Quicksilver Resources 10-K 2009
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
For the transition period from to
Commission file number: 001-14837
(Exact name of registrant as specified in its charter)
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definition of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
(Do not check if a smaller reporting company)
As of June 30, 2008, the aggregate market value of the registrants common stock held by non-affiliates of the registrant was $4,067,732,259 based on the closing sale price of $38.64 as reported on the New York Stock Exchange.
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of the latest practicable date.
DOCUMENTS INCORPORATED BY REFERENCE
Except as otherwise specified and unless the context otherwise requires, references to the Company, Quicksilver, we, us, and our refer to Quicksilver Resources Inc. and its subsidiaries.
As used in this annual report unless the context otherwise requires:
AECO is a reference, in dollars per MMbtu, for gas delivered onto the NOVA Gas Transmission Ltd. System in Alberta, Canada
Bbl or Bbls means barrel or barrels
Bbld means barrel or barrels per day
Bcf means billion cubic feet
Bcfd means billion cubic feet per day
Bcfe means Bcf of natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
Btu means British Thermal Units, a measure of heating value
Canada means the division of Quicksilver encompassing oil and natural gas properties located in Canada
CBM means coalbed methane
DD&A means Depletion, Depreciation and Accretion
Domestic means the properties of Quicksilver in the continental United States
LIBOR means London Interbank Offered Rate
MBbl or MBbls means thousand barrels
MBbld means thousand barrels per day
MMBbls means million barrels
MMBtu means million Btu and is approximately equal to 1 Mcf of natural gas
MMBtud means million Btu per day
Mcf means thousand cubic feet
Mcfe means Mcf natural gas equivalents calculated as one Bbl of oil or NGLs equaling six Mcf of gas
MMcf means million cubic feet
MMcfd means million cubic feet per day
MMcfe means MMcf of natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
MMcfed means MMcf of natural gas equivalents per day, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
NGL or NGLs means natural gas liquids
NYMEX means New York Mercantile Exchange
Oil includes crude oil and condensate
Tcf means trillion cubic feet
Tcfe means Tcf of natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
Other commonly used terms and abbreviations include:
Alliance Acquisition means the August 8, 2008 purchase of leasehold, royalty and midstream assets in the Barnett Shale in northern Tarrant and southern Denton counties of Texas
BBEP means BreitBurn Energy Partners L.P.
BreitBurn Transaction means the November 1, 2007 conveyance of our Northeast Operations in exchange for aggregate proceeds of $1.47 billion
FASB means the Financial Accounting Standards Board, which promulgates accounting standards in the U.S.
GAAP means accounting principles generally accepted in the United States
IPO means the KGS initial public offering completed on August 10, 2007
KGS means Quicksilver Gas Services LP, which is our publicly-traded partnership and trades under the ticker symbol KGS
Mercury means Mercury Exploration Company, which is owned by members of the Darden family
Michigan Sales Contract means the gas supply contract which terminates in March 2009 under which we agreed to deliver 25 MMcfd at a floor price of $2.49 per Mcf
Northeast Operations means the oil and gas properties and facilities in Michigan, Indiana and Kentucky which were conveyed to BreitBurn Operating, L.P. on November 1, 2007
PCAOB means the Public Company Accounting Oversight Board
SEC means the United States Securities and Exchange Commission
SFAS means Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board
Certain statements contained in this annual report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as may, assume, forecast, position, predict, strategy, expect, intend, plan, estimate, anticipate, believe, project, budget, potential, or continue, and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict and are subject to material uncertainties that may affect actual results and may be beyond our control.
All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.
Quicksilver Resources Inc., including its subsidiaries, (Quicksilver or the Company) is an independent energy company engaged primarily in exploration, development and production of unconventional natural gas onshore in North America. We own producing oil and natural gas properties in the United States, principally in Texas, Wyoming and Montana, and in Alberta, Canada, which had estimated total proved reserves of approximately 2.2 Tcfe of natural gas at December 31, 2008. We also explore for natural gas onshore in North America, principally in the Horn River Basin of Northeast British Columbia and the Delaware Basin of West Texas. In addition, our new ventures team actively studies other basins in North America for unconventional natural gas opportunities which may yield future exploration opportunities. We also own approximately 73% of KGS, a publicly traded midstream master limited partnership controlled by us, and we own approximately 41% of the limited partner units of BBEP, a publicly-traded oil and natural gas exploration and production master limited partnership.
