferral of this commitment we may be subject to a penalty payment.
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, 2012, we had 60 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 commercially viable quantities of oil or natural gas from these or any other potential drilling locations. The failure to drill our identified drilling locations on a timely basis or the failure of our drilling locations to yield oil or natural gas in commercially viable quantities could cause a decline in our proved reserves and adversely affect our ability to maintain leases, borrowing capacity, financial condition, results of operations and cash flows.
Many of our properties are in areas that may 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 or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling additional wells, that could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expense and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
We have multiple assets in early stages of development which have limited infrastructure.
Our Horn River Asset, West Texas Asset and Niobrara Asset are at early stages of development. As such, there is limited information on reservoir quality which may affect the development schedule and well spacing requirements to fully recover the natural gas reserves. Additionally, the infrastructure is still in development, 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 located within the Treaty 8 settlement negotiated between the Federal Crown and First Nations and is subject to aboriginal rights associated with traditional use of the lands that could potentially impact our ability to develop and produce our mineral rights. We are not aware that any claims have been made against us in respect of our properties and assets in connection with aboriginal rights; however, if a claim arose and was successful, such claim may have a material adverse effect on our business, financial condition and results of operations. In addition, prior to making decisions that may adversely affect existing or claimed aboriginal rights, governments in Canada have a duty to consult with aboriginal people potentially affected, and in some instances, a duty to accommodate concerns raised through such consultation. Regulatory authorizations for our operations may be affected by the time required for the completion of aboriginal consultation, and operational restrictions imposed by governmental authorities pursuant to such consultation may materially affect our business, financial condition and results of operations.


27


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.
Derivatives regulations adopted under the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, could have an adverse effect on our ability to use derivatives to reduce the effect of commodity price risk, interest rate and other risks associated with our business.
We use commodity derivatives to manage our commodity price risk. In 2010, the U.S. Congress adopted comprehensive financial reform legislation that, among other things, establishes comprehensive federal oversight and regulation of over-the-counter derivatives, termed “swaps” and “security-based swaps” by the Dodd-Frank Act, and many of the entities that participate in the swaps markets. The Commodity Futures Trading Commission (the “CFTC”) and the SEC, along with certain other regulators, must promulgate final rules and regulations to implement many of the Dodd-Frank Act swap regulatory provisions. The CFTC was given regulatory authority over swaps, which includes commodity swaps. The CFTC has finalized many, but not all, of its rules. The SEC's rules governing security-based swaps have largely not been finalized. As a result, the final form and timing of the implementation of the new swap regulatory regime affecting commodity derivatives remains uncertain.
In particular, the Dodd-Frank Act provides the CFTC with authority to adopt position limits for swaps. In 2011, the CFTC adopted a swap position limits rule, however, that rule was vacated by the U.S. District Court for the District of Columbia under a lawsuit brought by the financial services industry organizations. The CFTC has filed an appeal of the District Court's decisions with the U.S. Court of Appeals for the District of Columbia Circuit, which has not yet ruled on the appeal. It also is expected that the CFTC will revise and re-adopt position limit rules, which are expected to include position limits on commodity swaps. While the timing of implementation of 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, when in place, position limit rules will not have a material adverse impact on us by affecting the prices of or market for commodities relevant to our operations and/or by reducing the availability to us of commodity derivatives.
The Dodd-Frank Act will also impose a number of other new requirements on swap transactions and subject 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, all of which may have a material adverse effect on us. 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 the Dodd-Frank Act, swap dealers and major swap participants will be required to collect initial and variation margin from certain end-users of swaps. The rules implementing many of these requirements have not all 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, which could cause liquidity issues for us by reducing our ability to use our cash or other assets for capital expenditures or other corporate purposes and reduce our ability to execute strategic hedges to reduce commodity price uncertainty and protect cash flows.
If we reduce our use of derivatives as a result of the Dodd-Frank Act, the regulations promulgated under it and the changes to the nature of the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. In addition, the Dodd-Frank Act was intended, in part, to reduce the volatility of commodity prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to natural gas, NGLs and oil. Our revenue could, therefore, be adversely affected if commodity prices were to decrease.
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.


