ITEM 1. Business
GENERAL
We are an independent oil and gas company engaged primarily in the acquisition, exploration, development and production of onshore oil and gas in North America based in Fort Worth, Texas. We focus primarily on unconventional reservoirs where hydrocarbons may be found in challenging geological conditions, such as fractured shales, coalbeds and tight sands. Our producing oil and gas properties in the United States are principally located in Texas, Colorado, Wyoming and Montana, and in Canada in Alberta and British Columbia. We had total proved reserves of approximately 2.8 Tcfe at December 31, 2011. Our three core areas include:

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 exploration opportunities in North America, most notably in the following regions:

Midland and Delaware basins in West Texas;

Sandwash basin in Northwest Colorado; and

Bakken formation in Montana and Wyoming.
In addition, our new ventures team actively studies other basins in North America which may yield future exploration opportunities.
Our common stock trades under the symbol “KWK” on the New York Stock Exchange.
FORMATION AND DEVELOPMENT OF BUSINESS
We were organized as a Delaware corporation in 1997 and became a public company in 1999. As of February 15, 2012, members of the Darden family and entities controlled by them, beneficially owned more than 30% of our outstanding common stock.
STRATEGIC TRANSACTIONS IN THE LAST FIVE YEARS
On February 10, 2012, we filed a Form S-1 with the SEC to begin the registration and sale of limited partnership interests in a master limited partnership holding certain of our mature properties in our Barnett Shale Asset. We expect this registration statement to become effective in 2012.
In December 2011, we and KKR formed a midstream partnership to construct and operate natural gas midstream services to support producer customers in British Columbia. We contributed to the partnership our existing 20-mile, 20-inch gathering line and compression facilities and 10-year contracts for gas deliveries into those facilities in consideration for $125 million and a 50% interest in the partnership. The creation of this partnership is strategic to the continued development of our Horn River Asset as it is expected to reduce the cost of processing and transporting gas to sales markets.
In October 2010, we sold all of our interests in KGS to Crestwood. Crestwood paid $700 million in cash and assumed debt of $58 million and we recognized a gain of $494 million. In February 2012, we received an additional $41 million in consideration of an earn-out on these assets and will recognize an additional gain in the first quarter of 2012. We believe the sale of these midstream assets allowed us to better focus on the development of our natural gas properties while redeploying the associated capital into projects with higher expected returns.
In May 2010, we acquired an additional 25% working interest in our Lake Arlington Asset which represented 125 Bcf of proved reserves, for $62 million in cash and 3.6 million BBEP Units. Throughout 2010 and 2011, through this and other transactions, we continued to sell portions of our BBEP Units. At December 31, 2011, we no longer held any BBEP Units.
In January 2010, we completed the sale of certain of our midstream assets to KGS for $95 million. KGS funded the purchase primarily with proceeds from the KGS Secondary Offering which reduced our ownership in KGS from 73% to 61%.
In June 2009, we completed the Eni Transaction in which we sold 121 Bcf of proved reserves to Eni for $280 million. Also as part of the Eni Transaction, we and Eni formed a strategic alliance for the acquisition and development of unconventional natural gas resources in an area covering approximately 270,000 acres surrounding our Alliance Asset.
In December 2008, we sold the gathering system in our Lake Arlington Asset to KGS for $42 million.
In August 2008, we completed the $1.3 billion Alliance Acquisition that consisted of producing and non-producing leasehold, royalty and midstream assets in the Barnett Shale. Consideration in the transaction was $1 billion in cash and $262 million of our common stock.
In 2007, we sold all of our oil and gas properties in Michigan, Indiana and Kentucky to BBEP for $750 million in cash and 21.3 million BBEP Units, valued at $724 million at the closing of the transaction, resulting in total proceeds at closing of $1.474 billion.
BUSINESS STRATEGY
We have a multi-pronged strategy to increase share value through long-term cost-effective growth in production and reserves by focusing on unconventional resource plays onshore in North America. This strategy takes advantage of our proven record and expertise in identifying and developing properties containing fractured shale and coalbed methane. Our strategy includes the following key elements:
Focus on core areas of repeatable, low-risk development: We believe that development activity in areas we have acquired a contiguous acreage position allows us to efficiently deploy our resources, manage our costs and leverage our technical expertise. Additionally, we endeavor to acquire acreage positions that are not only contiguous from a land perspectives, which is more efficient for drilling, but is also contiguous from a resource perspective, which will create a more economic asset for us.
Pursue disciplined organic growth opportunities: We typically plan to spend 10% of our capital program on high-potential, longer cycle-time exploration projects to replenish our inventory of development projects for the future. Through our activities in multiple unconventional resource basins, we have significant expertise and a demonstrated history of identifying, developing and producing fractured shales, coal seams and tight sands. We are focused on identifying and evaluating additional opportunities that allow us to apply this expertise and experience to the development and operation of other unconventional reservoirs in North America. We believe our core strength lies in our ability to identify and acquire large resource targets at low cost per acre. When we have secured an acreage position, we then drill resource assessment wells and validation wells to determine the size and commerciality of the project. Once the project is validated, we build infrastructure to secure affordable gathering, processing, transportation, and operating costs. Finally, we move the project to the full development stage. We have historically monetized mature assets to provide financial flexibility for future projects. In 2012, we will continue to focus our development activities in the Barnett Shale. In Horn River, where we expect to convert our exploratory licenses covering more than 130,000 net prospective acres to leases with an expected 10-year term, we are in transition from the exploration phase to full development. Our exploration activities will be focused in the Sandwash basin, where we hold approximately 260,000 net acres, and in the Midland and Delaware basins of West Texas, where we hold approximately 155,000 net acres.
Enhance profitability through control and marketing of our equity natural gas and oil: We generally seek to maximize profitability by exercising control over the delivery of our production to distribution pipelines owned by third parties. We seek to achieve this by continuing to improve upon and add to our gathering and processing infrastructure during the infrastructure’s development phase. We believe this allows us to better manage the physical movement of our production and the efficiency of our operations by decreasing dependency on third parties. We also monitor the spot markets for commodities and seek to sell our uncommitted production into the most attractive markets. Our partnership with KKR established an area of mutual interest that covers approximately 30 million potential acres in the Horn River, Cordova, and Liard basins in British Columbia and
Northwest Territories for potential midstream expansion. We expect this partnership will reduce our cost to process and transport our gas to sales markets by 44% as compared to other current alternatives. The backbone of the midstream infrastructure is in place for our Barnett Shale Asset and Horseshoe Canyon Asset.
Maintain a prudent capital structure to ensure financial flexibility: We believe that a flexible financial structure enables us to capitalize on opportunities and to limit our financial risk. We believe our internally-generated cash flows supplemented with asset monetization, joint ventures and borrowings under our Combined Credit Agreements provide us with the financial flexibility to pursue our acquisition, development and exploration programs. In order to increase the predictability of the prices we receive for our natural gas and NGL production, we hedge the commodity price of a substantial portion of our expected production with financial derivative instruments. We regularly review the credit-worthiness of our hedging counterparties, and our hedging program is spread among numerous financial institutions, all of whom participated in our credit facilities at the time of entering into the hedge. We have entered into long-term hedges to provide predictability over longer periods.
BUSINESS STRENGTHS
High-quality asset base with long reserve life: Our proved reserves totaled approximately 2.8 Tcfe as of December 31, 2011 of which 69% were developed. Our Barnett Shale Asset has approximately 88% of our proved reserves and approximately 12% are located in our Horseshoe Canyon Asset and our Horn River Asset. These areas have a history of proven well performance and have established and emerging infrastructure to permit delivery of our production to sales markets. We believe our reserves are characterized by long lives and predictable well production profiles. Based on our annualized fourth-quarter 2011 average production from all of our properties, our implied reserve life (proved reserves divided by annualized fourth-quarter 2011 production) was 18.4 years and our implied proved developed reserve life (proved developed reserves divided by annualized fourth-quarter 2011 production) was 12.7 years. As of December 31, 2011, almost 98% of our proved reserves were attributable to properties we operate.
Multi-year inventory of developmental drilling projects: As of December 31, 2011, we owned leases covering more than 580,000 net acres in our three core areas, of which 82% were classified as held by production. Within our Barnett Shale Asset alone, we have identified drilling locations that provide us greater than a 10-year inventory of drilling locations at the 2012 anticipated drilling rate. Our drilling success rate has averaged more than 99% during the past three years. We use 3D seismic data to enhance our ongoing drilling and development efforts as well as to identify new targets in both new and existing fields, and our seismic library covers more than 90% of our acreage in our Barnett Shale Asset.
We have also identified exploratory opportunities that provide meaningful exposure to additional oil and gas resources. As of December 31, 2011, we have successfully drilled 10 gas wells and completed four gas wells in our Horn River Asset, and 80% of our licensed acreage has been validated. After completing our planned 2012 drilling in our Horn River Asset, we expect to be in a position to convert 98% of our licenses to 10-year leases. Our total proved reserves in our Horn River Asset are 99.3 Bcfe.
Proven record of organic growth in reserves and production: During the past three years, our proved reserves have grown 26% as we added 1.1 Tcfe of proved reserves from organic development activities. We supplemented this activity with acquisitions in the Barnett Shale and Horseshoe Canyon, which combined, total 147.3 Bcf of acquired proved reserves. We also sold 121 Bcf of proved reserves in the Eni Transaction in 2009. We have organically replaced 274% of our production during the three years ended December 31, 2011. Our growth has resulted from our ability to acquire attractive undeveloped acreage and to apply our technical expertise to find, develop and produce reserves. In recent years, we have demonstrated this ability through our accomplishments in our three core areas. We believe our current acreage position provides opportunities and flexibility to continue our organic growth of reserves and production.
Extensive technical experience and familiarity with developing and operating Barnett Shale properties and other unconventional resources. We are one of the five largest producers in the Barnett Shale. The development of the Barnett Shale helped pioneer unconventional shale development, and the Barnett Shale currently produces over 5.0 Bcf of natural gas per day with over 15,000 wells drilled since 2003, according to the Railroad
Commission of Texas. Our staff of petroleum professionals, many of whom have significant engineering, geologic and other expertise which allows us to be competitive in unconventional resource plays. We intend to utilize these resources to optimize our recovery of reserves and to enhance the value of our assets.
Experienced management and technical team: Our CEO, Glenn Darden, and our Chairman, Thomas F. Darden, are founding members of our company and have held executive positions with us since our formation. They and our experienced executive management team have successfully implemented a disciplined growth strategy with a primary focus on net asset value growth through the development of unconventional reservoirs. Messrs. Glenn and Thomas Darden have been in the oil and natural gas business their entire professional careers and each has extensive experience in the acquisition, exploration, development, and production of oil and gas properties, as well as experience in the integration and management of energy assets in a reliable and cost-effective manner. Our executive management team is supported by a core team of technical, operational and financial managers who have significant industry experience, including experience in drilling and completing horizontal wells in unconventional reservoirs and in evaluating and completing strategic transactions.
FINANCIAL INFORMATION ABOUT SEGMENTS AND GEOGRAPHICAL AREAS
The consolidated financial statements included in Item 8 of this Annual Report contain information on our segments and geographical areas, are incorporated herein by reference.
PROPERTIES
Substantially all of our properties consist of interests in developed and undeveloped oil and natural gas leases. In addition, we are currently developing gathering and processing facilities in our Horn River Asset with KKR, with whom we formed Fortune Creek.
OIL AND NATURAL GAS OPERATIONS
Our oil and natural gas operations are focused onshore in North America, in basins containing unconventional reservoirs with predictable, long-lived production. Our current production and development operations are concentrated in our three core areas: the Barnett Shale, Horn River, and Horseshoe Canyon. At December 31, 2011, we had total proved reserves of approximately 2.8 Tcfe, of which 77% is natural gas and 22% is NGLs. For 2011, we had total production of 150.5 Bcfe which averages to 413 MMcfed. In the last five years, we have grown our reserves and production at an approximate compound annual growth rate of 12% and 14%, respectively.
We believe the development of our leasehold interests in our core areas, and our exploration activities in the Sandwash basin and in West Texas will give us the flexibility over the next several years to grow reserves and production economically. We may also pursue acquisitions of additional interests where economically feasible, which could allow for further capitalization on our proven expertise in unconventional resource plays. Details of our 2012 capital program and our projected production levels can be found in Item 7 of this Annual Report.
Barnett Shale
Over 88% of our total proved reserves and over 81.6% of our total average daily production in 2011 were in our Barnett Shale Asset. In the fourth quarter of 2011, our net production from our wells in our Barnett Shale Asset was 338.0 MMcfed. We expect 74% of our 2012 production to come from our Barnett Shale Asset.
At December 31, 2011, we had approximately 140,000 net acres in the Barnett Shale of which approximately 55% is currently held by production. Much of our acreage in Hood and Somervell counties contains high-Btu natural gas. NGLs are extracted through midstream facilities that we constructed and are now owned by CMLP. In the current pricing environment, where NGLs trade at a premium to methane, we are able to increase our revenue per Mcf of natural gas production by extracting and separately selling NGLs. In 2011, sales of NGLs represented 22% of our Barnett Shale Asset production.
During 2011, we drilled 57 (49.9 net) wells and completed 128 (113.2 net) wells in our Barnett Shale Asset primarily from multi-well drilling pads. On these multi-well pads, all the wells are drilled prior to initiating completion activities. At December 31, 2011, we had drilled a total of 1,030 (859.4 net) wells in our Barnett
Shale Asset since we began exploration and development operations in 2003. At December 31, 2011, we had two drilling rigs operating in our Barnett Shale Asset, but expect to utilize an average of one rig in the high-liquid acreage of Hood and Somervell Counties for the remainder of 2012.
West Texas
During 2011, we continued to build an oil prospective acreage position in the Bone Springs and Wolfcamp formations in the Midland and Delaware basins in West Texas. We now hold leases totaling 155,000 acres across Reeves, Pecos, Jeff Davis, Upton, Crockett and Presidio Counties. We plan to commence drilling operations in this area late in the first quarter of 2012.
Rockies
Our Rocky Mountain assets are located in the Bakken formation in Montana and Wyoming and the Niobrara formation in the Sandwash basin in Colorado. We have approximately 175,000 net acres in the Bakken formation, 68% of which is held by production. At December 31, 2011, proved reserves from these properties were 16.7 Bcfe, of which 92% was oil or NGLs.
We also hold approximately 260,000 net acres in the Sandwash basin where we are currently conducting exploratory activities and have two producing gas wells. During 2011, we drilled seven vertical wells followed by our first horizontal well in the fourth quarter of 2011, with initial production results of up to 500 Bbld produced from a 3,000 foot lateral. We plan to drill an additional four to seven horizontal wells in 2012, and plan to move the program to the development stage in 2013, pending positive well results. Total proved reserves in our Sandwash Asset are 0.3 Bcfe at December 31, 2011.
Daily production from all our properties in the Rocky Mountain region averaged 3.3 MMcfed for 2011.
Horseshoe Canyon
At December 31, 2011, our Horseshoe Canyon Asset proved reserves were 231.4 Bcfe, all of which was natural gas. Production averaged 58.5 MMcfed in our Horseshoe Canyon Asset, representing 14.2% of our total 2011 production.
In our Horseshoe Canyon Asset, as of December 31, 2011, we had 49,458 (36,929 net) undeveloped acres. During 2011 we spent $3.0 million for drilling and completion, largely funded by cash flows from operations from our Horseshoe Canyon Asset. Similar to 2011, we expect to completely fund 2012 drilling and completion activities in this asset with operating cash flows.
Horn River
We also have exploratory licenses which we expect to convert to leases in more than 130,000 net acres in Horn River. During 2011, we spent $95.0 million for drilling and completion costs on our Horn River Asset where we drilled and cased 10 wells and completed one well. As of December 31, 2011, we had four wells producing and 10 wells drilled and awaiting completion in our Horn River Asset, of which we expect eight wells to come online in 2012. Our production requires gathering, processing and transportation, for which we believe we have ample capacity to meet our needs for the foreseeable future. Our total proved reserves in our Horn River Asset were 99.3 Bcfe as of December 31, 2011, all of which was natural gas.
Quicksilver entered into agreements with NGTL whereby NGTL has agreed to construct and own a 60-mile, 36” pipeline extension from its Alberta system to our Fortune Creek Meter Station in order to transport Horn River natural gas to sales markets. We expect this extension will provide a low-cost transportation alternative to existing infrastructure, and will deliver gas to sales hubs, some of which historically have traded at a premium to Station 2 pricing where most Horn River basin gas is currently sold. NGTL expects to begin right-of-way clearing in January 2013, with construction expected to start at the end of 2013. The pipeline is expected to be in-service by June 2014. We have entered into agreements with NGTL to deliver up to 1 Tcf of production over a 10-year period starting in 2014. Our obligation may be reduced by delivery of volumes from third-party producers. We are further required to deliver pipeline-quality gas, which we plan to treat in facilities constructed by Fortune Creek.
OIL AND NATURAL GAS RESERVES
Our proved reserve estimates and related disclosures for 2011, 2010 and 2009 are presented in compliance with the SEC rule. The information with respect to our proved reserves and related disclosures have been prepared by Schlumberger Data & Consulting Services (“Schlumberger”) and LaRoche Petroleum Consultants, Ltd. (“LaRoche”), our independent reserve engineers for U.S. and Canada, respectively.
The process of estimating our proved reserves is complex. In order to prepare these estimates, we have developed, maintained and monitored internal processes and controls for estimating and recording proved reserves in compliance with the rules and regulations of the SEC. Compliance with the SEC reserve guidelines is the primary responsibility of our reservoir engineering team. We require that proved reserve estimates be made by qualified reserve estimators, as defined by the Society of Petroleum Engineers’ standards. Our reservoir engineering team, which is responsible for our proved reserve estimates, participates in continuing education to maintain a current understanding of SEC reserve reporting requirements.
Our reservoir engineering team, led by Chris Mundy, Vice President-Engineering, is responsible for the preparation and maintenance of our engineering data and review of our proved reserve estimates with Schlumberger and LaRoche. Mr. Mundy has over 15 years of experience in the oil and gas industry. Mr. Mundy is licensed as a Professional Engineer, registered with the Association of Professional Engineers, Geologists and Geophysicists of Alberta and is a member of the Society of Petroleum Engineers. Mr. Mundy earned a Bachelor of Applied Science degree in civil engineering from the University of Waterloo, Ontario, Canada. The reservoir engineering team reports directly to him and is otherwise independent from management for our operating areas. Throughout the year, the reservoir engineering team analyzes the performance of producing properties for each operating area, identifies proved reserve additions and revisions and prepares internal proved reserve estimates. In addition, the team is responsible for maintaining all reserve engineering data. Integrity of reserve engineering data is enhanced by restricting full access to only the members of our reservoir engineering team. Limited other personnel have read-only access with no ability to modify reserve engineering data.
The technical person at Schlumberger responsible for overseeing the preparation of our estimates of proved reserves is Charles M. Boyer II, PG, CPG. Mr. Boyer is licensed in the Commonwealth of Pennsylvania and has over 30 years of geologic and engineering experience in the oil and gas industry. Mr. Boyer earned a Bachelor of Science degree in geological sciences from The Pennsylvania State University in University Park and completed graduate studies in mining and petroleum engineering at the University of Pittsburgh and The Pennsylvania State University. The technical persons at LaRoche responsible for preparing our estimates of Canadian proved reserves meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The technical person at LaRoche primarily responsible for overseeing the preparation of our estimates of proved reserves is Stephen W. Daniel. Mr. Daniel is a Professional Engineer licensed in the State of Texas who has 40 years of engineering experience in the oil and gas industry. Mr. Daniel earned a Bachelor of Science degree in Petroleum Engineering from University of Texas and has prepared reserves estimates for his employers throughout his career. He has prepared and overseen preparation of reports for public filings for LaRoche for the past 15 years. Prior to finalizing their proved reserve estimates, each of Schlumberger’s and LaRoche’s results are reviewed in detail by internal reservoir engineering teams, Mr. Mundy and the other members of our executive management team.
The Audit Committee of our Board has met with our executive management team, including Mr. Mundy, and with Schlumberger and LaRoche to discuss the process and results of proved reserve estimation. The analytical review of proved reserve estimates includes comparisons of ending proved undeveloped estimates to our average ending ultimate recoverable proved reserves for each of our operating areas. Additional reviews of drilling results and proved undeveloped estimates have been conducted with our executive management team and the Audit Committee of our Board.
Pursuant to the rules and regulations of the SEC, proved reserves are the estimated quantities of natural gas, NGLs and oil which, through analysis of geological and engineering data, demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” connotes a high degree of confidence that the quantities of natural gas, NGLs and oil actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the technologies used in the estimation process must have been demonstrated to yield results with consistency and
repeatability. Proved developed reserves are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are expected to be recovered from new wells on undrilled acreage. Proved reserves for undrilled wells are estimated only where it can be demonstrated that there is continuity of production from the existing productive formation. To achieve reasonable certainty of our proved reserve estimates, our reservoir engineering team assumes continued use of technologies with demonstrated success of yielding expected results, including the use of drilling results, well performance, well logs, seismic data, geologic maps, well stimulation techniques, well test data, and reservoir simulation modeling.
The proved reserve data we disclose are estimates and are subject to inherent uncertainties. The determination of our proved reserves is based on estimates that are highly complex and interpretive. Reserve engineering is a subjective process that depends upon the quality of available data and on engineering and geological interpretation and judgment. Although we believe our proved reserve estimates are reasonable, reserve estimates are imprecise and are expected to change as additional information becomes available. Additional information regarding risks associated with estimating our proved reserves may be found in Item 1A
ITEM 1A. Risk Factors
You should carefully consider the following risk factors together with all of the other information included in this Annual Report, including the financial statements and related notes, when deciding to invest in us. You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report could have a material adverse effect on our business, financial position, results of operations and cash flows.
Commodity prices fluctuate widely, and low prices could adversely affect our ability to borrow under and comply with our debt agreements and have a material adverse impact on our business, financial condition and results of operations.
Our revenue, profitability, and future growth depend in part on prevailing commodity prices. These prices also affect the amount of cash flow available to service our debt, fund our capital program and our other liquidity needs, as well as our ability to borrow, raise additional capital and comply with the terms of our various debt agreements. Among other things, the amount we can borrow under our Combined Credit Agreements is subject to periodic redetermination based in part on expected future prices. Lower prices may also reduce the amount of natural gas, NGLs and oil that we can economically produce.
Prices for our production fluctuate widely, particularly as evidenced by price movements between 2008 and 2011. Among the factors that can cause these fluctuations are:

domestic and foreign demand for oil and natural gas;

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 and climate change requirements;

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.
If the prices we receive for our production decrease, our exploration and development efforts are unsuccessful or our costs increase substantially, we may be required to recognize non-cash impairment of our oil and gas properties, which could have a material adverse effect on our results of operations.
We employ the full cost method of accounting for our oil and gas properties which, among other things, imposes limits to the capitalized cost of our assets. The capitalized cost pool cannot exceed the net present value of the underlying oil and gas reserves. We recognized impairment to the carrying value of our oil and gas properties in 2011, 2010 and 2009 of $49.1 million, $19.4 million and $979.5 million, respectively, and could recognize future impairments if the commodity prices utilized in determining proved reserve value cause the value of our proved reserves to decrease. Increased operating and capitalized costs without incremental increases in proved reserve value could also trigger impairment based upon decreased value of our proved reserves. The impairment of our oil and gas properties will cause us to reduce their carrying value and recognize non-cash expense, which could have a material adverse effect on our results of operations.
Our proved reserve and production estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in these estimates or underlying assumptions may materially affect the quantities and present value of our proved reserves and our forecasted production.
The process of estimating proved reserves and production is complex. In order to prepare these estimates, we and our independent reserve engineers must project future production rates and the timing and amount of future development expenditures and such projections may be inaccurate. We and the engineers must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. In addition to interpreting available technical data, we and the engineers must also analyze other various assumptions, including assumptions relating to economic factors. Any inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of proved reserves presented in our filings with the SEC.
Actual future production, commodity prices, revenue, taxes, development expenditures, operating expenses and our estimated quantities of recoverable proved reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of proved reserves and the estimated production presented in our filings with the SEC. In addition, we may adjust estimates of production and estimates of proved reserves to reflect production history, results of exploration and development, prevailing petroleum prices and other factors that may be beyond our control.
At December 31, 2011, 31% of our proved reserves were undeveloped. Recovery of undeveloped reserves requires additional capital expenditures and successful drilling and completion operations. Our proved reserve estimates assume that we will make significant capital expenditures to develop our proved reserves. Although we have prepared estimates of our proved reserves using SEC specifications, actual prices and costs may vary from these estimates, the development may not occur as scheduled or actual results of that development may not be as estimated prior to drilling.
The present value of future net cash flows disclosed in Item 8 of this Annual Report is not necessarily the fair value of our proved reserves. In accordance with SEC requirements, the discounted future net cash flows from proved reserves for 2011 are based upon prices determined on an unweighted average of the preceding 12-month first-day-of-the-month prices adjusted for local differentials and operating and development costs as of period end. Actual future prices and costs may be materially higher or lower than the prices and costs used in our estimate. Any changes in consumption by natural gas, NGL and oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the costs from the development and production of our oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is specified by the SEC, is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor in arriving at the actual fair value of our proved reserves.
All of our producing properties and operations are located in a small number of geographic areas, making us vulnerable to risks associated with operating in limited geographic areas.
Our Barnett Shale Asset and Horseshoe Canyon Asset account for 82% and 14% of our 2011 production, respectively. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or gas produced from the wells in these areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our business, financial condition and results of operations.
Our Canadian operations present unique risks and uncertainties, different from or in addition to those we face in our U.S. operations.
In addition to the various risks associated with our U.S. operations, risks associated with our operations in Canada, where we have substantial operations, include, among other things, risks related to increases in taxes and governmental royalties, aboriginal claims, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and compliance with U.S. and Canadian laws and regulations, such as the U.S. Foreign Corrupt Practices Act. For example, in addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates and other matters. The royalty regime is a significant factor in the profitability of oil and gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced. Laws and policies of the U.S. affecting foreign trade and taxation may also adversely affect our Canadian operations.
In addition, the level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing our activity levels. Also, certain of our oil and gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Therefore, seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity.
If we are unable to obtain needed capital or financing on satisfactory terms, our ability to replace our reserves or to maintain current production levels may be limited.
Historically, we have used our cash flow from operations, borrowings under our credit facilities and issuances of debt to fund our capital program, working capital needs and acquisitions. Our capital program may require additional financing above the level of cash generated by our operations to fund our growth. If our cash flow from operations decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our reserves or to maintain current production may be limited, resulting in decreased production over time. If our cash flow from operations is insufficient to satisfy our financing needs, we cannot be certain that additional financing will be available to us on acceptable terms or at all. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings, including the sale of equity interests in a master limited partnership, may be limited by our financial condition or general economic conditions at the time of any such financing or offering. Even if we are successful in obtaining the necessary funds, the terms of such financings could have a material adverse effect on our business, results of operations and financial condition. If additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis.
Our business involves many hazards and operational risks.
Our operations are subject to many risks inherent in the oil and gas industry, including operating hazards such as well blowouts, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, treatment plant “downtime,” pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could cause us to experience substantial losses. The occurrence of a significant accident or other event could curtail our operations and have a material adverse effect on our business, financial condition and results of operations.
Liabilities and expenses not covered by our insurance could have a material adverse effect on our business, financial condition and results of operations.
As a result of operating hazards, regulatory risks and other uninsured risks, we could incur substantial liabilities to third parties or governmental entities. We maintain insurance against some, but not all, of such risks and losses in accordance with customary industry practice. We are not insured against all incidents, claims or
damages that might occur, and pollution and environmental risks generally are not fully insurable. Any significant accident or event that is not adequately insured could adversely affect our business, financial condition and results of operations. In addition, we may be unable to economically obtain or maintain the insurance that we desire, or may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain of our insurance policies could escalate further. In some instances, certain insurance could become unavailable or available only at reduced coverage levels. Any type of catastrophic event that is not covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
The failure to replace our proved reserves could adversely affect our production and cash flows.
Producing oil and gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions. Our proved reserves will generally decline as proved reserves are produced, except to the extent that we conduct successful exploration or development activities or acquire additional proved reserves. In order to maintain or increase proved reserves and production, we must continue our development drilling or undertake other replacement activities. Our planned exploration and development projects or any acquisition activities that we may undertake might not result in meaningful additional proved reserves, and we might not have continuing success drilling productive wells. Even in the event that our exploration and development projects do result in meaningful additional commercially viable proved reserves, midstream infrastructure for these proved reserves may not exist or may not be constructed, either of which could adversely impact our ability to benefit from those proved reserves. If our exploration and development efforts are unsuccessful, our leases covering acreage that is not already held by production could expire. If they do expire and if we are unable to renew the leases on acceptable terms, we will lose the right to conduct drilling activities and the resulting economic benefits associated therewith. If we are unable to develop or acquire additional proved reserves to replace our current and future production at economically acceptable terms, our business, financial condition, results of operations would be adversely affected.
We cannot control the operations of gas gathering, processing, liquids fractionation and transportation facilities we do not own or operate.
We deliver our production to market through gathering, fractionation and transportation systems that we do not own. The marketability of our production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. A portion of our production could be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, maintenance of third-party facilities or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities or interstate pipelines to transport our production. Disruption of our production could negatively impact our ability to market, fractionate and deliver our production. Since we do not own or operate these assets, their continuing operation is not within our control. If any of these pipelines and other facilities becomes unavailable or capacity constrained, or if further planned development of such assets is delayed or abandoned, it could have a material adverse effect on our business, financial condition and results of operations.
Competition in our industry is intense, and we are smaller and have a more limited operating history than many of our competitors.
We compete with major and independent oil and gas companies for property acquisitions and for the equipment and labor required to develop and operate our properties. Many of our competitors have substantially greater financial and other resources than we do, and they may be better able to absorb the burden of drilling and infrastructure costs and any changes in federal, state, provincial and local laws and regulations than we can, which would adversely affect our competitive position. In addition, there is substantial competition for investment capital in the oil and gas industry. These competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than we can. Our ability to
explore for oil and gas prospects and to acquire additional properties in the future will depend upon our ability to conduct operations, to evaluate and select suitable properties and to complete transactions in this highly competitive environment. Furthermore, the oil and gas industry competes with other industries in supplying the energy and fuel needs of industrial, commercial and other consumers. Our inability to compete effectively with other oil and gas companies could have a material adverse impact on our business activities, financial condition and results of operations.
Our hedging policy may not effectively mitigate the impact of commodity price volatility on our cash flows, and our hedging activities could result in losses or limit our ability to benefit from price increases.
To reduce our exposure to hydrocarbon price fluctuations, we have entered and intend to continue to enter into commodity derivatives covering our future production, which may limit the benefit we would receive from increases in hydrocarbon prices. These arrangements also expose us to risk of financial losses in some circumstances, including the following:

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. If we choose not to enter into such commodity derivatives in the future, we could be more affected by changes in commodity prices than our competitors who engage in hedging arrangements.
Delays in obtaining oil field equipment and increases in drilling and other service costs could adversely affect our ability to pursue our drilling program.
As commodity prices increase, demand and costs for drilling equipment, crews and associated supplies, equipment and services can increase significantly. We cannot be certain that in a higher petroleum price environment we would be able to obtain necessary drilling equipment and supplies in a timely manner, on satisfactory terms or at all, and we could experience difficulty in obtaining, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services. In addition, drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, including urban drilling, and possible title issues. As a result of increased activity levels, we have seen increases and supply limitations for the services we procure. Any such shortages or delays and price increases could adversely affect our ability to execute our drilling program.
Our activities are regulated by complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to various U.S. and Canadian federal, state, provincial and local government laws and regulations that could change in response to economic or political conditions. Matters that are typically regulated include:

discharge permits for drilling operations;

water obtained for drilling purposes;

drilling permits and bonds;

reports concerning operations;

spacing of wells;

disposal wells;