Our common stock trades under the symbol KWK on the New York Stock Exchange. Our principal and administrative offices are located at 777 West Rosedale St., Fort Worth, Texas 76104. The units of KGS are publicly traded on the NYSE Arca under the ticker symbol KGS and the units of BBEP are traded on the NASDAQ Global Select Market under the ticker symbol BBEP.
Through our predecessors, we began operations in 1963 as a privately-held company controlled by members of the Darden family. We were organized as a Delaware corporation in 1997 and became a public company in 1999. As of December 31, 2008, members of the Darden family and entities controlled by them, beneficially owned approximately 30% of our outstanding common stock.
In August 2008, we completed the $1.3 billion Alliance Acquisition that consisted of producing and non-producing leasehold, royalty and midstream assets that we believe complements our existing operations in the Fort Worth Basin of North Texas. Consideration in the transaction was $1 billion in cash and $262 million in Quicksilver common stock. We funded the cash portion of the transaction by drawing $675 million on our Senior Secured Second Lien Facility and drawing the remainder on our Senior Secured Credit Facility. We estimate that the 13,000 net acres acquired contain more than one trillion cubic feet of net recoverable natural gas resources, including 299 Bcf classified as proved at the time of the acquisition.
We have a multi-pronged strategy to increase share value through cost-effective growth in production and reserves by focusing on unconventional natural gas plays onshore in North America. This strategy takes advantage of the Companys proven record and expertise in identifying and developing properties containing fractured shales, coalbed methane and tight sands. Our strategy includes the following key elements:
Focus on core areas of repeatable, low-risk development: We intend to invest the vast majority of our 2009 capital budget on low-risk development and exploitation projects on our extensive leasehold positions in the Fort Worth and Western Canadian Sedimentary basins. In 2009, we expect to concentrate our drilling in our Barnett Shale properties in the Fort Worth Basin of North Texas and in our Canadian CBM properties in Alberta, Canada. We believe that operating in concentrated areas allows us to more efficiently deploy our resources, manage costs and leverage our base of technical expertise.
Pursue disciplined organic growth opportunities: We intend to invest approximately 10% of our 2009 capital budget in high-potential, longer cycle-time exploration projects to replenish our inventory of development projects for the future. Through our activities in each of the Fort Worth and Western Canadian
Sedimentary basins, we have developed significant expertise in identifying, developing and producing fractured shales, coal seams and tight sands. We are focused on identifying and evaluating opportunities that allow us to apply this expertise and experience to the development and operation of other unconventional reservoirs in North America. In 2009, we will focus our exploratory activities on our 127,000 acres in the Horn River Basin of Northeast British Columbia where we hold a 100% working interest. We also expect to complete the exploratory evaluation of our acreage in the Delaware Basin of West Texas in 2009. In addition, we may seek to acquire similar acreage positions for future exploration activities.
Enhance profitability through control and marketing of our equity natural gas and crude oil: We 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. We believe this allows us to better manage the physical movement of our production and the costs 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. We continue to control our midstream operations in the Fort Worth Basin through our approximate 73% interest in KGS, including 100% of its general partner. KGS brought on line an additional 125 Mmcfd of processing capacity during the first quarter of 2009.
Maintain flexible financial profile: We believe that a conservative financial structure will better position us to capitalize on opportunities and to limit our financial risk. Our ownership interests in KGS and BBEP provide additional financial flexibility for the Company while enabling us to participate in the expected future growth of both these entities. In addition, to help ensure a level of predictability in the prices we receive for our natural gas and crude oil production, we hedge the commodity price of all of our products with financial instruments covering a substantial portion of our production. We regularly review the credit-worthiness of our hedging counterparties, and our hedging program is spread among numerous financial institutions, all of which participate in our credit facility.
High-quality asset base with long reserve life: Our proved reserves of approximately 2.2 Tcfe as of December 31, 2008, were approximately 99% natural gas and NGLs and approximately 63% proved developed. The majority of these reserves are located in our core areas in the Fort Worth Basin in North Texas and the Western Canadian Sedimentary Basin in Alberta, which accounted for approximately 84% and 15%, respectively, of our proved reserves. Based on our annualized fourth-quarter 2008 average production from these properties, our implied reserve life (proved reserves divided by annualized fourth-quarter 2008 production) was 18.5 years and our implied proved developed reserve life (proved developed reserves divided by annualized fourth quarter 2008 production) was 11.6 years. We believe our assets are characterized by long reserve lives and predictable well production profiles. As of December 31, 2008, we operated properties containing approximately 99% of our proved reserves.