28


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 28, 2013, members of the Darden family, together with entities controlled by them, beneficially owned approximately 30% of our outstanding common stock. As a result, they are generally able to significantly affect the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our charter or bylaws and the approval of mergers and other significant corporate transactions.
Our amended and restated certificate of incorporation, restated bylaws and stockholder rights plan contain provisions that could discourage an acquisition or change of control without our board of directors' approval.
Our amended and restated certificate of incorporation and restated bylaws contain provisions that could discourage an acquisition or change of control without our board of directors' approval. In this regard:
our board of directors is authorized to issue preferred stock without stockholder approval;
our board of directors is classified; and
advance notice is required for director nominations by stockholders and actions to be taken at annual meetings at the request of stockholders.
In addition, we have amended and extended a stockholder rights plan, which could also impede a merger, consolidation, takeover or other business combination involving us, even if that change of control might be beneficial to stockholders, thus increasing the likelihood that incumbent directors will retain their positions. In 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 further delayed or not completed, our stock price may decline and our growth potential may not be enhanced.
In 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”). In February 2012, we 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 securities may change materially from those anticipated, including the effects of our current joint venture marketing process. If the MLP transaction is not completed or is 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.
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 material weaknesses in our internal controls that, if not properly corrected, could result in material misstatements in our financial statements.
We have identified two material weaknesses in our system of internal control over financial reporting as of December 31, 2012. A material weakness is a deficiency, or combination of deficiencies in internal controls over financial reporting that results in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.
We did not maintain operating effectiveness of our controls over the documentation in 2012 for derivatives that had fair value at the designation date. Our controls failed to detect that, for contracts designated as hedges that had a fair value on the date of designation, there were undocumented potential sources of ineffectiveness. Specifically, our documentation did not include an assessment of whether interest rate changes could cause the derivatives to not be effective over their lives, which is required due to the presence of fair value on the designation date. Effective December 31, 2012, management discontinued the use of hedge accounting on all derivative contracts and does not expect the material weakness associated with hedge accounting


29


to recur. If, in the future, we were to begin to designate our derivatives as hedges we would need to enhance our controls regarding consideration of all sources of ineffectiveness.
We also had a material weakness related to the operating effectiveness of controls over deferred income taxes. We had difficulty in preparing a timely reconciliation of certain temporary differences, particularly related to the tax basis in property, plant and equipment, from our provision to our tax returns and our tax subledger. The Company is in the process of implementing system and procedural changes to prevent these issues from recurring in 2013. These issues were exacerbated by turnover within the tax department in 2012 and 2013, and the Company is in the process of evaluating its resource needs in this area.
A significant deficiency as of December 31, 2012 relates to the operating effectiveness of our controls for our calculation of the asset retirement obligation for our Canadian assets. In response, management has enhanced its controls in this area and believes that these enhancements, when repeated as applicable in future periods, will remediate the matter.
If we are not able to remedy the control deficiencies in a timely manner, we may be unable to provide holders of our securities with the required financial information in a timely and reliable manner, either of which could subject us to litigation and regulatory enforcement actions.
ITEM 1B.
Unresolved Staff Comments
None.
 
ITEM 2.
Properties
A detailed description of our significant properties and associated 2012 developments can be found in Item 1 of this Annual Report, which is incorporated herein by reference.
 
ITEM 3.
Legal Proceedings
On December 18, 2012, Vantage Fort Worth Energy LLC (“Vantage”) served a lawsuit against us and others in the 352nd Judicial District Court of Texas in Tarrant County, Texas asserting claims for trespass to try title, suit to quiet title, trespass and conversion in connection with 16 wells located on a 158.75 acre tract in Tarrant County, Texas. They seek declaratory and injunctive relief, an accounting and an unspecified amount of actual damages, interest and court costs. We filed our answer on January 14, 2013. On January 28, 2013, Vantage filed its Motion for Non-suit with respect to certain defendants and First Amended Petition. Vantage's current complaint also seeks an unspecified amount of actual damages, interest and costs. We plan a vigorous defense in this matter.
 
ITEM 4.
Mine Safety Disclosures
Not applicable.