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 are subject to environmental laws, regulations and permits, including greenhouse gas requirements, which may expose us to significant costs, liabilities and obligations.
We are subject to stringent and complex U.S. and Canadian federal, state, provincial and local environmental laws, regulations and permits relating to, among other things, the generation, storage, handling, use, disposal, gathering, transmission and remediation of natural gas, NGLs, oil and other hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife, habitat, water and wetlands protection; the storage, use, treatment and disposal of water, including process water; the placement, operation and reclamation of wells; and the health and safety of our employees. These requirements may impose operational restrictions and remediation obligations. In particular, many of these requirements are intended to help preserve water resources and regulate those aspects of our operations that could potentially impact surface water or groundwater. Failure to comply with these laws, regulations and permits may result in our being subject to litigation, fines or other sanctions, including the revocation of permits and suspension of operations, and could otherwise delay or impede the issuance or renewal of permits. We expect to continue to incur significant capital and other compliance costs related to such requirements.
We could be subject to joint and several strict liability for any environmental contamination at our currently or formerly owned, leased or operated properties or third-party waste disposal sites. In addition to potentially significant investigation and remediation costs, such matters can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.
These laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. For example, federal and state regulators are becoming increasingly focused on air emissions from our industry, including volatile organic compound emissions, which increased scrutiny could lead to heightened enforcement of existing regulations as well as the imposition of new air emission measures. With respect to GHG emissions, we are currently required to report annual GHG emissions from certain of our operations, and additional GHG emission related requirements have been implemented or are in various stages of development. Any current or future GHG or other air emission requirements could curtail our operations or otherwise result in operational delays, liabilities and increased compliance costs. In addition, to the extent climate change results in more severe weather, our or our customers’ operations may be disrupted, which could curtail our exploration and production activity, increase operating costs and reduce product demand.
Our costs, liabilities and obligations relating to environmental matters could have a material adverse effect on our business, reputation, results of operations and financial condition.
Our hydraulic fracturing operations are subject to laws and regulations that could expose us to increased costs and additional operating restrictions and delays, and adversely affect production.
We rely and expect to continue to rely upon hydraulic fracturing. Various federal, state, provincial and local initiatives have been implemented or are under development to regulate or further investigate the environmental impacts of hydraulic fracturing. In particular, the EPA has commenced a study to determine the environmental and health impacts of hydraulic fracturing and announced that it will propose standards for the treatment or disposal of wastewater from certain gas production operations. In July 2011, the EPA also proposed new air standards that would require measures to reduce volatile organic compound emissions at new hydraulically fractured natural gas wells and existing wells that are re-fractured. In addition, certain municipalities and states in which we operate, including Colorado, Montana, Texas and Wyoming, have adopted, or are considering adopting, regulations that have imposed, or could impose, more stringent permitting, transparency, disposal and well construction requirements on hydraulic fracturing operations. For example, in December 2011, the Railroad
Commission of Texas and the Colorado Oil and Gas Conservation Commission finalized regulations requiring public disclosure of chemicals in fluids used in the hydraulic fracturing process. Similar regulations exist in British Columbia. Local ordinances or other regulations also may regulate or prohibit the performance of well drilling in general and hydraulic fracturing in particular. Such laws and regulations may result in increased scrutiny or third-party claims, or otherwise result in operational delays, liabilities and increased costs.
Hydraulic fracturing requires significant quantities of water. Recently, Texas has been experiencing a drought. Any diminished access to water for use in hydraulic fracturing in Texas or other locations in which we operate, whether due to usage restrictions or drought or other weather conditions, could curtail our operations or otherwise result in operations delays or increased costs. Any current or future federal, state, provincial or local hydraulic fracturing requirements applicable to our operations, or diminished access to water for use in hydraulic fracturing, could have a material adverse effect on our business, results of operations and financial condition.
The risks associated with our debt could adversely affect our business, financial condition, and results of operations, and could cause our securityholders to experience a partial or total loss of their investment in us.
Subject to the limits contained in our various debt agreements, we may incur additional debt. Our ability to incur additional debt and to comply with the terms of our debt agreements is affected by a variety of factors, including commodity prices and their effects on our proved reserves, financial condition, results of operations and cash flows. In addition, we expect our ability to borrow under our Combined Credit Agreements will depend on our borrowing base, which will be redetermined at least twice each year based on our reserve reports and such other information deemed appropriate by the administrative agent in a manner consistent with its normal oil and gas lending criteria as it exists at the time of the redetermination. If we incur additional debt or fail to increase the quantity and value of our proved reserves, the risks that we expect to face as a result of our indebtedness could intensify.
We have demands on our cash resources, including operating expense, funding of our capital expenditures and the interest expense we expect to have on our outstanding debt. Our level of debt, the value of our oil and gas properties and other assets, the demands on our cash resources, and the provisions of our outstanding debt could have important effects on our business and on the value of our securities. For example, the provisions of our outstanding debt could:

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 cannot assure you that we would be able to implement any of these strategies on satisfactory terms, if at all, and our inability to do so could cause our securityholders to experience a partial or total loss of their investment in us.
The provisions of our debt agreements and the risks associated with our debt could adversely affect our business, financial condition and results of operations.
Our debt agreements restrict our ability to, among other things:

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;

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 financial covenants that are more fully described in Note 11 to our consolidated financial statements found in Item 8 of this Annual Report. Our ability to comply with the covenants and other provisions of our debt agreements may be affected by events beyond our control, and we may be unable to comply with all aspects of our debt agreements in the future. In addition, our ability to borrow under our Combined Credit Agreements is dependent upon the quantity and value of our proved reserves and other assets.
The provisions of our debt agreements may affect the manner in which we obtain future financing, pursue attractive business opportunities and plan for and react to changes in business conditions. In addition, failure to comply with the provisions of our debt agreements could result in an event of default which could enable the applicable creditors to declare the outstanding principal and accrued interest to be immediately due and payable. Moreover, any of our debt agreements that contain a cross-default or cross-acceleration provision could also be subject to acceleration. If we were unable to repay the accelerated amounts, the creditors could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, we may have insufficient assets to repay such debt in full, and the holders of our securities could experience a partial or total loss of their investment.
Parties with whom we do business may become unable or unwilling to timely perform their obligations to us.
We enter into contracts and transactions with various third parties, including contractors, suppliers, customers, lenders and counterparties to hedging arrangements, under which such third parties incur performance or payment obligations to us. Any delay or failure on the part of one or more of such third parties to perform their obligations to us could, depending upon the nature and magnitude of such failure or failures, have a material adverse effect on our business, financial condition and results of operations.
The operations of the third parties on whom we rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state, provincial and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations.
We have substantial financial and other commitments related to our development of a gathering, processing and transportation system for Horn River.
We have agreed to provide NOVA Gas Transmission Ltd. (“NGTL”) with letters of credit to cover its costs to construct a pipeline and meter station (the “project”) that will connect the gas produced from our Horn River
Asset, to NGTL’s Alberta System (the “Horn River Mainline”). Our financial exposure is staged in increments as the project is built and ultimately, the costs for the project are estimated to be C$257 million including taxes of approximately C$28 million. Upon completion of the project, the requirement to provide the letters of credit will terminate.
We have also committed to deliver gas from our Horn River Asset for gathering and transport and must pay fees related to those services whether or not we deliver gas. These commitments are presented in Delivery Commitments and Purchases of Natural Gas, NGLs and Oil in Item 1. Our ability to fund these commitments may be affected by economic and capital markets conditions and other factors that may be beyond our control. In addition, we only have 99.3 MMcf of proved reserves our Horn River Asset as of December 31, 2011. Accordingly, our ability to deliver up to 1 Tcf of gas depends upon our ability to drill additional successful wells in our Horn River Asset, find third-party sources to supplement or satisfy our obligation or to pay a demand charge. Failure to satisfy our financial or other commitments could have a material adverse effect on our business, results of operations and financial condition.
If we do not make acquisitions on economically acceptable terms, our future growth will be limited.
In addition to expanding production from our current reserves, we may pursue acquisitions. If we are unable to make these acquisitions because we are: (1) unable to identify attractive acquisition candidates, to analyze acquisition opportunities successfully from an operational and financial point of view or to negotiate acceptable purchase contracts with them; (2) unable to obtain financing for these acquisitions on economically acceptable terms; or (3) outbid by competitors, then our future growth could be limited. Furthermore, even if we do make acquisitions, these acquisitions may not result in an increase in the cash generated by operations.
Any acquisition involves potential risks, including, among other things:

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

an inability to integrate successfully the assets we acquire;

the assumption of unknown liabilities;

limitations on rights to indemnity from the seller;

mistaken assumptions about the overall costs of equity or debt;

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

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

customer or key employee losses at the acquired businesses.
Drilling locations that we decide to drill may not meet our pre-drilling expectations, may not yield oil or natural gas in commercially viable quantities and are susceptible to uncertainties that could materially alter the occurrence, timing or success of drilling.
As of December 31, 2011, we had 393 proved undeveloped locations with proved undeveloped reserves. These identified drilling locations represent an important part of our strategy. Our ability to execute our drilling program is subject to a number of uncertainties, including the availability of capital, regulatory approvals, commodity prices, costs and drilling results. In addition, the cost and timing of drilling, completing, and operating any well are often uncertain, and new wells may not be productive. We cannot assure you that the analogies we draw from available data from other wells will be applicable to our identified drilling locations. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. Because of these uncertainties, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. The failure to drill our identified drilling locations on a timely basis or the failure of our drilling locations to yield oil or natural gas in commercially viable quantities could cause a decline in our proved reserves and adversely affect our results of operations.
Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when operating wells that they own.
Many of our properties are in areas that may have already been partially depleted. The owners of leasehold interests lying contiguous or adjacent to or adjoining any of our properties could take actions, such as drilling additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids towards the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, operations conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time for completion operations and other activities conducted on those properties, could result in increased lease operating expense and could adversely affect the production from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
Horn River is in an early stage of development and has limited infrastructure.
Our Horn River Asset is at an early stage of development. As such, there is limited information on reservoir quality and continuity which may affect the development schedule and well spacing requirements to fully recover the natural gas reserves. Additionally, the infrastructure in our Horn River Asset is still in development, which could lead to delays or unexpected costs associated with getting our production to market.
Aboriginal peoples hold certain constitutionally protected rights in Canada that could materially affect our business, financial condition and results of operations.
Aboriginal peoples in Canada hold certain constitutionally protected rights pursuant to historic occupation of lands, historic customs and treaties with governments. Such rights may include, among other things, rights to access lands, and hunting and fishing rights. The extent and nature of aboriginal rights vary from place to place in Canada, depending on historic and contemporary circumstances. All of our Horn River Asset acreage is covered by overlapping aboriginal rights claims. We are not aware that any claims have been made against us in respect of our properties and assets in connection with aboriginal rights; however, if a claim arose and was successful, such claim may have a material adverse effect on our business, financial condition and results of operations. In addition, prior to making decisions that may adversely affect existing or claimed aboriginal rights, governments in Canada have a duty to consult with aboriginal people potentially affected, and in some instances, a duty to accommodate concerns raised through such consultation. Regulatory authorizations for our operations may be affected by the time required for the completion of aboriginal consultation and operational restrictions imposed by governmental authorities pursuant to such consultation may materially affect our business, financial condition and results of operations.
A significant increase in the differential between the NYMEX price or other benchmark prices and the prices we receive for our production could adversely affect our financial condition.
The prices that we receive for our production often reflect a regional discount, based on the location of production, to the relevant benchmark prices, such as NYMEX, that are used for calculating the fair value of our commodity derivatives. Although there has been a demonstrated and consistent basis spread between NYMEX and where we sell our production, any increase in these differentials, if significant, could adversely affect our financial condition.
The recent adoption of the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, could have an adverse effect on our ability to use derivatives to reduce the effect of commodity price risk, interest rate and other risks associated with our business.
We use commodity derivatives to manage our commodity price risk. The U.S. Congress recently adopted comprehensive financial reform legislation that, among other things, establishes comprehensive federal oversight and regulation of over-the-counter derivatives and many of the entities that participate in that market. Although the Dodd-Frank Act was enacted on July 21, 2010, the Commodity Futures Trading Commission (the “CFTC”)
and the SEC, along with certain other regulators, must promulgate final rules and regulations to implement many of its provisions relating to over-the-counter derivatives. While some of these rules have been finalized, many have not and, as a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.
In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain, energy commodity futures and options contracts and economically equivalent swaps, futures and options. The position limit levels set the maximum amount of a contract that a trader may own or control separately or in combination, net long or short. The final rules also contain limited exemptions from position limits for certain bona fide hedging transactions and positions that were established in good faith before the initial limits become effective. The final rules became effective on January 17, 2012, but position limits will be phased in over time according to a specified schedule and the implementation of certain position limits is dependent on finalization of certain other rules to be jointly promulgated by the CFTC and the SEC. In addition, on December 2, 2011, the International Swaps and Derivatives Association, Inc. and the Securities Industry and Financial Markets Association filed a legal challenge to the final rules, claiming, among other things, that the rules may adversely impact commodities markets and market participants, including end-users, by reducing liquidity and increasing price volatility.
While the timing of implementation of the final rules on position limits, their applicability to, and impact on, us and the success of any legal challenge to their validity remain uncertain, there can be no assurance that they will not have a material adverse impact on us by affecting the prices of or market for commodities relevant to our operations and/or by reducing the availability to us of commodity derivatives. The Dodd-Frank Act will also impose a number of other new requirements on certain over-the-counter derivatives that may have a material adverse effect on us. The Dodd-Frank Act will also subject certain swap dealers and major swap participants to significant new regulatory requirements which in certain cases may cause them to conduct their activities through new entities that may not be as creditworthy as our current counterparties. The impact of this new regulatory regime on the availability, pricing and terms and conditions of commodity derivatives remains uncertain, but there can be no assurance that it will not have a materially adverse effect on our ability to hedge our exposure to commodity prices.
In addition, under Dodd-Frank swap dealers and major swap participants will be required to collect initial and variation margin from certain end-users of over-the-counter derivatives. While rules implementing many of these requirements have been proposed by relevant regulators, not all have been finalized and therefore the timing of their implementation and their applicability to us remains uncertain. Depending on the final rules and definitions ultimately adopted, we might in the future be required to post collateral for some or all of our derivative transactions. Posting of collateral could cause liquidity issues for us by reducing our ability to use our cash or other assets for capital expenditures or other corporate purposes and could therefore reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus protect cash flows.
If we reduce our use of derivatives as a result of the Dodd-Frank Act, the regulations promulgated under it and the changes to the nature of the derivatives markets, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. In addition, the Dodd-Frank Act was intended, in part, to reduce the volatility of commodity prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to natural gas, NGLs and oil. Our revenue could, therefore, be adversely affected if commodity prices were to decrease.
Lastly, the Dodd-Frank Act requires, no later than 270 days after the enactment of the Act, the SEC to promulgate rules requiring SEC reporting companies that engage in the commercial development of oil, natural gas or minerals, to include in their annual reports filed with the SEC disclosure about all payments (including taxes, royalties, fees and other amounts) made by the issuer or an entity controlled by the issuer to the United States or to any non-U.S. government for the purpose of commercial development of oil, natural gas or minerals. As these rules are not yet effective, we are unable to predict what form these rules may take and whether we will be able to comply with them without adversely impacting our business, or at all. Any of these consequences could have a material adverse effect on our business, financial condition and results of operations.
The loss of key personnel could adversely affect our ability to operate.
Our operations are dependent on a relatively small group of key management personnel, including our executive officers. There is a risk that the services of all of these individuals may not be available to us in the future. Because competition for experienced personnel in our industry can be intense, we may be unable to find acceptable replacements with comparable skills and experience and their loss could adversely affect our ability to operate our business.
A small number of existing stockholders exercise significant control over our company, which could limit your ability to influence the outcome of stockholder votes.
As of February 15, 2012, members of the Darden family, together with entities controlled by them, beneficially owned approximately 30% of our outstanding common stock. As a result, they are generally able to significantly affect the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our charter or bylaws and the approval of mergers and other significant corporate transactions.
Our amended and restated certificate of incorporation, restated bylaws and stockholder rights plan contain provisions that could discourage an acquisition or change of control without our board of directors’ approval.
Our amended and restated certificate of incorporation and restated bylaws contain provisions that could discourage an acquisition or change of control without our board of directors’ approval. In this regard:

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 adopted a stockholder rights plan, which could also impede a merger, consolidation, takeover or other business combination involving us, even if that change of control might be beneficial to stockholders, thus increasing the likelihood that incumbent directors will retain their positions. In certain circumstances, the fact that corporate devices are in place that will inhibit or discourage takeover attempts could reduce the market value of our common stock.
If our plan to separate certain of our Barnett Shale assets into a new publicly-traded master limited partnership is delayed or not completed, our stock price may decline and our growth potential may not be enhanced.
On October 19, 2011, we announced a plan to separate certain of our mature onshore oil and gas properties in our Barnett Shale Asset into a new publicly-traded master limited partnership (“MLP”). On February 10, 2012, MLP filed an initial registration statement on Form S-1 in connection with this planned initial public offering. Completion of this plan is subject to market conditions and numerous other risks beyond our control, including, but not limited to, the general economy, credit markets, equity markets and energy prices. Therefore, it is possible that MLP will not complete an offering of securities, will not raise the planned amount of capital even if an offering of securities is completed and will not be able to complete its proposed actions on the desired timetable. Furthermore, the structure, nature, purpose, and proposed manner of offering of MLP may change materially from those anticipated. If the transaction is not completed or delayed, our stock price may decline and our growth potential may not be enhanced.
If completed, our plan to separate portions of our Barnett Shale Asset may not achieve its intended results and could have an adverse effect on us due to a number of factors. Following the completion of the planned initial public offering, we will initially be the largest unitholder of MLP, holding common units, subordinated units and incentive distribution rights. We cannot assure you that the trading price of our common stock, which will include our retained investment in MLP, as adjusted for any changes in the combined capitalization of these companies, will be equal to or greater than the trading price of our common stock prior to the planned initial public offering of MLP.
In addition, MLP, and therefore our retained investment in MLP, will be subject to the risks normally attendant to businesses in the oil and natural gas industry, including most of the same risks to which we are subject.
Our announcement of this plan did not, and this risk factor does not, constitute an offer to sell or the solicitation of an offer to buy any securities. Any offers, solicitations of offers to buy, or any sales of securities of MLP will be made only in accordance with the registration requirements of the Securities Act of 1933 or an exemption therefrom.
We have identified a material weakness in our internal controls that, if not properly corrected, could result in material misstatements in our financial statements.
We have identified a material weakness in our system of internal control over financial reporting as of December 31, 2011. A material weakness is a deficiency, or combination of deficiencies in internal controls over financial reporting that results in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.
The material weakness was related to the design and operating effectiveness of the computation of impairment of our non-oil and gas assets. Specifically, the weakness relates to design deficiencies regarding the assessment of triggering events and the consideration of asset groupings, as well as other deficiencies related to the performance and documentation of a recovery test and other fair value computational matters. In response to the identification of the material weakness, management has enhanced its process for documenting identification of impairment indicators, and the preparation and review of undiscounted recovery tests and discounted cash flow analyses. Significant deficiencies as of December 31, 2011 related to the Company’s calculation of its asset retirement obligation and exclusion of certain future development costs from the depletion calculation. In response to the identification of the significant deficiencies, management has enhanced the process for preparation and review of the inputs to the asset retirement obligation and the depletion calculation. Management believes that these enhancements and improvements, when repeated as applicable in future periods, remediate the material weakness and significant deficiencies described above.
Although there can be no assurances, we believe these enhancements and improvements, when repeated in future periods, will remediate the control deficiencies described above. If we are not able to remedy the control deficiencies in a timely manner, we may be unable to provide holders of our securities with the required financial information in a timely and reliable manner and we may incorrectly report financial information, either of which could subject us to litigation and regulatory enforcement actions.
ITEM 1B.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 2.
ITEM 2. Properties
A detailed description of our significant properties and associated 2011 developments can be found in Item 1 of this Annual Report, which is incorporated herein by reference.
ITEM 3.
ITEM 3. Legal Proceedings
We are a defendant in lawsuits from time to time in the normal course of business. We are not party to any legal proceedings that, based on facts currently available, management believes will, individually or in the aggregate, have a material adverse effect on Quicksilver’s business, operating results, financial condition or cash flows. In addition, allegations against our Executive Vice President - Operations in the District Court of Cleveland County, Oklahoma were dismissed on January 17, 2012.
ITEM 4.
ITEM 4. Mine Safety Disclosures
Not applicable.
PART II.
ITEM 5.
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.
As of March 30, 2012, there were approximately 742 common stockholders of record.
We have not paid cash dividends on our common stock and intend to retain our cash flow from operations for the future operation and development of our business. In addition, we have debt agreements that restrict payments of dividends.
Performance Graph
The following performance graph compares the cumulative total stockholder return on Quicksilver common stock (KWK) with the Standard & Poor’s 500 Stock Index (the “S&P 500 Index”), the Standard & Poor’s 500 Exploration and Production Index (the “S&P 500 E&P Index”, also commonly referred to as the “S&P Midcap Oil, Gas, and Consumable Fuels Index”), and the Standard & Poor’s 400 Oil and Gas Index (the “S&P 400 Oil and Gas Index”) for the period from December 31, 2006 to December 31, 2011, assuming an initial investment of $100 and the reinvestment of all dividends, if any. In 2011, we changed from using the published index, the S&P Midcap Oil, Gas, and Consumable Fuels Index, to the S&P 400 Oil and Gas Index because we believe the S&P 400 Oil and Gas Index is a closer representation of our peer group and thus will depict a more reasonable correlation of KWK returns to the peer average.
Comparison of Cumulative Five Year Total Return
Issuer Purchases of Equity Securities
The following table summarizes our repurchases of Quicksilver common stock during the quarter ended December 31, 2011.
(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.
ITEM 6.
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:
(1) Per share amounts have been adjusted to reflect a two-for-one stock split effected in the form of a stock dividend in January 2008.
(2) Operating income for 2011 includes gains of $217.9 million from the sale of BBEP Units. Operating income also includes charges for impairment of $58.0 million and $49.1 million for our HCDS and certain midstream assets in Texas, and Canadian oil and gas properties, respectively.
(3) Operating income for 2010 includes gains of $494.0 million and $57.6 million from the sales of KGS and BBEP Units, respectively. Operating income also includes charges for impairment of $28.6 million and $19.4 million for our HCDS and Canadian oil and gas properties, respectively.
(4) Operating loss for 2009 includes charges of $786.9 million and $192.7 million for impairments associated with our U.S. and Canadian oil and gas properties, respectively. Net loss also includes $75.4 million of income attributable to our proportionate ownership of BBEP and a charge of $102.1 million for impairment of that investment.
(5) Operating loss for 2008 includes a charge of $633.5 million for impairment associated with our U.S. oil and gas properties. Net loss also includes $93.3 million for pre-tax income attributable to our proportionate ownership of BBEP and a pre-tax charge of $320.4 million for impairment of that investment.
(6) Operating income for 2007 include a gain of $628.7 million recognized from the divestiture of our Michigan, Indiana and Kentucky oil and gas properties and other assets and a charge of $63.5 million associated with a natural gas fixed-price sales contract that expired in March 2009 under which we no longer delivered natural gas produced from properties owned or operated by us.
(7) Note 2 to the consolidated financial statements in Item 8 contains additional information regarding the immaterial restatement to the 2010 results of operation primarily for the revised gain on sale of our interests in KGS and to a lesser extent additional depletion expense.
ITEM 7.
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following Management’s Discussion and Analysis (“MD&A”) is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Annual Report. Until the sale of all of our interests in KGS, we conducted our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller midstream segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis.
Note 2 to the consolidated financial statements in Item 8 contains additional information regarding the immaterial restatement to the 2010 results of operations primarily for the restated gain on sale of our interests in KGS and to a lesser extent additional depletion expense. Accordingly, Management’s Discussion and Analysis of Financial Condition and Results of Operations has been revised for the effects of the immaterial restatement.
Our MD&A includes the following sections:

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

2011 Highlights - a summary of significant activities and events affecting Quicksilver

2012 Capital Program - a summary of our planned capital expenditures during 2012

Financial Risk Management - information about debt financing and financial risk management

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

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

Critical Accounting Estimates - a discussion of critical accounting estimates that represent choices between acceptable alternatives and/or require management judgments and assumptions.
OVERVIEW
We are an independent oil and gas company engaged primarily in the acquisition, exploration, development, and production of onshore oil and gas based in Fort Worth, Texas. We focus primarily on unconventional reservoirs where hydrocarbons may be found in challenging geological conditions such as fractured shales, coalbeds and tight sands. We generate revenue, income and cash flows by producing and selling natural gas, NGLs and oil. We conduct acquisition, exploration, development, and production activities to replace the reserves that we produce.
At December 31, 2011, 77% and 22% of our proved reserves were natural gas and NGLs, respectively. Consistent with one of our business strategies, we continue to develop our unconventional resources by applying our expertise to our development projects in our Barnett Shale Asset, Horseshoe Canyon Asset and Horn River Asset, which had 88%, 8% and 4%, respectively, of our proved reserves at December 31, 2011. During 2011, based on the success of our exploration in our Horn River Asset, we began to consider this a development area, particularly in the southern portion of our acreage. Our acreage in our Horn River Asset provides us the most immediate additional opportunity for further application of our unconventional resources expertise.
We focus on three key value drivers:

reserve growth;

production growth; and

maximizing our operating margin.
Our reserve growth relies on our ability to apply our technical and operational expertise to explore and develop unconventional reservoirs. We strive to increase reserves and production through aggressive
management of our operations and through relatively low-risk developmental drilling. We will also continue to identify high-potential exploratory projects with comparatively higher levels of financial risk. All of our development and exploratory programs are aimed at providing us with opportunities to develop unconventional reservoirs.
We believe the acreage we hold in our core operating areas is well suited for production increases through developmental drilling. We perform workover and infrastructure projects to reduce ongoing operating costs and enhance current and future production rates. We regularly review the properties we operate to determine if steps can be taken to efficiently increase reserves and production.
In evaluating the results of our efforts, we consider the capital efficiency of our drilling program and also measure the following key indicators, whose recent results are shown below:
(1) This ratio is calculated by subtracting beginning of the year proved reserves from adjusted end of the year proved reserves and dividing by beginning of the year proved reserves. Adjusted end of the year reserves are calculated by adding back divested reserves and production and deducting acquired reserves from end of the year reserves.
2011 HIGHLIGHTS
Master Limited Partnership
In October 2011, we announced our intention to file a registration statement on Form S-1 with the SEC in connection with the initial issuance of common units representing limited partner interest in a proposed master limited partnership (the “MLP”). We expect the MLP will use the proceeds from the sale of common units and borrowings under a planned new bank credit facility as consideration of certain of our Barnett Shale assets. We will retain a significant ownership position in the MLP and will own 100% of the general partner.
Fortune Creek
In December 2011, we announced the formation of Fortune Creek, a midstream partnership with KKR, dedicated to the construction and operation of midstream services to support us and potential producer customers primarily in British Columbia, Canada. The highlights of the transaction include:

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

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

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

We will be the operator of the partnership;