Multi-year inventory of development and exploitation drilling projects: As of December 31, 2008, we owned leases covering more than 542,000 net acres in our two core areas, of which approximately 42% were undeveloped. Within the Fort Worth Basin alone, we have more than 1,650 identified drilling locations, which at the 2009 anticipated drilling rate of proved reserves, provide us with a 10-year inventory of drilling locations. 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 the Fort Worth Basin. For 2009, we have budgeted approximately $400 million for drilling activities.
Proven record of organic growth in reserves and production: During the past three years, we have added approximately 1.5 Tcfe of proved reserves from organic development drilling activities. We have supplemented this activity with the Alliance Acquisition, which added 299 Bcfe of proved reserves at the time of its purchase and divested approximately 546 Bcfe of proved reserves associated with our former Northeast Operations in 2007. Excluding acquisition and divestiture activity, we have replaced approximately 78% of our reserves during the years ended December 31, 2008. Our growth has resulted from our ability to acquire
attractive undeveloped acreage and apply our technical expertise to find, develop and produce reserves. In recent years, we have demonstrated this ability through our accomplishments in our two core areas. We believe our current acreage position will provide opportunities to continue our reserve and production growth.
Midstream strength: Our midstream operations, which are owned or operated by KGS, are well positioned to complement our growth initiatives in the Fort Worth Basin and to compete with other midstream providers for unaffiliated business. Quicksilvers operational structure allows our midstream operations to more accurately forecast future gathering and processing estimates and to assess the need and timing for capacity additions. KGS assets in the Fort Worth Basin are well positioned to expand the gathering system footprint, increase throughput volumes and plant utilization which ultimately increase cash flows.
Experienced management and technical team: Our CEO, Glenn Darden, and our Chairman, Thomas Darden, are founding members of our company and have held executive positions at Quicksilver since our formation. They both have been in the oil and natural gas business their entire professional careers. Since our formation, they, along with an 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 resources. Our executive management team is supported by a core team of technical and operating managers who have significant industry experience, including experience in drilling and completing horizontal wells and in unconventional reservoirs.
The consolidated financial statements included in Item 8 of this annual report contain information on our segments and geographical areas, which is incorporated herein by reference.
Substantially all of our properties consist of interests in developed and undeveloped oil and natural gas leases and mineral acreage. In addition, we have midstream assets, including natural gas and NGL processing plants and related gathering and treating systems. Our midstream operations in the Fort Worth Basin are conducted by KGS, of which we own approximately 73% of the partnership interests, including 100% of its general partner. We also indirectly own interests in other oil and natural gas properties through our ownership of approximately 21.348 million limited partnership units in BBEP, approximately 41% of their partnership interests.
Our oil and natural gas operations are focused onshore in North America, primarily in unconventional natural gas plays. Our current production and development operations are concentrated in the Fort Worth and Western Canadian Sedimentary basins. At December 31, 2008, we had estimated total proved reserves of approximately 2.2 Tcfe, approximately 99% of which were natural gas and NGLs and approximately 63% of which were proved developed. Approximately 84% of our reserves at December 31, 2008 were located in Texas and approximately 15% were in Canada. For the year ended December 31, 2008, we had average production of 262.8 MMcfe per day and total production of 96.2 Bcfe. Since going public in 1999, we have grown our reserves and production at an approximate compound annual growth rate of 25% and 19% respectively.
The Barnett Shale play in the Fort Worth Basin in North Texas comprised 84% of our total estimated proved reserves and approximately 75% of our total average daily production for 2008. In the quarter ended December 31, 2008, our net production from wells in the Fort Worth Basin was approximately 259 MMcfed. We expect our 2009 production from Texas to represent approximately 80% of our 2009 production.
At December 31, 2008, we held approximately 192,000 net acres in the Fort Worth Basin of which approximately 34% is currently developed. We have identified more than 1,650 remaining potential drilling
locations. Much of our acreage in Hood and Somervell counties contains high-Btu natural gas which contains NGLs within the natural gas stream. We gather our production and process the high-Btu natural gas through our midstream system that is owned and operated by KGS. Effective in the first quarter of 2009, this system includes processing facilities which have the capacity to process more than 325 MMcfd of natural gas.