30


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  
2012
 
 
 
Fourth Quarter
$
4.96

 
$
2.62

Third Quarter
5.97

 
3.28

Second Quarter
5.65

 
2.93

First Quarter
7.18

 
4.14

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


As of February 28, 2013, there were approximately 660 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”) and the Standard & Poor’s 400 Oil and Gas Index (the “S&P 400 Oil & Gas Index”) for the period from December 31, 2007 to December 31, 2012, assuming an initial investment of $100 and the reinvestment of all dividends, if any.
Comparison of Cumulative Five Year Total Return


31


Issuer Purchases of Equity Securities
The following table summarizes our repurchases of Quicksilver common stock during the quarter ended December 31, 2012.
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 2012
 
1,323

 
$
4.19

 

 

November 2012
 
103,486

 
$
3.17

 

 

December 2012
 

 

 

 

Total
 
104,809

 
$
3.18

 

 


(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.




32


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,
 
      2012 (1) 
 
      2011 (2) 
 
   2010 (3)
 
      2009 (4) 
 
      2008 (5) 
 
 
 
 
 
 
 
 
 
 
 
(In thousands, except for per share data)
Operating Results Information
 
 
 
 
 
 
 
 
 
Total revenue
$
709,038

 
$
943,623

 
$
928,331

 
$
832,735

 
$
800,641

Operating income (loss)
(2,465,761
)
 
122,604

 
804,134

 
(613,873
)
 
(249,697
)
Income (loss) before income taxes
(2,648,176
)
 
147,909

 
713,828

 
(836,856
)
 
(585,077
)
Net income (loss)
(2,352,606
)
 
90,046

 
455,290

 
(545,239
)
 
(373,622
)
Net income (loss) attributable to Quicksilver
(2,352,606
)
 
90,046

 
445,566

 
(557,473
)
 
(378,276
)
Diluted earnings (loss) per common share
$
(13.83
)
 
$
0.52

 
$
2.50

 
$
(3.30
)
 
$
(2.33
)
Dividends paid per share

 

 

 

 

Financial Condition Information
 
 
 
 
 
 
 
 
 
Property, plant and equipment - net
$
1,029,058

 
$
3,460,519

 
$
3,063,245

 
$
2,542,845

 
$
3,298,830

Midstream assets held for sale - net

 

 
27,178

 
548,508

 
492,733

Total assets
1,381,788

 
3,995,462

 
3,507,734

 
3,612,882

 
4,498,208

Long-term debt
2,063,206

 
1,903,431

 
1,746,716

 
2,427,523

 
2,586,045

All other long-term obligations
283,588

 
495,939

 
248,762

 
121,877

 
282,101

Total equity
(1,132,797
)
 
1,261,919

 
1,069,905

 
696,822

 
1,211,563

Cash Flow Information
 
 
 
 
 
 
 
 
 
Cash provided by operating activities
$
227,727

 
$
253,053

 
$
397,720

 
$
612,240

 
$
456,566

Capital expenditures
485,479

 
690,607

 
695,114

 
693,838

 
1,286,715

 
(1) 
Operating loss for 2012 includes charges for impairment of $2.6 billion for certain midstream assets in Colorado and U.S. and Canadian oil and gas properties. Net loss includes a tax valuation allowance of $595.3 million.
(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 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.




33


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.
Our MD&A includes the following sections:
Overview of quarter restatement – a description of the restatement of our historical quarterly financial statements
Overview – a general description of our business; the value drivers of our business; and key indicators
2012 Highlights – a summary of significant activities and events affecting Quicksilver
2013 Capital Program – a summary of our planned capital expenditures during 2013
Financial Risk Management – information about debt financing and financial risk management
Results of Operations – an analysis of our consolidated results of operations for the three years presented in our financial statements
Liquidity, Capital Resources and Financial Position – an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments
Critical Accounting Estimates – a discussion of critical accounting estimates that represent choices between acceptable alternatives and/or require management judgments and assumptions.