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

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

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

The formation of an area of mutual interest for the midstream business covering approximately 30 million potential acres in Horn River, Liard and Cordova basins in British Columbia and the Northwest Territories, which is expected to include third-party transportation and processing infrastructure and agreements.
New Credit Facilities
In September 2011, we terminated and replaced our $1.0 billion global 2007 Senior Secured Credit Facility with new separate five-year syndicated senior secured revolving credit facilities for our U.S. and Canadian operations. The $1.25 billion Initial U.S. Credit Facility had a borrowing base of $850 million, including a letter of credit capacity of $75 million, as of September 30, 2011. The C$500 million Initial Canadian Credit Facility had a borrowing base of C$225 million, including a letter of credit capacity of C$100 million, as of September 30, 2011.
During December 2011, the Initial U.S. Credit Facility and the Initial Canadian Credit Facility were amended and restated by the Combined Credit Agreements. The $1.75 billion Combined Credit Agreements have a global borrowing base of $1.075 billion, including a global letter of credit capacity of $175 million, as of December 31, 2011.
We are currently working with our lending group of banks to establish a revolving credit facility for the MLP. When it becomes effective, we expect the borrowing base on the Combined Credit Facility to be reduced by $200 million. We expect the MLP credit facility to have an initial borrowing base of $275 million at the closing of the facility.
Convertible Debentures
On November 1, 2011, we repurchased substantially all of our outstanding convertible debentures for $150.0 million, after they were presented to us for repurchase by debenture holders. The repurchase transaction was completed utilizing borrowings from the Initial U.S. Credit Facility. During the first quarter of 2012, we repurchased the remaining debentures.
Emerging Basins
We have built an acreage position of 260,000 acres in the Sandwash basin of northwestern Colorado in a 900- square mile fairway prospective for the Niobara and Lower Mancos Shales. We drilled and completed seven vertical wells through December 2011, and drilled our first horizontal well in the fourth quarter of 2011 with initial production results of 500 bbld and completed approximately 3,000 lateral feet, which is half of the length of the lateral we plan to ultimately drill. We expect to drill and complete four to seven horizontal wells in 2012.
We have also built a 155,000 acre position in the Midland and Delaware basins of West Texas prospective in the Bone Springs and Wolfcamp formations and principally concentrated in four core areas: Jeff Davis and Reeves Counties, Upton and Crockett Counties, Pecos County and Presidio County. In early 2012, we retained an investment bank to help evaluate the opportunities for a joint venture partner to help exploit our West Texas acreage.
Sale of BBEP Units
During 2011, we sold 15.7 million BBEP Units for aggregate proceeds of $273.0 million, recognizing total gains of $217.9 million in our income statement as other income. At December 31, 2011, we no longer owned any BBEP Units.
2012 CAPITAL PROGRAM
We expect our 2012 capital program to be spent in the following areas:
The chart above does not include approximately $40 million of overhead and interest expense that may be ordinarily capitalized and corporate and administrative capital.
FINANCIAL RISK MANAGEMENT
We have established internal control policies and procedures for managing risk within our organization. The possibility of decreasing prices received for our natural gas, NGL and oil production is among the several risks that we face. We seek to manage this risk by entering into derivative contracts which we strive to account for as hedges. We have mitigated the downside risk of adverse price movements through the use of these derivatives but, in doing so, have also limited our ability to benefit from favorable price movements. Our commodity price strategy enhances our ability to execute our development and exploration programs, meet debt service requirements and pursue acquisition opportunities even in periods of price volatility or depression. Item 7A
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We enter into financial derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future production and to increase the predictability of our revenue. As of December 31, 2011, the following forecasted production has been hedged with price collars or price swaps.
Utilization of our financial hedging program will most often result in realized prices from the sale of our natural gas, NGL and oil that vary from market prices. As a result of settlements of derivative contracts, our revenue from natural gas, NGL and oil production was greater by $84.8 million, $248.9 million and $310.9 million for 2011, 2010 and 2009, respectively.
The following table details our open derivative positions at December 31, 2011:
During February 2012, we revamped our hedge platform. Through terminations of a portion of our existing natural gas hedge positions, we executed a new series of hedges that accomplish a revised natural gas hedging platform of:
These hedges did not result in the transfer or the receipt of any net cash proceeds. We expect our entire hedge portfolio to continue to qualify for hedge accounting.
The fair value of all derivative instruments included in these disclosures was estimated using prices quoted in markets for the periods covered by the derivatives and the value confirmed by counterparties. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives.
Interest Rate Risk
In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We deferred gains of $30.8 million as a fair value adjustment to our debt, which we began to recognize over the life of the associated debt instruments. For 2011, 2010 and 2009, interest expense decreased $4.8 million, $14.0 million and $13.7 million, respectively, because of our interest rate swaps.
Should we be required to borrow under our Combined Credit Agreements and based on interest rates as of December 31, 2011, each $50 million in borrowings would result in additional annual interest payments of $1.1 million. If the current borrowing availability under our Combined Credit Agreements were to be fully utilized by year-end 2012 at interest rates as of December 31, 2011, we estimate that annual interest payments would increase by $26.1 million. If interest rates change by 1% on our December 31, 2011 variable debt balances of $227.5 million our annual pre-tax income would decrease or increase by $2.3 million.
In the future, we may enter into interest rate derivative contracts on a portion of our outstanding debt to mitigate the risk of fluctuation of rates or manage the floating versus fixed rate risk.
Foreign Currency Risk
Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. For 2011, 2010 and 2009, non-functional currency transactions resulted in losses of $2.5 million, $0.5 million, and $2.2 million, respectively, included in net earnings. Furthermore, the Amended and Restated Canadian Credit Facility permits Canadian borrowings to be made in either U.S. or Canadian-denominated amounts. However, the aggregate borrowing capacity of the entire facility is calculated using the U.S. dollar equivalent. Accordingly, there is a risk that exchange rate movements could impact our available borrowing capacity.
ITEM 8.
ITEM 8. Financial Statements and Supplementary Data
QUICKSILVER RESOURCES INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Quicksilver Resources Inc.
Fort Worth, Texas
We have audited the accompanying consolidated balance sheets of Quicksilver Resources Inc. and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of income (loss) and comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Quicksilver Resources Inc. and subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, on December 31, 2009, the Company adopted Accounting Standards Update No. 2010-3, “Oil and Gas Reserve Estimation and Disclosures.”
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 15, 2012 expressed an adverse opinion on the effectiveness of the Company's internal control over financial reporting because of a material weakness.
/s/ Deloitte & Touche LLP
Fort Worth, Texas
April 15, 2012
QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
In thousands, except for per share data
(1) Note 2 contains additional information.
The accompanying notes are an integral part of these consolidated financial statements.
QUICKSILVER RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2011 AND 2010
In thousands, except for share data
(1) Note 2 contains additional information.
The accompanying notes are an integral part of these consolidated financial statements.
QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
In thousands
(1) Note 2 contains additional information.
The accompanying notes are an integral part of these financial statements.
QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS END DECEMBER 31, 2011, 2010 AND 2009
In thousands
(1) Note 2 contains additional information.
The accompanying notes are an integral part of these consolidated financial statements.
QUICKSILVER RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009
1.
NATURE OF OPERATIONS
We are an independent oil and gas company incorporated in the state of Delaware and headquartered in Fort Worth, Texas. We engage in the acquisition, exploration, development, production and sale of natural gas, NGLs and oil in North America. As of December 31, 2011, our significant oil and gas reserves and operations are located in:
•
Texas
•
U.S. Rocky Mountains
•
Alberta
•
British Columbia
We have offices located in:
•
Fort Worth, Texas
•
Glen Rose, Texas
•
Cut Bank, Montana
•
Steamboat Springs, Colorado
•
Calgary, Alberta
•
Fort Nelson, British Columbia
Our results of operations are largely dependent on the difference between the prices received for our natural gas, NGL and oil products and the cost to find, develop, produce and market such resources. Natural gas, NGL and oil prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond our control. These factors include worldwide political instability, quantities of natural gas in storage, foreign supply of natural gas and oil, the price of foreign imports, the level of consumer demand and the price of available alternative fuels. We actively manage a portion of the financial risk relating to natural gas, NGL and oil price volatility through derivatives.
2.
SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our consolidated financial statements include our accounts and all of our majority-owned subsidiaries and companies over which we exercise control through majority voting rights or other means of control. We eliminate all inter-company balances and transactions in preparing consolidated financial statements. We account for our ownership in unincorporated partnerships and companies, including BBEP, under the equity method when we have significant influence over those entities, but because of terms of the ownership agreements, we do not meet the criteria for consolidation of the entities.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates.
Significant estimates underlying these financial statements include the estimated quantities of proved natural gas, NGL and oil reserves (including the associated future net cash flows from those proved reserves) used to compute depletion expense, the full cost ceiling limitation and estimates of current revenue. Other estimates that require assumptions concerning future events and substantial judgment include the estimated fair values of
derivatives, asset retirement obligations and employee stock-based compensation. Income taxes also involve the use of considerable judgment in the estimation and evaluation of deferred income tax assets and our ability to recover operating loss carry-forwards and assessment of uncertain tax positions.
Cash Equivalents
Cash equivalents consist of time deposits and liquid debt investments with original maturities of three months or less at the time of purchase.
Accounts Receivable
We sell our natural gas, NGL and oil production to various purchasers. Each of our counterparties is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although we do not require collateral, we require appropriate credit ratings and, in some instances, obtain parental guarantees. Receivables are generally collected within 30 to 60 days. When collections of specific amounts due are no longer reasonably assured, we establish an allowance for doubtful accounts though we have not had a significant instance of nonpayment. During 2011, two purchasers individually accounted for 15% and 11% of cash collected for our consolidated natural gas, NGL and oil sales. During 2010, two purchasers individually accounted for 17% and 12% of cash collected for our consolidated natural gas, NGL and oil sales.
Hedging and Derivatives
We enter into derivatives to mitigate risk associated with the prices received from our natural gas, NGL and oil production. We may also utilize derivatives to hedge the risk associated with interest rates on our outstanding debt. All derivatives are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates.
To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, includes performing regression analysis and is generally based on the most recent relevant historical correlation between the derivative and the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as revenue or interest expense when the underlying transaction occurs.
For derivatives that qualify as cash flow hedges, the effective portions of gains and losses are deferred in accumulated other comprehensive income and recognized in revenue or interest expense in the period in which the hedged transaction is recognized. Gains or losses on derivatives terminated prior to their original expiration date are deferred and recognized as earnings during the period that the hedge covered. If the hedged transaction is no longer probable, the deferred gain or loss would be immediately recorded to earnings. Changes in value of ineffective portions of hedges, if any, are recognized currently as a component of other revenue.
For derivatives that qualify as fair value hedges, such as interest rate swaps, the gains or losses are recognized currently in earnings, while the gains or losses on the hedged items adjust the carrying value of the hedged items and are recognized currently in earnings. Any gains or losses on the derivatives not offset by the gains or losses on the hedged items are recognized as the value of ineffectiveness in the hedge relationships.
We enter into derivatives with counterparties who are our lenders. All versions of our credit facility provide for collateralization of amounts outstanding from our derivatives in addition to amounts outstanding under the facility. Additionally, default on any of our obligations under derivatives with counterparty lenders could result in acceleration of the amounts outstanding under the credit facility. Our credit facility and our internal credit policies require that any counterparties, including facility lenders, with whom we enter into commodity derivatives have credit ratings that meet or exceed BBB- or Baa3 from Standard and Poor’s or Moody’s, respectively. The fair value for each derivative takes credit risk into consideration, whether it be our counterparties’ or our own. Derivatives are classified as current or non-current derivative assets and liabilities, based on the expected timing of settlements.
Investments in Equity Affiliates
During December 2011, we liquidated our investment in BBEP which we had accounted for using the equity method. Prior to this liquidation, we reviewed our investment for impairment whenever events or circumstances indicated that the investment’s carrying amount may not be recoverable. We recorded our portion of BBEP’s earnings during the quarter in which its financial statements become publicly available. Consequently, our 2011, 2010 and 2009 annual results of operations include BBEP’s earnings for the 12 months ended September 30, 2011, 2010 and 2009. Note 7 contains more information on our BBEP investment.
Property, Plant, and Equipment
We follow the full cost method in accounting for our oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in cost centers on a country-by-country basis. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals reduce the accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is calculated and recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves. We may exclude costs associated with unevaluated properties from amounts subject to depletion.
Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (1) estimated future net revenue from proved reserves, discounted at 10% per annum, including the effects of derivatives that hedge our oil and gas revenue, (2) the cost of properties not being amortized, (3) the lower of cost or market value of unproved properties included in the cost being amortized, less (4) income tax effects related to differences between the book and tax basis of the natural gas and oil properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required. Note 8 to these financial statements contains further discussion of the ceiling test.
All other properties and equipment are stated at original cost and depreciated using the straight-line method based on estimated useful lives ranging from five to forty years.
Inventory
Inventories were comprised of $23.2 million and $25.3 million of materials and parts and $2.3 million and $2.1 million of NGLs as of December 31, 2011 and 2010, respectively. Our materials, parts and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, chemicals, operating supplies and ordinary maintenance materials and parts. The materials, parts and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. “Market,” in the context of inventory valuation, represents net realizable value, which is the amount that we are allowed to bill to the joint accounts under joint operating agreements to which we are a party. Impairments for materials and supplies inventories are recorded as lease operating expense in the accompanying consolidated statements of operations.
Asset Retirement Obligations
We record the fair value of the liability for asset retirement obligations in the period in which it is legally or contractually incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is recognized as expense through depletion or depreciation over the asset’s useful life. Changes in the liability for the asset retirement obligations are recognized for (1) the passage of time and (2) revisions to either the timing or the amount of estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted fair value to its estimated settlement value.
Revenue Recognition
Revenue is recognized when title to the products transfer to the purchaser. We use the “sales method” to account for our production revenue, whereby we recognize revenue on all production sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2011 and 2010, our aggregate production imbalances were not material.
Environmental Compliance and Remediation
Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred. Those environmental remediation costs which improve a property are capitalized.
Debt
We record all debt instruments at face value. When an issuance of debt is made at other than par, a discount or premium is separately recorded. The discount or premium is amortized over the life of the debt using the effective interest method. We separately accounted for the liability and equity components of our convertible debentures, which resulted in our recognizing interest expense at our effective borrowing rate in effect at the time of issuance. Note 11 contains further information regarding our convertible debentures.
Income Taxes
Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must reflect tax rates expected to be in effect in years in which the temporary differences reverse. Canadian taxes are calculated at rates expected to be in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested in Canada and thus not considered available for distribution to the parent company. Net operating loss carry-forwards and other deferred tax assets are reviewed annually for recoverability, and, if necessary, are recorded net of a valuation allowance.
Stock-based Compensation
We measure and recognize compensation expense for all share-based payment awards made to employees and directors based on their estimated fair value at the time the awards are granted. Our board of directors may elect to issue awards payable in cash. For all awards, we recognize the expense associated with the awards over the vesting period. The liability for fair value of cash awards is reassessed at every balance sheet date, such that the vested portion of the liability is adjusted to reflect revised fair value through compensation expense.
Disclosure of Fair Value of Financial Instruments
Our financial instruments include cash, time deposits, accounts receivable, notes payable, accounts payable, long-term debt and financial derivatives. The fair value of long-term debt is estimated as the present value of future cash flows discounted at rates consistent with comparable maturities and includes consideration of credit risk. The carrying amounts reflected in the balance sheet for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value.
Foreign Currency Translation
Our Canadian subsidiary maintains its general ledger using the Canadian dollar. All balance sheet accounts of our Canadian operations are translated into U.S. dollars at the period end exchange rate and statement of income items are translated at the weighted average exchange rate for the period. The resulting translation adjustments are made directly to a component of accumulated other comprehensive income within stockholders’ equity. Gains and losses from foreign currency transactions are included in the consolidated results of operations.
Noncontrolling Interests in Consolidated Subsidiaries
Noncontrolling interests reflect the fractional outside ownership of our majority-owned and consolidated subsidiaries. Until we sold all of our interests in KGS in October 2010, we included the results of operations and financial position of KGS in our consolidated financial statements and recognized the portion of KGS’ results of operations attributable to unaffiliated unitholders as a component of “income attributable to noncontrolling interests.”
Immaterial Restatement
The consolidated financial statements as of and for the year ended December 31, 2010 have been restated to increase the previously recognized gain related to the sale of our interests in KGS by $20.7 million and to provide additional deferred taxes on the increased gain. The previously reported gain excluded certain liabilities for intercompany transactions related to services performed by KGS for our U.S. exploration and production segment, which should have been included in the gain calculation. Additional depletion expense was recognized due to the inclusion of additional future development costs in the 2010 depletion calculation. The results of this restatement, which had no impact on our total cash flow from operations, investing and financing activities as reported, were as follows:
Consolidated Statement of Income (Loss) and Comprehensive Income
For the year ended December 31, 2010
In addition to the restatement as described above, we restated amounts within the condensed consolidating financial information which is more fully described in Note 19. The effects of these restatements did not have an effect on retained earnings as of or prior to December 31, 2009.
Variable Interest Entities
An entity is a variable interest entity (VIE) if it meets the criteria outlined in ASC 810, Consolidation (formerly FASB Interpretation No. 46(R)), which are: (1) the entity has equity that is insufficient to permit the
entity to finance its activities without additional subordinated financial support from other parties, or (2) the entity has equity investors that cannot make significant decisions about the entity’s operations or that do not absorb their proportionate share of the expected losses or receive the expected returns of the entity.
VIEs require assessment of who is the primary beneficiary and for whether the primary beneficiary should consolidate the VIE. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the variable interest entity that most significantly impacts the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. Application of the VIE consolidation requirements may require the exercise of significant judgment by management.
In December 2011, we began to include the financial position of Fortune Creek in our consolidated financial statements. The results from operations for Fortune Creek for 2011 were immaterial. Note 16 contains additional discussion regarding the Fortune Creek.
Earnings per Share
We report basic earnings per common share, which excludes the effect of potentially diluted securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. The calculation of earnings per share is found at Note 18.
Recently Issued Accounting Standards
Accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements materially affecting our financial statements have been issued since the filing of our 2010 Annual Report on Form 10-K.
3.
ACQUISITIONS AND DIVESTITURES
2010 Crestwood Transaction and Midstream Operations
In October 2010, we completed the sale of all of our interests in KGS to Crestwood. The Crestwood Transaction included our conveying:

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

5,696,752 common units of KGS;