OVERVIEW OF QUARTER RESTATEMENT
As part of our year-end 2012 procedures, we concluded that the documentation for our derivatives designated during 2012 that had fair value on the dates they were initially designated as hedges failed to give consideration to all sources of ineffectiveness. Specifically, our documentation did not include an assessment of whether interest rate changes could cause the instruments to not be effective over the life of the contract, which was required given the presence of fair value at the date of hedge designation. Management had documented its assessment of interest rate risk in 2011 on similar derivatives and concluded its effect to be immaterial and, thus, did not document the risk in 2012. Accordingly, these derivatives did not qualify for hedge accounting in 2012 and their changes in value must be recognized in earnings.
Because the derivatives did not qualify for hedge accounting, their inclusion in the U.S. and Canadian full cost ceiling was inappropriate. Thus, our full cost ceiling calculations were revised and resulted in restatements to impairment expense recognized in earlier quarters. Also, we determined that the deferred taxes used in our Canadian ceiling test for the first two quarters of 2012 included temporary differences for non-property related items. We have restated the ceiling impairments from the interim quarters to correct for these inclusions. The impairment expense that resulted from the ceiling calculation restatements also caused reductions to our depletion rates for the quarters and we have restated depletion expense. Income taxes have also been restated for each of the 2012 quarters to reflect the foregoing restated items.
The following table and subsequent section discuss the effect of the restatement for impacted line items on the consolidated statement of income (loss) for the first three quarters in 2012. Amounts related to derivatives previously classified in other revenue have been reclassified to derivative gains (losses), net. The total impact to the income statement is shown in the Supplemental Selected Quarterly Financial Statements included in Item 8 to this Annual Report.


34


  
For the Three Months Ended
March 31, 2012
 
For the Three Months Ended
June 30, 2012
 
For the Three Months Ended
September 30, 2012
  
As previously reported
 
As restated
 
As previously reported
 
As restated
 
As previously reported
 
As restated
 
 
 
 
 
 
 
 
 
 
 
 
Production revenue
171,820

 
166,454

 
150,503

 
150,311

 
157,699

 
156,288

Derivative gain (loss), net

 
(6,664
)
 

 
33,139

 

 
(60,377
)
Total revenue
145,469

 
172,866

 
168,562

 
194,018

 
177,702

 
118,188

Depletion, depreciation and accretion
54,439

 
54,439

 
51,942

 
48,016

 
43,209

 
34,014

Impairment
62,746

 
317,928

 
991,921

 
1,199,726

 
546,835

 
551,132

Operating income (loss)
(40,200
)
 
(267,985
)
 
(974,589
)
 
(1,153,012
)
 
(521,935
)
 
(576,551
)
Income (loss) before income taxes
(85,018
)
 
(312,803
)
 
(1,019,430
)
 
(1,197,853
)
 
(569,410
)
 
(624,026
)
Income tax (expense) benefit
25,094

 
101,238

 
346,889

 
395,831

 
(82,352
)
 
(166,494
)
Net income (loss)
(59,924
)
 
(211,565
)
 
(672,541
)
 
(802,022
)
 
(651,762
)
 
(790,520
)
Earnings (loss) per common share - diluted
(0.35
)
 
(1.24
)
 
(3.96
)
 
(4.72
)
 
(3.83
)
 
(4.65
)
Quarter Ended March 31, 2012
The derivative restatement adjustment decreased production revenue by $3.6 million and $1.8 million for the U.S. and Canada, respectively, while derivative gains increased $20.7 million and $12.0 million for the U.S. and Canada, respectively. Impairment expense increased as the result of these derivatives no longer being included in the cost center ceiling by $115.7 million and $139.5 million for the U.S. and Canada, respectively. The income tax impact of these adjustments resulted in an increase to the tax benefit of $41.9 million and $34.2 million for the U.S. and Canada, respectively. Our consolidated net loss increased $151.6 million. The restatement increased diluted net loss per share by $0.89, from diluted net loss per share of $0.35 as previously reported, to diluted net loss per share of $1.24.
Quarter Ended June 30, 2012
The derivative restatement adjustment increased production revenue by $1.3 million for the U.S. and decreased production revenue by $1.5 million for Canada, while derivative gains increased $22.2 million and $3.5 million for the U.S. and Canada, respectively. Impairment expense increased as the result of these derivatives no longer being included in the cost center ceiling by $144.0 million and $63.8 million for the U.S. and Canada, respectively, while depletion expense decreased $1.3 million and $2.6 million for the U.S. and Canada, respectively. The income tax impact of these adjustments resulted in an increase to the tax benefit of $34.3 million and $14.6 million for the U.S. and Canada, respectively. Our consolidated net loss increased $129.5 million. The restatement increased diluted net loss per share by $0.76, from diluted net loss per share of $3.96 as previously reported, to diluted net loss per share of $4.72.
Quarter Ended September 30, 2012
The derivative restatement adjustment decreased production revenue by $0.3 million and $1.1 million for the U.S. and Canada, respectively, while derivative losses increased $42.8 million and $15.3 million for the U.S. and Canada, respectively. Impairment expense increased as the result of these derivatives no longer being included in the cost center ceiling by $43.4 million for the U.S. and decreased impairment expense by $39.1 million for Canada, while depletion expense decreased $3.3 million and $5.9 million for the U.S. and Canada, respectively. The income tax impact of these adjustments resulted in an increase to the tax expense of $75.3 million and $8.8 million for the U.S. and Canada, respectively. Our consolidated net loss increased $138.8 million. The restatement increased diluted net loss per share by $0.82, from diluted net loss per share of $3.83 as previously reported, to diluted net loss per share of $4.65.
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, 2012, 76% and 23% 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 81%, 11% and 7%, respectively, of our proved reserves at December 31, 2012. During 2012, 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


35


our Horn River Asset provides us the most immediate additional opportunity for further application of our unconventional resources expertise.
Our focus for 2013 is on the execution of strategic transactions and the improvement of our capital structure through deleveraging and the extension of our debt maturities. If we are successful with these priorities in 2013, we would expect that we would focus on three other value drivers in the future:
reserve growth;
production growth; and
maximizing our operating margin.
Our reserve growth depends on our ability to fund a drilling program. It also relies on our ability to apply our technical and operational expertise to explore and develop unconventional reservoirs. We strive to increase reserves and production through aggressive management of our operations and through relatively low-risk developmental drilling. All of our development and exploratory programs are aimed at providing us with opportunities to develop unconventional reservoirs.
We believe the acreage we hold in our core operating areas is well suited for 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,
 
2012 (2)
 
2011
 
2010
Organic reserve growth (1)
(42
)%
 
1
%
 
19
%
Production volume (Bcfe)
131.8

 
150.6

 
129.6

Cash flow from operating activities (in millions)
$
227.7

 
$
253.1

 
$
397.7

Diluted earnings (loss) per share
$
(13.83
)
 
$
0.52

 
$
2.50


(1) 
This ratio is calculated by subtracting beginning of the year proved reserves from adjusted end of the year proved reserves and dividing by beginning of the year proved reserves. Adjusted end of the year reserves are calculated by adding back divested reserves and production and deducting acquired reserves from end of the year reserves.
(2) 
During 2012, Quicksilver recognized substantial negative reserve revisions due to lower average SEC commodity prices compared to prior periods. As such, we recognized a 1.2 Tcfe negative revision for all of 2012, which represents a 44% decline compared to 2011 year-end reserves. Organic reserve adds in 2012 were approximately 49 Bcfe, which represents less than 2% growth from 2011. The modest level of reserve additions results from two main factors: 1) approximately 85% of the 22 gross wells drilled in the Barnett Shale in 2012 were PUD locations at year-end 2011. Therefore, no new reserves were recognized for these PUD locations after bringing them on line; and 2) we did not recognize significant additional PUD locations at year-end 2012 due the influence of commodity prices on the five-year development profile. Customarily, we would recognize additional PUD locations to offset drilled locations during the year provided the new PUDs meet the SEC's standards, including the five-year limitation.
The organic reserve growth ratio is a supplemental measure that we use to assess how successfully we are implementing our business strategy of pursuing disciplined organic growth. We believe that total reserve growth is a multi-year key value driver of which organic reserve growth is a component. Reserve estimation has inherent limitations which are detailed in our Risk Factors in Item 1A and include assumptions regarding future production rates, timing and amount of future development expenditures, results of geological, geophysical, production and engineering data and economic factors. Any inaccuracies in these assumptions could materially affect the estimated quantities of proved reserves. Item 8 “Supplemental Oil and Gas Information” contains additional information about our reserves.