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

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

a subordinated promissory note issued to us by KGS with a carrying value of $58 million at September 30, 2010.
We received net proceeds of $700 million including $8.0 million from KGS for third quarter 2010 distributions and after transaction costs. We recognized a gain of $494.0 million. We have the right to collect up to an additional $72 million in future earn-out payments in 2012 and 2013, although we have recognized no assets related to these opportunities. In February 2012, we collected $41 million of these earn-out payments.
Under the agreements governing the Crestwood Transaction, we agreed not to compete with CMLP (to which KGS was renamed) with respect to the gathering, treating and processing of natural gas and the transportation of natural gas liquids in Denton, Hood, Somervell, Johnson, Tarrant, Parker, Bosque and Erath Counties in Texas. We also entered into an agreement with CMLP for the joint development of areas governed by certain of our existing agreements, and further, we amended our existing agreements. The most significant amendments include extending the terms of all gathering agreements with CMLP through 2020 and establishing a fixed gathering rate of $0.55 per Mcf for the gathering system in our Alliance Asset.
In September 2010, our board of directors approved a plan for disposal of the HCDS, which is included in our midstream segment. We conducted an impairment analysis of the HCDS and recognized a charge of $28.6 million for impairment in the third quarter of 2010. During the fourth quarter of 2011, we discontinued our efforts to actively market the HCDS assets to prospective buyers. GAAP also generally limits reporting such items as held for sale to one year. As a result, we have not reported the HCDS in our financial statements as an asset held for sale as of December 31, 2011. Further, we recognized an additional impairment charge of $10.3 million in 2011 for HCDS.
We have continued to report our interests sold in the Crestwood Transaction and the HCDS as part of our continuing operating results because our use of their midstream services constitutes a “continuation of service” that precludes presentation of those businesses as discontinued operations under GAAP.
The operating results of these midstream operations, as classified in our statement of income, are summarized below:
(1) Our KGS operations earned revenue from processing and gathering of our natural gas and NGL production. This revenue was consolidated as a reduction of processing, gathering and transportation expense for purposes of presenting our consolidated statements of income.
Lake Arlington Acquisition
In May 2010, we completed the acquisition of an additional 25% working interest in our company-operated Lake Arlington Asset, for which we conveyed $62.1 million in cash and 3,619,901 BBEP Units owned by us with a market value of $54.4 million on the date of closing. We recognized a gain of $35.4 million as other income for the difference between our carrying value of $5.24 per BBEP Unit and the fair value of $15.03 per BBEP Unit on the date of the transaction.
2009 Eni Transaction
In June 2009, we completed the Eni Transaction whereby we entered into a strategic alliance with Eni and sold a 27.5% interest in our Alliance Asset. The assets were sold to Eni for $279.7 million in cash, inclusive of the Gas Purchase Commitment assumed and normal post-closing adjustments. We used the proceeds generated to repay a portion of the Senior Secured Second Lien Facility.
In connection with the sale, we entered into a gas gathering agreement for a pre-set price with Eni covering Eni’s production. Under that agreement and subsequent agreements, CMLP will gather, treat and deliver Eni’s production. Eni paid $19.2 million to us for construction and installation of the facilities required to gather Eni’s production from future Alliance airport area wells. CMLP is now the sole owner of these facilities and is entitled to recognize gathering revenue for the volume of gas that are gathered.
Also as part of the sale, we entered into a joint development agreement with Eni. The joint development agreement includes a schedule of wells that we agreed to drill and complete with participation by Eni during the development period. In connection with the scheduled drilling of these wells, we have committed to drill and complete a minimum number of lateral feet each year. Eni agreed to pay us a turnkey drilling and completion cost of $994 per linear foot attributable to Eni. Through December 31, 2011 we had cumulatively completed 137,184 linear feet under the agreement, compared with a contract minimum of 130,743 feet. A total of 191,819 linear feet is required to be completed by December 31, 2013. Under the joint development agreement, we may be obligated to pay Eni for damages at the end of the development period should we fail to meet the linear footage requirements and certain production requirements have not been satisfied. We currently expect to satisfy these requirements and have recognized no liability related to non-performance.
4.
DERIVATIVES AND FAIR VALUE MEASUREMENTS
The following table categorizes our commodity derivative instruments based upon the use of input levels:
The fair value of “Level 2” derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value reported by counterparties. The fair value of derivative instruments designated “Level 3” was estimated using prices quoted in markets where there is insufficient market activity for consideration as “Level 2” instruments. Currently, only our natural gas hedges with an original tenure of 10 years utilize “Level 3” inputs, primarily related to comparatively less market data available for their later term compared with our other shorter term hedges. Estimates were determined by applying the net differential between the prices in each derivative and market prices for future periods to the amounts stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at the credit adjusted risk free rate.
The following table identifies the changes in “Level 3” fair values for the periods indicated:
Commodity Price Derivatives
As of December 31, 2011, we had price collars and swaps hedging our anticipated natural gas and NGL production as follows:
On August 31, 2011, we designated our 10-year natural gas swaps as hedges. Unrealized gains of $48.9 million were recognized from the date we entered into them through that date and have been reported in “other revenue.” After the designation date, additional unrealized gains and losses, net of hedge ineffectiveness, have been recognized in AOCI until the associated sale of natural gas production occurs. These gains were partially offset by a decrease in fair value of the related hedge assets due to credit risk of our counterparties as of December 31, 2011.
Interest Rate Derivatives
In June 2009, we entered into interest rate swaps on our $475 million senior notes due 2015 and our $350 million senior subordinated notes effectively converting the interest on those issues from a fixed to a floating rate indexed to a one-month LIBOR. The maturity dates and all other significant terms were the same as those of the underlying debt. Under these swaps, we paid a variable interest rate and received the fixed rate applicable to the underlying debt. The interest income or expense was accrued as earned and recorded as an adjustment to the interest expense accrued on the fixed-rate debt. The interest rate swaps were designated as fair value hedges of the underlying debt. The value of the contracts, excluding the net interest accrual, amounted to a net asset of $4.1 million and a $4.1 million offsetting fair value adjustment to the debt hedged as of December 31, 2009. No ineffectiveness was recorded in connection with the fair value hedges. The 2010 and 2009 average effective interest rates on the 2015 Senior Notes were 6.5% and 5.1%, respectively. The 2010 and 2009 average effective interest rates on the Senior Subordinated Notes were 5.4% and 3.7%, respectively.
In February 2010, we executed the early settlement of the 2009 interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We received cash of $18.0 million in the settlement, including $3.7 million for interest previously accrued and earned, and recognized the remaining $14.3 million as a fair value adjustment to our debt.
In February 2010, we entered into new interest swaps to hedge the same debt instruments. We executed early settlement of a portion of the 2010 interest rate swaps in May 2010 and the remaining 2010 interest swaps
in July 2010 for $6.8 million and $16.7 million, respectively. These settlements included $7.0 million for interest previously accrued and earned. The remaining cash of $16.5 million was recognized as a fair value adjustment to our debt.
The remaining deferral of these early settlements from all interest rate swaps will continue to be recognized as a reduction of interest expense over the life of the associated underlying debt instruments currently scheduled as follows:
Gas Purchase Commitment
We recognized a liability at the time of the Eni Transaction pursuant to the Gas Purchase Commitment based on the estimated production volume attributable to Eni through December 31, 2010, which then totaled 22.2 Bcf. The Gas Purchase Commitment contained an embedded derivative that was adjusted to fair value throughout the period of the commitment, which expired on December 31, 2010. The following summarizes activity to the Gas Purchase Commitment:
All Derivatives
The estimated fair value of all of our derivatives at December 31, 2011 and 2010 were as follows:
The increase in carrying value of our commodity price derivatives since December 31, 2010 principally resulted from the overall decline in market prices for natural gas relative to the prices in our open derivative instruments at December 31, 2011 and due to more coverage of future production. These increases were partially offset by monthly settlements received during 2011.
The changes in the carrying value of our derivatives for 2011 and 2010 are presented below:
Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during 2012 would result in a gain of $86.7 million net of income taxes. Hedge derivative ineffectiveness resulted in net gains of $5.9 million for 2011, and net losses of $2.6 million and $0.1 million for 2010 and 2009, respectively.
5.
ACCOUNTS RECEIVABLE
Accounts receivable consisted of the following:
6.
OTHER CURRENT ASSETS
Other current assets consisted of the following:
7.
INVESTMENT IN BBEP
At December 31, 2011, we no longer owned any BBEP Units. Note 3 contains additional information regarding the use of 3.6 million BBEP Units as partial consideration in the acquisition of oil and gas properties in May 2010. We further reduced our ownership in September 2010 when we sold 1.4 million BBEP Units at a unit price of $16.22, net of fees paid. We recognized a gain of $14.4 million as other income for the difference between our carrying value at the time of the sale of $5.82 per BBEP Unit and the net sales proceeds. In October 2010, we sold an additional 650,000 BBEP Units at a unit price of $17.72 and recognized a gain of $7.7 million.
Our ownership interest in BBEP was further reduced in February 2011 when BBEP issued approximately 4.9 million BBEP Units. During 2011, we eliminated our ownership through the sale of approximately 15.7 million BBEP Units at a weighted average unit sales price of $17.40. We recognized gains of $217.9 million as other income for the difference between our weighted average carrying value of $3.51 per BBEP Unit and the net sales proceeds.
We initially received 21.4 million BBEP Units during November 2007 as partial consideration of our oil and gas properties in Michigan, Indiana and Kentucky. On June 17, 2008, BBEP announced that it had repurchased and retired 14.4 million BBEP Units, which represented 22% of the units previously outstanding. The resulting reduction in the number of BBEP Units outstanding increased our ownership at the time from 32% to 41%.
After obtaining our BBEP Units, we evaluated our investment for impairment in response to decreases in both prevailing commodity prices and the BBEP Unit price. We considered numerous factors in evaluating whether this was an other-than-temporary decline. As a result of the period during which BBEP Units traded below our net carrying value per unit, prevailing petroleum prices and broad limitations on available capital resulted in the determination that this was an other-than-temporary decline. Accordingly, the impairment analysis at December 31, 2008 utilized a price of $7.05 per BBEP Unit, or an aggregate fair value of $150.5 million for our investment in BBEP. The estimated fair value of $150.5 million was then compared to our carrying value of $470.9 million. The difference of $320.4 million was recognized as an impairment charge during 2008.
At March 31, 2009, an additional charge for impairment of $102.1 million was recognized as the closing price of $6.53 per BBEP Unit, or an aggregate fair value of $139.4 million, exceeded our carrying value of $241.5 million. No subsequent impairment of our investment has occurred.
We accounted for our investment in BBEP Units using the equity method, utilizing a one-quarter lag from BBEP’s publicly available information. Summarized financial information for BBEP is as follows:
(1) For the twelve months ended September 30, 2011 and 2009, unrealized gains of $24.0 million and $181.9 million on commodity derivatives were recognized. For the twelve months ended September 30, 2010,
unrealized losses of $12.1 million on commodity derivatives were recognized. Realized gains on commodity derivatives of $70.6 million for the early settlement of derivative positions were included for the twelve months ended September 30, 2009.
(2) An impairment of BBEP’s oil and gas properties of $86.4 million was included for the twelve months ended September 30, 2009.
(3) The twelve months ended September 30, 2011, 2010 and 2009 included $3.3 million, $5.2 million and $11.1 million, respectively, for unrealized gains on interest rate swaps.
Changes in the balance of our investment in BBEP for 2011 and 2010 were as follows:
8.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following:
Ceiling Test Analysis and Impairment
The charges for impairment are summarized below:
As described in Note 2, we are required to perform a quarterly ceiling test for impairment of our oil and gas properties in each of our cost centers. The charge for impairment in 2011 was recognized as a result of a 12% decrease in AECO natural gas price utilized in our Canadian ceiling test from December 31, 2010 to March 31, 2011. The charge for impairment in 2010 was recognized as a result of significant changes in our Canadian cost center for the initial producing wells in our Horn River Asset and associated field costs while new proved reserves recognized were limited because of the short production history for the area. We recognized charges for impairment of both our U.S. and Canadian cost centers during 2009 due to significant decreases in natural gas and NGL market prices.
In September 2010, our board of directors approved a plan for disposal of the HCDS. As a result of the decision, we conducted an impairment analysis of the HCDS and recognized a $28.6 million charge for impairment. During the third quarter 2011, we discontinued our efforts to actively market the HCDS assets and
re-assumed operating it from CMLP at which time we conducted a recovery test for impairment that did not result in an impairment charge. Based on decreased volumes and increased operating costs during the fourth quarter 2011, we recognized additional impairment of $13.3 million determined on a market-based approach to fair value. We also recognized an impairment charge of $44.7 million related to certain Barnett Shale midstream assets to reduce their carrying value to estimated fair value as a result of decreased development by us and others in response to decreased natural gas prices during the fourth quarter. This decrease in current and forecasted development coupled with CMLP’s inability to attract third parties to utilize their adjoining system is the underlying causes of the impairment. The resulting post-impairment carrying value equaled the discounted fair value of these assets’ future cash flows.
Because of the volatility of oil and natural gas prices, it is reasonably possible we may experience additional impairment in future periods.
Unevaluated Natural Gas and Oil Properties Not Subject to Depletion
Under full cost accounting, we may exclude certain unevaluated property costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties not subject to depletion at December 31, 2011 and 2010 and the year in which they were incurred follows:
The following table summarizes the regions where we have unevaluated property costs not subject to depletion.
Costs are transferred into the amortization base on an ongoing basis, as projects are evaluated and proved reserves established or impairment determined. Pending determination of proved reserves attributable to the above costs, we cannot assess the future impact on the amortization rate. Unevaluated acquisition costs will require an estimated eight to ten years of exploration and development activity before evaluation is complete.
Other Matters
Capitalized overhead costs that directly relate to exploration and development activities were $18.3 million, $17.7 million and $17.1 million for 2011, 2010 and 2009, respectively. Depletion per Mcfe was $1.35, $1.30 and $1.36 for 2011, 2010 and 2009, respectively. Depreciation expense was $20.3 million, $35.0 million and $37.3 million for 2011, 2010 and 2009, respectively.
9.
OTHER ASSETS
Other assets consisted of the following:
Costs related to the acquisition of debt are deferred and amortized over the term of the debt.
10.
ACCRUED LIABILITIES
Accrued liabilities consisted of the following:
11.
LONG-TERM DEBT
Long-term debt consisted of the following:
Maturities are as follows:
Credit Facilities
In September 2011, we terminated and replaced our $1.0 billion global 2007 Senior Secured Credit Facility with new separate five-year syndicated senior secured revolving credit facilities for our U.S. and Canadian operations. The $1.25 billion Initial U.S. Credit Facility had a borrowing base of $850 million, including a letter of credit capacity of $75 million, as of September 30, 2011. The C$500 million Initial Canadian Credit Facility had a borrowing base of C$225 million, including a letter of credit capacity of C$100 million, as of September 30, 2011. The borrowing base for each facility was to be re-determined at least semi-annually based upon engineering reports and such other information deemed appropriate by the applicable administrative agent, in a manner consistent with its normal oil and gas lending criteria as it exists at the time of such redetermination.
During December 2011, the Initial U.S. Credit Facility and the Initial Canadian Credit Facility were amended and restated by the Combined Credit Agreements. The Combined Credit Agreements provide for an up to five-year combined revolving credit facility pursuant to which revolving credit loans and letters of credit may be provided to Quicksilver and Quicksilver Resources Canada Inc., as applicable, from time to time in an amount not to exceed the lesser of the borrowing base or commitments. The $1.75 billion Combined Credit Agreements have a global borrowing base of $1.075 billion, including a global letter of credit capacity of $175 million, as of December 31, 2011. The Combined Credit Agreements’ availability is governed by a global borrowing base. The global borrowing base and the U. S. borrowing base will be re-determined at least semi-annually based
upon engineering reports and such other information deemed appropriate by the global administrative agent, in a manner consistent with its normal oil and gas lending criteria as it exists at the time of such redetermination. At the time of each such redetermination up to 100% of the U. S. borrowing base (less a $50 million minimum retained amount) may be allocated to the Canadian borrowing base. The commitments under each of the Amended and Restated U.S. Credit Facility and the Amended and Restated Canadian Credit Facility may be increased by an amount up to $250 million, subject to certain conditions, without the consent of the lenders.
Borrowings under the Amended and Restated U.S. Credit Facility are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured by 100% of the equity interests of each of Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Barnett Shale Operating LLC, and Quicksilver Resources Partners Operating Ltd. and certain oil and gas properties and related assets of Quicksilver. Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by 100% of the equity interests of Quicksilver Resources Canada Inc. and its oil and gas properties and related assets and certain oil and gas properties and related assets of Quicksilver. At December 31, 2011, there was $798.1 million available under the Combined Credit Agreements.
The Amended and Restated U.S. Credit Facility also provides for the extension of swingline loans to Quicksilver. Borrowings under the Amended and Restated U.S. Credit Facility bear interest at a variable annual rate based on adjusted LIBOR or ABR plus, in each case, an applicable margin, provided that each swingline loan shall be comprised entirely of ABR loans. Borrowings under the Amended and Restated Canadian Credit Facility may be made in U.S. dollars or Canadian dollars and will be comprised entirely of Canadian prime loans, Canadian Deposit Offer Rate (“CDOR”) loans, U.S. prime loans or eurodollar loans, in each case, plus an applicable margin. The applicable margin under both credit facilities adjusts as the utilization of the global borrowing base changes.
Our ability to remain in compliance with the financial covenants in our Combined Credit Agreements may be affected by events beyond our control, including market prices for our products. Any future inability to comply with these covenants, unless waived by the requisite lenders, could adversely affect our liquidity by rendering us unable to borrow further under our credit facilities and by accelerating the maturity of our indebtedness.
Senior Notes Due 2015
In June 2008, we issued $475 million of senior notes due 2015, which are unsecured senior obligations of Quicksilver. The notes were issued at 98.66% of par. Interest at the rate of 8.25% is payable semiannually on February 1 and August 1.
Senior Notes Due 2016
In June 2009, we issued $600 million of senior notes due 2016, which are unsecured senior obligations. The notes were issued at 96.72% of par, which resulted in proceeds of $580.3 million that were used to repay a portion of the Senior Secured Second Lien Facility. Interest at the rate of 11.75% is payable semiannually on January 1 and July 1.
Senior Notes Due 2019
In August 2009, we issued $300 million of senior notes due 2019, which are unsecured senior obligations. The notes were issued at 97.61% of par, which resulted in proceeds of $292.8 million that were used to repay a portion of our 2007 Senior Secured Credit Facility. Interest at the rate of 9.125% is payable semiannually on February 15 and August 15.
Senior Subordinated Notes
In 2009, we issued $350 million of senior subordinated notes due 2016. The senior subordinated notes are unsecured senior subordinated obligations and bear interest at the rate of 7.125% which is payable semiannually on April 1 and October 1.
Senior Note Repurchases
During 2011, we repurchased the following senior notes in open market transactions:
Convertible Debentures
The convertible debentures due November 1, 2024 are contingently convertible into shares of our common stock. The debentures bear interest at an annual rate of 1.875% payable semi-annually on May 1 and November 1. Additionally, holders of the debentures can require us to repurchase all or a portion of their debentures on November 1, 2011, 2014 and 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into shares of our common stock at a rate of 65.4418 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events including certain changes of control, holders of the debentures are not entitled to exercise their conversion rights unless the closing price of our stock is at least $18.34 (120% of the conversion price per share) for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter. Upon conversion, we have the option to deliver any combination of our common stock and cash. Should all debentures be converted to our common stock, an additional 9,816,270 shares, subject to adjustment, would become outstanding; however, as of January 1, 2011, the debentures were not convertible based on share prices for the quarter ended December 31, 2010. We reported these obligations as current obligations in our December 31, 2010 balance sheet.
On November 1, 2011, we repurchased substantially all of the debentures for $150.0 million, after they were presented to us for repurchase by debenture holders. The repurchase transaction was completed utilizing borrowings from the Initial U.S. Credit Facility. During the first quarter of 2012, we repurchased the remaining debentures.
At December 31, 2010, the remaining unamortized discount on the debentures was $6.5 million, resulting in a carrying value of $143.5 million. The remaining discount was accreted to face value through October 2011. For 2011 and 2010, interest expense on our convertible debentures, recognized at an effective interest rate of 6.75%, was $8.9 million and $10.2 million, respectively, including contractual interest of $2.3 million for 2011 and $2.8 million for 2010.
Summary of All Outstanding Debt
As of December 31, 2011, the following subsidiaries are guarantors under our debt obligations: Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., and Barnett Shale Operating LLC. The following table summarizes other significant aspects of our long-term debt outstanding at December 31, 2011:
(1) Borrowings under the Amended and Restated U.S. Credit Facility are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured by 100% of the equity interests of each of Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Barnett Shale Operating LLC, and Quicksilver Resources Partners Operating Ltd., and certain oil and gas properties and related assets of Quicksilver. Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by 100% of the equity interests of Quicksilver Resources Canada Inc. and its oil and gas properties and related assets, and certain oil and gas properties and related assets of Quicksilver. The other debt presented is based upon structural seniority and priority of payment.
(2) The principal amount for the Combined Credit Agreements represents the borrowing base as of December 31, 2011.
(3) Represents the weighted average borrowing rate payable to lenders.
(4) Amounts outstanding under the Amended and Restated U.S. Credit Facility bear interest, at our election, at (i) adjusted LIBOR (as defined in the credit agreement) plus an applicable margin between 1.50% to 2.50%, (ii) ABR (as defined in the credit agreement), which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) adjusted LIBOR (as defined in the credit agreement) plus 1.0%, plus, in each case under scenario (ii), an applicable margin between 0.50% to 1.50%. We also pay a per annum fee on all letters of credit issued under the Amended and
Restated U.S. Credit Facility equal to the applicable margin and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.375% to 0.50%, in each case, based on global borrowing base usage.
(5) Amounts outstanding under the Amended and Restated Canadian Credit Facility bear interest, at our election, at (i) the CDOR Rate (as defined in the credit agreement) plus an applicable margin between 1.50% and 2.50%, (ii) the Canadian Prime Rate (as defined in the credit agreement) plus an applicable margin between 0.50% and 1.50%, (iii) the U.S. Prime Rate (as defined in the credit agreement) plus an applicable margin between 0.50% and 1.50% and (iv) eurodollar loans (as defined in the credit agreement) plus an applicable margin between 1.50% to 2.50%. We pay a per annum fee on all letters of credit issued under the Amended and Restated Canadian Credit Facility equal to the applicable margin and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.375% to 0.50%, in each case, based on global borrowing base usage.
(6) The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions and related definitions contained in the documents governing the various components of our debt.
(7) The estimated fair value is determined based on market quotations on the balance sheet date for fixed rate obligations. We consider debt with variable interest rates to have a fair value equal to its carrying value.
12.
ASSET RETIREMENT OBLIGATIONS
The following table provides a reconciliation of the changes in the estimated asset retirement obligation from January 1, 2010 through December 31, 2011.
13.
INCOME TAXES
Significant components of our deferred tax assets and liabilities as of December 31, 2011 and 2010 are as follows:
(1) Note 2 contains additional information regarding restated 2010 amounts.
The components of net income (loss) before income tax for 2011, 2010 and 2009 are as follows:
No rate changes occurred in any taxing jurisdiction for 2009, 2010 or 2011. For 2012 and beyond, we have utilized a rate of 25% in Canada and a federal rate of 35% and a state rate of 1% in the U.S. to value our deferred tax positions, with the U.S. federal and state future rates mirroring existing applicable rates.
The components of income tax expense for 2011, 2010 and 2009 are as follows:
(1) Note 2 contains additional information regarding restated 2010 amounts.
The following table reconciles the statutory federal income tax rate to the effective tax rate for 2011, 2010 and 2009:
(1) Note 2 to contains additional information regarding restated 2010 amounts.
We incurred net operating tax losses of $35 million, $336 million and $656 million in 2011, 2009 and 2008, respectively, of which $138 million was carried back to 2007. Approximately $476 million of the remaining $889 million has been applied to our 2010 taxable income and the remainder is included in deferred tax assets at December 31, 2011. Our net operating losses will expire between 2029 and 2032. In December 2009, newly enacted federal legislation allowed us to carry back 2008 alternative minimum tax losses of $35 million to 2004 and 2007. The net operating losses have not been reduced by a valuation allowance, because we believe that future taxable income would more likely than not be sufficient to utilize substantially all of our operating loss tax carry-forwards prior to their expiration.
QRI’s tax basis in the Fortune Creek Partnership exceeds book basis by $29 million. The Company expects to realize the deferred tax asset related to this balance only through the Partnership’s sale at which time the transaction will be treated as a capital transaction under Canadian tax law, taxed at the Canadian statutory rate of 12.5% for capital gains. We believe that it is more likely than not that we will be unable to realize the benefit of this deferred tax asset. Accordingly, we have recorded a full valuation allowance of $3.7 million for this item.
During October 2009, the IRS commenced an audit of our 2007 and 2008 consolidated U.S. federal income tax returns. No significant adjustments have been proposed by the IRS for those years. The Joint Committee of Taxation has reviewed and accepted the net operating loss carrybacks we filed in 2009. We remain subject to examination by the IRS for the years 2001 through 2006 except for 2004. An audit was completed by the IRS for 2004 and the statute of limitations has now expired for that year.
The following schedule reconciles the total amounts of unrecognized tax benefits for 2011 and 2010:
At December 31, 2011, $9.0 million of these unrecognized tax benefits, if recognized, would impact the effective tax rate.
14.
COMMITMENTS AND CONTINGENCIES
Contractual Obligations
Information regarding our contractual obligations, at December 31, 2011, is set forth in the following table:
(1) Under contracts with various third parties, we are obligated to provide minimum daily natural gas volume for gathering, processing, fractionation and transportation, as determined on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our gathering and transportation contracts with CMLP have no minimum volume requirement and, therefore, are not reported in the above amounts.
(2) We lease drilling rigs from third parties for use in our development and exploration programs. The outstanding drilling rig contracts require payment of a specified day rate ranging from $12,500 to $27,005 for the entire lease term regardless of our utilization of the drilling rigs.
(3) We lease office buildings and other property under operating leases. Rent expense for operating leases with terms exceeding one month was $4.8 million in 2011, $4.3 million in 2010 and $4.1 million in 2009.
(4) At December 31, 2011, we were under contract to purchase goods and services for use in field and gas plant operations.
Commitments and Contingencies
In April 2011, we entered into the NGTL Project, which will serve our Horn River Asset. Under the governing agreements, we agreed to provide financial assurances in the form of letters of credit to NGTL during the construction phase of the project, which is expected to continue through 2014. Assuming the project is fully constructed and based on estimated costs of C$257.4 million, including taxes of C$27.6 million, we expect to provide cumulative letters of credit as follows:
(1) A letter of credit for C$32.6 million is outstanding for the NGTL Project as of December 31, 2011.
Should other companies subscribe to the project, then our financial assurances under the agreements will be reduced. If the project is terminated by NGTL, then we would be responsible for all of the costs incurred or for which NGTL is liable, and we would have the option to purchase NGTL’s rights in the project for a nominal fee. Should the project be terminated by NGTL, we are required to pay NGTL an additional C$26.4 million. NGTL may terminate the project if it is not approved by the National Energy Board of Canada. Based on this and on numerous other factors, we consider the likelihood to be remote that NGTL will terminate the project. Accordingly, no amounts have been recognized on our consolidated balance sheet as of December 31, 2011. Upon completion of the project, all construction-related guarantees will expire.
We have also entered into agreements to deliver production from our Horn River Asset to NGTL over a 10-year period. These agreements will be extended in the event NGTL has either not received 1 Tcf of gas from us and other third parties, or recovered its costs as of the end of the 10-year period. In such event, the extension will be for delivery of minimum volumes of 106 MMcfd until such time that 1 Tcf of gas is delivered.
Also under the agreements, we are required to treat the gas to meet NGTL pipeline specifications. Such treatment will require us to construct treating facilities. We will develop our plans to address the treating requirements prior to the commissioning of the assets being constructed by NGTL.
At December 31, 2011, we had $9.1 million in surety bonds issued to fulfill contractual, legal or regulatory requirements and $49.4 million in letters of credit outstanding against the credit facility. Surety bonds and letters of credit generally have an annual renewal option.
On July 26, 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arises out of press releases in 2011 questioning the projected decline curves and economics of shale gas wells.
The allegations against our Executive Vice President - Operations in the District Court of Cleveland County, Oklahoma were dismissed on January 17, 2012.
Environmental Compliance
Our operations are subject to stringent, complex and changing laws and regulations pertaining to health, safety and the environment. As an owner, lessor or operator of our facilities, we are subject to laws and regulations at the federal, state, provincial and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities incorporates compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At December 31, 2011, we had recorded $0.1 million for liabilities for environmental matters.
15.
NONCONTROLLING INTERESTS AND KGS
KGS issued 4,000,000 newly issued common units in December 2009 in the KGS Secondary Offering and received $80.3 million, net of underwriters’ discount and other offering costs. The portion of these proceeds
related to our initial ownership interests, $50.2 million, was recognized as an increase to “Additional Paid-in Capital” on our consolidated balance sheet. In January 2010, the underwriters exercised their option to purchase an additional 549,200 newly issued common units for $11.1 million. As a result we recognized an additional $6.7 million to “Additional Paid-in Capital” in January 2010. KGS offered additional units to the public to provide funding for its acquisition of certain midstream assets from us, which was completed in January 2010 for $95.2 million.
With the closing of the Crestwood Transaction, we no longer consolidate the KGS (or CMLP as it is now known) in our financial statements. Accordingly, we no longer have noncontrolling interests attributable to it within our financial statements.
16.
FORTUNE CREEK
In December 2011, we entered into an agreement to form a midstream partnership, Fortune Creek, dedicated to the construction and operation of midstream assets to support natural gas producers primarily in British Columbia.
The partnership established an area of mutual interest for the midstream business covering approximately 30 million potential acres which includes transportation and processing infrastructure and agreements.
In connection with the partnership formation, we contributed an existing 20-mile, 20-inch gathering line, its related compression facilities, and 10-year contracts dedicating our future gas production from our Horn River Asset, as more fully described below. KKR contributed $125 million cash in exchange for a 50% interest in the partnership. Our Canadian subsidiary has responsibility of the day-to-day operations of Fortune Creek.
Our Canadian subsidiary entered into a firm gathering agreement with Fortune Creek which is guaranteed by us. At our election, KKR has the responsibility to fund all of the capital contributions associated with the development of the new gas treatment facility in exchange for preferential cash flow distributions. If our subsidiary does not meet its obligations under the gathering agreement, KKR has the right to liquidate the partnership and consequently we have recorded the funds contributed by KKR as a liability in our consolidated financial statements.
Based on an analysis of the entities equity at risk, we have determined the partnership to be a VIE. Further, based on our ability to direct the activities surrounding the production of natural gas and our direct management of the operations of the facilities, we have determined we are the primary beneficiary and therefore, we consolidate Fortune Creek.
The following December 31, 2011 balances related to Fortune Creek are recorded in our consolidated balance sheet:
17.
QUICKSILVER STOCKHOLDERS’ EQUITY
Common Stock, Preferred Stock and Treasury Stock
We are authorized to issue 400 million shares of common stock with a $0.01 par value per share and 10 million shares of preferred stock with a $0.01 par value per share. At December 31, 2011, we had 171.6 million shares of common stock outstanding.
The following table shows common share and treasury share activity since January 1, 2009:
Quicksilver Stockholder Rights Plan
In 2003, our Board of Directors declared a dividend distribution of one preferred share purchase right for each share of common stock then outstanding. Each right, when it becomes exercisable, entitles stockholders to buy one one-thousandth of a share of Quicksilver’s Series A Junior Participating Preferred Stock at an exercise price of $90, after adjustments to reflect the two-for-one stock split in January 2008.
The rights will be exercisable only if such a person or group acquires 15% or more of our common stock or announces a tender offer the consummation of which would result in ownership by such a person or group (an “Acquiring Person”) of 15% or more of common stock. This 15% threshold does not apply to certain members of the Darden family and affiliated entities, which collectively owned, directly or indirectly, approximately 30% of our common stock at February 15, 2012.
If an Acquiring Person acquires 15% or more of our outstanding common stock, each right will entitle its holder to purchase, at the right's then-current exercise price, a number of our common shares having a market value of twice such price. If we are acquired in a merger or other business combination transaction after an Acquiring Person has acquired 15% or more of our outstanding common stock, each right will entitle its holder to purchase, at the right's then-current exercise price, a number of the acquiring company's common shares having a market value of twice such price.
Prior to the acquisition by an Acquiring Person of beneficial ownership of 15% or more of our common stock, the rights are redeemable for $0.01 per right at the option of our Board of Directors.
Stock-Based Compensation
2006 Equity Plan
In 2006, our Board of Directors and our stockholders approved the 2006 Equity Plan, under which 14 million shares of common stock were reserved for issuance as grants of stock options, appreciation rights, restricted shares, restricted stock units, performances shares, performance units and senior executive plan bonuses. In May 2009, stockholders approved an amendment to the 2006 Equity Plan, which increased the number of shares available for issuance to 15 million. Our executive officers, other employees, consultants and non-employee directors are eligible to participate in the 2006 Equity Plan. Options reflect an exercise price of no less than the fair market value on the date of grant and have a term that expires 10 years from the date of grant. At December 31, 2011 and 2010, 12.6 million shares and 14.1 million shares (including 0.9 million shares and 0.6 million shares, respectively, surrendered to us to satisfy participants’ tax withholding obligations which then became available for future issuance under the 2006 Equity Plan), respectively, were available for issuance under the 2006 Equity Plan.
Stock Options
The following summarizes the values from and assumptions for the Black-Scholes option pricing model:
The following table summarizes our stock option activity for 2011:
We estimate that a total of 3.7 million stock options will become vested including those options already exercisable. The unexercised options have a weighted average exercise price of $12.03 and a weighted average remaining contractual life of 7.5 years.
Compensation expense related to stock options of $7.0 million, $6.7 million and $4.5 million was recognized for 2011, 2010 and 2009, respectively. The total intrinsic value of options exercised during 2011, 2010 and 2009, was $1.2 million, $2.8 million and $4.3 million, respectively.
Restricted Stock and Stock Units
The following table summarizes our restricted stock and stock unit activity for 2011:
At December 31, 2010, we had unrecognized compensation cost related to outstanding unvested restricted stock and RSUs of $13.9 million. As of December 31, 2011, the unrecognized compensation cost related to outstanding unvested restricted stock and RSUs was $17.3 million, which is expected to be recognized in
expense over the next 2 years. Grants of restricted stock and RSUs during 2011 had an estimated grant date fair value of $19.3 million. The fair value of RSUs settled in cash was $2.5 million and $5.5 million at December 31, 2011 and 2010, respectively. For 2011, 2010 and 2009, compensation expense of $13.9 million, $13.3 million and $14.6 million, respectively, was recognized. The total fair value of shares vested during 2011, 2010 and 2009 was $13.6 million, $16.4 million and $11.0 million, respectively.
Accumulated Other Comprehensive Income
At December 31, 2011, AOCI included $195.2 million and $19.7 million for derivatives and foreign currency translation, respectively. At December 31, 2010, AOCI included $97.2 million and $33.0 million for derivatives and foreign currency translation, respectively. All of these balances were attributable to us.
18.
EARNINGS PER SHARE
The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income per common share.
(1) Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, should be included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses because there is no contractual obligation to do so.
(2) For 2011, the effects of 9.8 million shares associated with our convertible debentures for the period outstanding were antidilutive, and stock options and unvested restricted stock units representing 1.9 million and 0.1 million shares, respectively, were antidilutive and, therefore, excluded from the diluted share calculations. For 2010, stock options and unvested restricted stock units representing 1.2 million and 0.1 million shares, respectively, were antidilutive and, therefore, excluded from the diluted share calculations. For 2009, the effects of 9.8 million shares associated with our contingently convertible debt and all share-based compensation awards were antidilutive and, therefore, excluded from the diluted share calculations.
(3) Note 2 contains additional information regarding restated 2010 amounts.
19.
CONDENSED CONSOLIDATING FINANCIAL INFORMATION
The following tables provide information about the entities that guarantee our senior notes and senior subordinated notes. The guarantees are full and unconditional and joint and several.
Under SEC rules, we are required to present financial information segregated between our guarantor and non-guarantor subsidiaries. The indentures under both our senior notes and our senior subordinated notes distinguish between “restricted” subsidiaries and “unrestricted” subsidiaries and further specify supplemental information that is not required under GAAP. The following table illustrates our subsidiaries and their status pursuant to the senior notes due 2015, senior notes due 2016, senior notes due 2019 and the senior subordinated notes:
Guarantor Subsidiaries -
Restricted
Non-Guarantor Subsidiaries
Restricted
Unrestricted
Cowtown Pipeline Funding, Inc.
Quicksilver Resources Canada Inc.
Quicksilver Gas Services Holdings LLC (2)
Cowtown Pipeline Management, Inc.
Cowtown Drilling Inc. (1)
Quicksilver Gas Services GP LLC (2)
Cowtown Pipeline L.P.
Quicksilver Resources Partners Operating Ltd. (3)
Quicksilver Gas Services LP (2)
Cowtown Gas Processing L.P.
Quicksilver Gas Services Operating LLC (2)
Barnett Shale Operating LLC (3)
Quicksilver Gas Services Operating GP LLC (2)
Cowtown Pipeline Partners L.P. (2)
Cowtown Gas Processing Partners L.P. (2)
Makarios Midstream Inc. (3)
1622834 Alberta Inc. (3)
Makarios Resources International Holdings LLC (3)
Makarios Resources International Inc. (3)
Quicksilver Resources GP LLC (3)
Quicksilver Production Partners LP (3)
(1) This entity was inactive for the three-year period ended December 31, 2011.
(2) We sold all our interests in this entity to Crestwood on October 1, 2010.
(3) These entities were created in 2011.
We own 100% of each of the restricted subsidiaries.
Quicksilver and the restricted subsidiaries conduct all of our exploration and production activities, and the unrestricted subsidiaries primarily conduct midstream operations or are related to our midstream MLP. Neither the restricted non-guarantor subsidiaries nor the unrestricted non-guarantor subsidiaries guarantee the obligations under the senior notes and the senior subordinated notes.
However, the restricted non-guarantor subsidiaries, like the restricted guarantor subsidiaries, are limited in their activity by the covenants in the indentures for such matters as:

incurring additional indebtedness;

paying dividends;

selling assets;

making investments; and

making restricted payments.
Subject to restrictions set forth in the indentures, we may in the future designate one or more additional subsidiaries as unrestricted.
The following tables present financial information about Quicksilver and our restricted subsidiaries for the annual periods covered by the consolidated financial statements. Under the indenture, Fortune Creek is not considered to be a subsidiary and therefore it is presented separately from the other subsidiaries for these purposes. The 2011, 2010 and 2009 condensed consolidating financial information includes changes in the financial information of our unrestricted non-guarantor subsidiaries to present the 2011, 2010 and 2009 financial information including the effects of the purchase of certain of our midstream assets by KGS and the Crestwood Transaction where we sold all of our interests in the unrestricted subsidiaries.
Immaterial Restatement of Condensed Consolidating Financial Information
We have restated 2010 results of operation and financial condition related to the gain on sale of our interests in KGS, which is more fully described in Note 2. This restatement impacted the “Quicksilver Resources Inc.” column.
In addition, we restated 2010 results of operation and financial condition to reclassify an $85.0 million intercompany payable previously recorded in current assets to current liabilities within the “Quicksilver Resources Inc.” column. We also restated to reclassify a $243.6 million intercompany receivable and payable previously reported as Investment in subsidiaries to Other Assets in the “Quicksilver Resources Inc.” column and to Long-term liabilities in the “Restricted Non-Guarantor Subsidiaries” column. These restatements had no impact on the totals reported for the “Quicksilver and Restricted Subsidiaries” for 2010 results of operation and financial condition.
Condensed Consolidating Balance Sheets
Condensed Consolidating Statements of Income
Condensed Consolidating Statements of Cash Flows
20.
SEGMENT INFORMATION
We operate in two geographic segments, the U.S. and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. Additionally, prior to the Crestwood Transaction, we operated in the midstream segment in the U.S., where we provided natural gas gathering and processing services predominantly through KGS. Following our announced partnership with KKR, we expect to have a midstream segment in Canada beginning in 2012 conducted through Fortune Creek. Revenue earned by KGS prior to the Crestwood Transaction for the gathering and processing of our gas has been eliminated on a consolidated basis as is the GPT recognized by our producing properties. We evaluate performance based on operating income and property and equipment costs incurred.
(1) Note 2 contains additional information regarding restated 2010 amounts.
21.
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid (received) for interest and income taxes is as follows:
Other significant non-cash transactions are as follows:
22.
EMPLOYEE BENEFITS
Quicksilver has a 401(k) retirement plan available to all U.S. full time employees who are at least 21 years of age. We make matching contributions and a fixed annual contribution and have the ability to make discretionary contributions to the plan. Expense associated with company contributions was $2.3 million, $2.5 million and $2.3 million for 2011, 2010 and 2009, respectively.
We have a retirement plan available to all Canadian employees. The plan provides for a match of employees’ contributions by us and a fixed annual contribution. Expense associated with company contributions for 2011, 2010 and 2009 was $0.8 million for each year.
We maintain a self-funded health benefit plan that covers all eligible U.S. employees. The plan has been reinsured on an individual claim and total group claim basis. We have an individual stop loss of $125,000 and an aggregating stop loss of $175,000. For 2011, 2010 and 2009 we recognized expense of $4.8 million, $3.5 million and $4.6 million, respectively, for this plan.
23.
TRANSACTIONS WITH RELATED PARTIES
As of February 15, 2012, members of the Darden family and entities controlled by them beneficially own approximately 30% of our outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.
We paid $0.2 million in 2011, $0.6 million in 2010, and $0.7 million in 2009 for rent and property management services on buildings owned by entities controlled by members of the Darden family. Rental rates were determined based on comparable rates charged by third parties. In October 2011, we agreed to purchase a manufacturing facility from an entity controlled by members of the Darden family for $1.1 million. We previously leased this facility from the seller for the manufacture of oil and gas equipment.
During 2011, 2010 and 2009, we paid $0.9 million, $0.8 million and $0.2 million for use of an airplane owned by an entity controlled by members of the Darden family. Usage rates were determined based upon comparable rates charged by third parties.
We paid $0.2 million in 2009 primarily for delay rentals under leases for over 5,000 acres held by a related entity. The lease terms were determined based on comparable prices and terms granted to third parties with respect to similar leases in the area. No payments were made in 2011 or 2010.
Payments received in 2011, 2010 and 2009 from Mercury for sublease rentals, employee insurance coverage and administrative services were $0.1 million, $0.3 million, and $0.3 million, respectively.
An entity affiliated with Mercury received $0.2 million in commission for the sale and purchases of property to unrelated third parties in 2011. The entity also received a $1.4 million commission from the lessor in connection with office space leased as of August 2010.
SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table presents selected quarterly financial data derived from our consolidated financial statements. This summary should be read in conjunction with our consolidated financial statements and related notes also contained in this Item 8 to our Annual Report on Form 10-K.
(1) Operating income for the first quarter of 2011 includes a charge of $49.1 million for impairment of the Canadian oil and gas properties to net realizable value.
(2) Operating income for the third quarter of 2010 includes a charge of $28.6 million for impairment of the HDCS to net realizable value.
(3) Operating income for the fourth quarter of 2010 includes a gain on sale of $494.0 million for the sale of all of our interests in KGS and a charge of $19.4 million for the impairment of our Canadian oil and gas properties.
(4) Note 2 to the consolidated financial statements contains additional information regarding restated 2010 amounts. Given the sale of our interests in KGS occurred in October 2010, only the fourth quarter of 2010 was affected.
(5) Operating income for fourth quarter 2011 includes gains of $217.9 million from the sale of BBEP Units. Operating income also includes charges for impairment of $58.0 million for our HCDS and certain midstream assets in Texas.
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Proved oil and gas reserves estimates for our properties in the U.S. and Canada were prepared by independent petroleum engineers from Schlumberger Data and Consulting Services and LaRoche Petroleum Consultants, Ltd., respectively. The reserve reports were prepared in accordance with guidelines established by the SEC. Natural gas, NGL and oil prices used in the 2011, 2010 and 2009 reserve reports are the unweighted average of the preceding 12-month first-day-of-the-month prices as of the date of the reserve reports without any. For all years, operating costs, production and ad valorem taxes and future development costs were based on year-end costs with no escalation.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represent estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of our natural gas, NGL and oil reserves or the costs that would be incurred to obtain equivalent reserves.
As required by GAAP, we have also included separate disclosure and presentation of our share of BBEP’s proved reserves for 2010 and 2009 because we account for BBEP by the equity method.
Consolidated Quicksilver (Excluding BBEP Reserves)
The changes in our proved reserves for the three years ended December 31, 2011 were as follows:
(1) Purchases of U.S. reserves in place during 2010 relate principally to the acquisition of additional working interest in our company-operated Lake Arlington Asset and the Alliance Transaction, respectively. These transactions are more fully described in Note 3 to our consolidated financial statements. The 2010 purchase of Canadian reserves in place relates to the acquisition of additional working interests in a company-operated field located in our Horseshoe Canyon Asset.
(2) Sales of reserves in place during 2009 relate principally to the Eni Transaction, which is more fully described in Note 3 to our consolidated financial statements.
(3) Extensions and discoveries for each period presented represent extensions to reserves attributable to additional drilling activity subsequent to discovery. U.S. extensions and discoveries for:

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

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

2009 are 99% attributable to our Barnett Shale Asset (of which 42% were proved developed); and
Canadian extensions and discoveries for:

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

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

2009 are 53% attributable to our Horn River Asset and 47% are attributable to our Horseshoe Canyon Asset.
(4) Revisions for each period presented reflect upward (downward) changes in previous estimates attributable to changes in operating and development costs, new information gained primarily from development drilling activity and production history and changes to development plans. Revisions include (154,405) MMcfe, (73,096) MMcfe and 132,846 MMcfe for such matters in 2011, 2010 and 2009, respectively. Revisions also include (54,539) MMcfe, 117,975 MMcfe and (251,676) MMcfe for changes in economic factors in 2011, 2010 and 2009. In 2011, negative revisions not related to economic factors resulted from removing proved undeveloped reserves that had not been developed within five years (55 Bcfe), change in performance related to offsetting activities, higher pipeline pressures and other factors (85 Bcfe) and various operational issues (14 Bcfe).
The carrying value of our oil and gas assets as of December 31, 2011, 2010 and 2009 were as follows:
Our consolidated capital costs incurred for acquisition, exploration and development activities during each of the three years ended December 31, 2011, were as follows:
Consolidated results of operations from our producing activities for each of the three years ended December 31, 2011, are set forth below:
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of our natural gas and oil properties. An estimate of such value should consider, among other factors, anticipated future prices of natural gas and oil, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, estimated future capital and operating costs and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows for 2011 were estimated by applying the unweighted average of the preceding 12-month first-day-of-the-month prices, adjusted for contracts with price floors but excluding hedges, and unescalated year-end costs to the estimated future production of the year-end reserves. These prices have varied widely and have a significant impact on both the quantities and value of the proved reserves as reduced prices cause wells to reach the end of their economic life much sooner and also make certain
proved undeveloped locations uneconomical, both of which reduce reserves. The following representative prices were used in the Standardized Measure and were adjusted by field for appropriate regional differentials:
Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated proved natural gas and oil properties. Tax credits and net operating loss carry-forwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
The Standardized Measure at December 31, 2011, 2010 and 2009 was as follows:
The primary changes in the Standardized Measure for 2011, 2010 and 2009 were as follows:
Quicksilver’s Share of BBEP Reserves
The following disclosures required under GAAP represent our share of BBEP’s reserves and BBEP’s oil and gas operations as of December 31, 2010 and 2009, which are all located in the U.S. In 2011, our investment in BBEP was eliminated and we no longer own any BBEP Units as of December 31, 2011. Note 7 in our consolidated financial statements contains additional information regarding our relationship with BBEP.
The following provides information regarding ownership percentages applied to BBEP’s gross reported amounts, as applicable:
The changes in our share of BBEP’s oil and gas reserves were as follows:
(1) Amounts are included as needed to reconcile Quicksilver’s portion of beginning reserves to ending reserves that result from changes in Quicksilver’s proportionate ownership of BBEP.
(2) During 2010, capital expenditures of $11.3 million were incurred and 16 wells drilled to convert 922 MMcf of natural gas and 959 MBbl of oil from proved undeveloped to proved developed. During 2009, capital expenditures of $2.3 million were incurred and 11 wells drilled to convert 196 MMcf of natural gas and 230 MBbl of oil from proved undeveloped to proved developed.
(3) As of December 31, 2010 and 2009, no material proved undeveloped reserves have remained undeveloped for more than five years.
The following representative prices were used in BBEP’s Standardized Measure:
The following table summarizes the carrying value of our portion of BBEP’s consolidated oil and gas assets as of December 31, 2010.
The following table summarizes our share of the capital costs incurred by BBEP during the two years ended December 31, 2010:
The following table summarizes our share of BBEP’s results of operations from its producing activities for each of the two years ended December 31, 2010:
The following table summarizes our share of BBEP’s Standardized Measure at December 31, 2010 and 2009:
The following table summarizes our share of the primary changes in BBEP’s Standardized Measure for 2010 and 2009:
(1) Amounts are included as needed to reconcile our portion of beginning value to ending value that result from changes in our proportionate ownership of BBEP.
ITEM 9.
ITEM 9. Changes in and Disagreements with Accountants or Accounting and Financial Disclosure
None.
ITEM 9A.
ITEM 9A. Controls and Procedures
Disclosure Controls and Procedures
Disclosure controls and procedures, as defined in SEC literature, are controls and other procedures that are designed to ensure that the information that we are required to disclose in the reports that we file or submit to the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
In connection with the preparation of this Annual Report on Form 10-K, our management, under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2011. In making this evaluation, our management considered the matters relating to the material weakness discussed below.
Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2011. In light of the material weakness described below, we revised our impairment analysis for midstream assets and have concluded that the financial statements in this Annual Report on Form 10-K present fairly, in all material respects, our consolidated financial position, results of operation and cash flows in conformity with generally accepted accounting principles.
Management’s Report on Internal Control Over Financial Reporting
Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with existing policies or procedures may deteriorate.
Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management conducted an assessment of our internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, our management has concluded that, as of December 31, 2011, it did not maintain effective internal control over financial reporting due to a material weakness relating to the design and operating effectiveness of the computation of impairment of our non-oil and gas assets. The weakness relates to design deficiencies regarding the assessment of triggering events and the consideration of asset groupings; and other deficiencies related to the performance and documentation of a recovery test and other fair value computational matters.
The effectiveness of our internal control over financial reporting as of December 31, 2011, has been audited by Deloitte & Touche LLP, our independent registered public accounting firm, and they have issued an attestation report on the effectiveness of our internal control over financial reports, as stated in their report included herein.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the quarter ended December 31, 2011, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. In response to the identification of the material weakness, management has enhanced its process for documenting identification of impairment indicators, and the preparation and review of undiscounted recoverability tests and discounted cash flow analyses. Management believes that these enhancements and improvements, when repeated as applicable in future periods, remediate the material weakness described above.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Quicksilver Resources Inc.
Fort Worth, Texas
We have audited the internal control over financial reporting of Quicksilver Resources Inc. and subsidiaries (the "Company") as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. A material weakness was identified relating to the design and operating effectiveness of the computation of impairment of non-oil and gas assets. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the consolidated financial statements as of and for the year ended December 31, 2011, of the Company and this report does not affect our report on such financial statements.
In our opinion, because of the effect of the material weakness identified above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2011 of the
Company. We considered the material weakness identified above in determining the nature, timing, and extent of audit tests applied in our audit of the 2011 consolidated financial statements, and this report does not affect our report dated April 15, 2012, which expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the adoption of Accounting Standards Update No. 2010-3, “Oil and Gas Reserve Estimation Disclosures.”
/s/ Deloitte & Touche LLP
Fort Worth, Texas
April 15, 2012
ITEM 9B.
ITEM 9B. Other Information
On July 26, 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arises out of recent press reports questioning the projected decline curves and economics of shale gas wells. We understand from the SEC that a number of other shale gas producers received similar subpoenas.
PART III
ITEM 10.
ITEM 10. Directors, Executive Officers and Corporate Governance
The information concerning our directors set forth under “Corporate Governance Matters” in the proxy statement for our May 16, 2012 annual meeting of stockholders (“2012 Proxy Statement”) is incorporated herein by reference. The information concerning any changes to the procedure by which a security holder may recommend nominees to the board of directors set forth under “Corporate Governance Matters - Committees of the Board” in the 2012 Proxy Statement is incorporated herein by reference. Certain information concerning our executive officers is set forth under the heading “Business - Executive Officers of the Registrant” in Item 1 of this Annual Report. The information concerning compliance with Section 16(a) of the Exchange Act set forth under “Section 16(a) Beneficial Ownership Reporting Compliance” in the 2012 Proxy Statement is incorporated herein by reference.
The information concerning our audit committee set forth under “Corporate Governance Matters - Committees of the Board” in the 2012 Proxy Statement is incorporated herein by reference.
The information regarding our Code of Business Conduct and Ethics set forth under “Corporate Governance Matters - Corporate Governance Principles, Processes and Code of Business Conduct and Ethics” in the 2012 Proxy Statement is incorporated herein by reference.
ITEM 11.
ITEM 11. Executive Compensation
The information set forth under “Executive Compensation,” “Corporate Governance Matters - Compensation Committee Interlocks and Insider Participation,” “Corporate Governance Matters - Director Compensation for 2011” and “Certain Relationships and Related Transactions” in the 2012 Proxy Statement is incorporated herein by reference.
ITEM 12.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information set forth under “Security Ownership of Management and Certain Beneficial Holders” in the 2012 Proxy Statement is incorporated herein by reference. The information regarding our equity plans under which shares of our common stock are authorized for issuance as set forth under “Equity Compensation Plan Information” in the 2012 Proxy Statement is incorporated herein by reference.
ITEM 13.
ITEM 13. Certain Relationships and Related Transactions, and Director Independence
The information set forth under “Certain Relationships and Related Transactions” in the 2012 Proxy Statement is incorporated herein by reference.
Information regarding our directors’ independence set forth under “Corporate Governance Matters - Independent Directors” in the 2012 Proxy Statement is incorporated herein by reference.
ITEM 14.
ITEM 14. Principal Accountant Fees and Services
The information set forth under “Independent Registered Public Accountants” in the 2012 Proxy Statement is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
The following are filed as part of this Annual Report:
Financial Statements
See the index to the consolidated financial statements and related footnotes and other supplemental information included in Item 8 of this Annual Report, which identifies the financial statements filed herewith.
Financial Statement Schedules
All other schedules are omitted from this item because the information is inapplicable or is presented in the consolidated financial statements and related notes in Item 8 of this Annual Report.
EXHIBIT INDEX
* Excludes schedules and exhibits we agree to furnish supplementally to the SEC upon request
** Indicates a management contract or compensatory plan or arrangement
SIGNATURES
Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on behalf of the registrant and in the capacities and on the dates indicated have signed this report below.