2012 HIGHLIGHTS
Joint Venture Update
On December 28, 2012, we entered into an agreement with SWEPI LP to jointly develop our oil and gas interests in the Niobrara formation of the Sand Wash Basin and to establish an Area of Mutual Interest (“AMI”) covering in excess of 850,000 acres. Each party assigned to the other a 50% working interest in the majority of its combined acreage so that each party owns a 50% interest in more than 320,000 acres and has the right to a 50% interest in any acquisition within the AMI. SWEPI paid us an equalization payment for 50% of the acreage contributed by us in excess of the acreage that SWEPI contributed. SWEPI is


36


the operator of the majority of the jointly owned lands. This relationship is strategic to the development of the Niobrara Asset as it created contiguous acreage blocks, which will lead to a more orderly and cost-effective development of the basin.
Quicksilver is engaged in confidential negotiations with a potential buyer to sell a non-operated minority working interest in its Barnett Shale Asset.
We continue our efforts to achieve a joint venture in our Horn River Asset in Northeast British Columbia, with the downstream marketing of the gas a top priority. We plan minimal capital spending in our Horn River Asset pending completion of a joint venture.
Horn River Development
We completed our first multi-well pad in our Horn River Asset during June and July 2012. The initial instantaneous production results from these new wells ranged between 23 MMcfd and 34 MMcfd, which exceeded our expectations. Production was curtailed from the new eight-well pad since August 2012 due to a delay in commissioning of a third-party's treating facility and limitations of surface equipment. In December 2012, we secured temporary alternative treating and transportation and increased gross production to 100 MMcfd within 15 days. We do not have a firm date for when the new treating facility, at which we have firm capacity, will be operable, but we believe we have sufficient treating and transportation capacity in the interim to meet our needs.
On January 30, 2013, the Canadian NEB issued its report recommending against approval of NGTL's Komie North Project, which included a 75-mile pipeline that would connect NGTL's Alberta system to a meter station planned to be constructed on our acreage in the Horn River Basin. We believe the NEB's recommendation against the Komie North Project will be adopted by the federal authority. The NEB concluded that the evidence presented at this time did not justify a 36-inch line as proposed; however, its recommendation notwithstanding, the NEB emphasized its belief in the long-term prospects for development of the Horn River Basin. We believe NGTL will undertake efforts to secure additional shipper support for this pipeline.
We had previously provided $30 million in letters of credit, which were reduced to $14 million during March 2013. We believe future financial assurances, upon a revised application, which we expect may be delayed by up to two years, would be reduced proportionately relative to additional shipper support. Likewise, we are planning to defer drilling in the Horn River Basin until 2014 and have the ability to defer construction of a natural gas treating facility until at least 2016 to coincide with the revised timelines for the Komie North Project.
Our ability to sell gas at the Station 2 and AECO hubs has not been impacted by the NEB's recommendation, as its acreage is served by existing treating facilities and pipelines which today can accommodate in excess of 1 billion cubic feet per day. Due to the pace of development in the basin by all producers, discounted excess capacity is available in the region to meet Quicksilver's needs.
Emerging Basins
During 2012, we drilled and completed three vertical wells in the Sand Wash Basin using a variety of stimulation methods and drilled one well. We are currently conducting exploratory activities and have eight producing wells as of December 31, 2012.
During 2012, 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. Our leases total 125,000 acres across Reeves, Pecos, Jeff Davis, Upton and Crockett Counties. We drilled and completed our first short-lateral well in Pecos County in August 2012, which targeted the Third Bone Springs formation, and we drilled and completed another short-lateral well in Upton County in December 2012, which targeted the Wolfcamp formation.
Master Limited Partnership
In February 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 amended the registration statement in May to include financial statements for 2011 and to address comments received from the SEC and again in June to include financial statements for the first quarter of 2012 and to address further comments received from the SEC. In July 2012, we were informed that the SEC had no further comments. During the fourth quarter of 2012 we recognized an expense for the deferred filing fees associated with this offering since the transaction has been dormant since June 2012. This accounting treatment does not preclude us from updating the registration document at a later date and we will continue to monitor market conditions to assess the timing of an offering, which may be influenced by a joint venture covering our Barnett Shale Asset.


37


Significant Contract Revisions
In August 2012, we amended our Combined Credit Agreements primarily to relax the financial covenants through the second quarter of 2014. Specific changes to the Combined Credit Agreements are outlined in Note 11 to the consolidated financial statements in Item 8.

2013 CAPITAL PROGRAM
We expect our 2013 capital program to be spent in the following areas:
 
(In millions)
Barnett Shale
$
10

Niobrara
35

West Texas
6

Total U.S.
51

Horn River
29

Horseshoe Canyon
3

Total Canada
32

Corporate (1)
37

Total Company
$
120

(1) Includes capitalized interest expense and capitalized internal costs.
We expect our 2013 production volume to be between 335 and 345 MMcfe per day.
FINANCIAL RISK MANAGEMENT
We have established internal control policies and procedures for managing risk within our organization. The possibility of decreasing prices received for our natural gas, NGL and oil production is one of the several risks that we face. We seek to manage this risk by entering into derivative contracts. We have mitigated the downside risk of adverse price movements through the use of 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.



38


RESULTS OF OPERATIONS
“Other U.S.” refers to the combined amounts for our operations in our Niobrara Asset, West Texas Asset and Southern Alberta Asset.
Revenue
We aggregate production revenue and realized cash gains (losses) on derivatives not treated as hedges in measuring revenue from our oil and gas production. Historically, we have used hedge accounting and combining these items mirrors our views of the derivatives' usefulness and provides more comparability.
Production Revenue and Realized Cash Gains (Losses) on derivatives by operating area:
 
Natural Gas
 
NGL
 
Oil
 
Total
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
 
2012
 
2011
 
2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(In millions)
Barnett Shale
$
200.9

 
$
376.5

 
$
321.2

 
$
137.5

 
$
216.6

 
$
160.6

 
$
10.9

 
$
11.8

 
$
11.8

 
$
349.3

 
$
604.9

 
$
493.6

Other U.S.
0.6

 
1.1

 
2.3

 
0.5

 
0.6

 
0.5

 
13.7

 
12.3

 
10.0

 
14.8

 
14.0

 
12.8

Hedging
151.3

 
100.2

 
250.2

 
23.5

 
(46.1
)
 
(24.1
)
 

 

 

 
174.8

 
54.1

 
226.1

U.S.
352.8

 
477.8

 
573.7

 
161.5

 
171.1

 
137.0

 
24.6

 
24.1

 
21.8

 
538.9

 
673.0

 
732.5

Horseshoe Canyon
48.2

 
79.2

 
90.4

 
0.1

 
0.1

 
0.2

 

 

 

 
48.3

 
79.3

 
90.6

Horn River
23.9

 
17.4

 
10.6

 

 

 

 

 

 

 
23.9

 
17.4

 
10.6

Hedging
19.8

 
30.8

 
22.7

 

 

 

 

 

 

 
19.8

 
30.8

 
22.7

Canada
91.9

 
127.4

 
123.7

 
0.1

 
0.1

 
0.2

 

 

 

 
92.0

 
127.5

 
123.9

Consolidated production revenue
$
444.7

 
$
605.2

 
$
697.4

 
$
161.6

 
$
171.2

 
$
137.2

 
$
24.6

 
$
24.1

 
$
21.8

 
$
630.9

 
$
800.5

 
$
856.4

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S. realized cash derivative gains
23.0

 

 

 

 

 

 

 

 

 
23.0

 

 

Canada realized cash derivative gains
19.8

 

 

 

 

 

 

 

 

 
19.8

 

 

Consolidated realized cash derivative gains
42.8

 

 

 

 

 

 

 

 

 
42.8

 

 

Consolidated production revenue and realized cash derivative gains (1)
$
487.5

 
$
605.2

 
$
697.4

 
$
161.6

 
$
171.2

 
$
137.2

 
$
24.6