KGS manages approximately 350 miles of natural gas gathering pipelines, ranging up to 20 inches in diameter, all located in the Fort Worth Basin. Additionally, KGS owns two NGL pipelines that interconnect with pipelines owned by third parties. The pipeline system gathers and delivers natural gas produced by our wells and those of third parties to the processing facilities. We expect to continue to construct additional gathering assets as additional wells in the Fort Worth Basin are developed. Our capital expenditures budget for 2009 includes approximately $155 million for midstream assets, including $35 million to be spent by KGS.
During 2008, we drilled 296 gross (259.7 net) wells in the Fort Worth Basin primarily from multi-well drilling pads. On these multi-well pads, all the wells are drilled prior to initiating completion activities. At December 31, 2008, we had drilled a total of 703 gross (620.1 net) wells in the Fort Worth Basin since we began exploration and development operations in 2003. In 2008, we completed 255 gross (222.6 net) wells and tied 256 gross (226.8 net) wells into sales.
We also control approximately 475,000 net acres in West Texas, predominantly in the Delaware Basin. Through December 31, 2008, we had drilled or re-entered wells on that acreage to evaluate horizontal and vertical opportunities within both the Barnett and Woodford shale formations. We expect to complete this evaluation during 2009.
The portion of the 2009 capital budget allocated to our Texas interests is approximately $475 million. At December 31, 2008, we had six drilling rigs operating for us in the Fort Worth Basin, and we expect to utilize as many as nine rigs in this area during 2009.
Our Rocky Mountain producing properties are located in Montana and Wyoming. Production from those properties is primarily crude oil from established formations at depths ranging from 1,000 feet to 17,000 feet. At December 31, 2008, our Rocky Mountain proved reserves were approximately 1.9 MMBbls of crude oil and 1.6 MMcfe of natural gas and NGLs for total equivalent reserves of 13 Bcfe. Daily production from our properties in the Rocky Mountain region averaged 3.1 MMcfed for 2008.
At December 31, 2008, Canadian reserves of 333 Bcfe, primarily attributable to our CBM projects in Alberta, comprised 15% of our total reserves. 2008 production averaged 63 MMcfed, representing approximately 24% of our total 2008 production and Canadian production averaged 65 MMcfed during the fourth quarter of 2008.
As of December 31, 2008, we had approximately 161,000 gross (102,000 net) undeveloped acres in Alberta, Canada. On this acreage, we drilled 373 gross (156.9 net) productive wells with 356 gross (144.7 net) wells tied into sales in 2008. During 2009, we expect to tie into sales all of the approximately 180 wells completed but not producing at December 31, 2008. These expenditures were fully funded by Canadian cash flows from operations, which we expect to continue in 2009.
In 2008, we acquired an additional 50,000 acres in the Horn River Basin of Northeast British Columbia resulting in a total of approximately 127,000 contiguous acres in this basin. We spud our first exploratory well on this acreage in 2008 and spud a second well in the first quarter of 2009.
We believe that our 2009 and 2010 growth will be through development of our leasehold interests in our core areas in the Barnett Shale and CBM formations in Alberta. In addition, we are actively exploring the Horn River Basin in Northeast British Columbia and the Delaware Basin in West Texas. We believe that our
future reserve and production growth will come primarily from our Texas and Canadian operations. We may also pursue acquisitions of additional undeveloped leasehold interests, which could allow for further capitalization on our proven expertise in unconventional gas plays.
We intend to focus our capital spending program primarily on the continued development of our properties in Texas and Alberta. For 2009, we have established a capital budget of $600 million, of which we have allocated $400 million for drilling activities, $155 million for gathering and processing facilities, including approximately $35 million to be funded directly by KGS, $40 million for acquisition of additional leasehold interests and $5 million for other property and equipment. On a regional basis, approximately $475 million has been allocated to Texas to drill approximately 180 wells on operated properties and to tie in approximately 100 such wells. Canada has been allocated $110 million to maintain current production levels though the drilling of approximately 180 wells and to begin exploratory activities in the Horn River Basin. The remaining capital budget is spread among our other operating areas. The budget for gathering and processing expenditures includes $114 million in Texas, which includes $35 million of expenditures to be funded by KGS, and $41 million in Canada.
OIL AND NATURAL GAS RESERVES
The following reserve quantity and future net cash flow information concerns our proved reserves. Independent petroleum engineers with Schlumberger Data and Consulting Services and LaRoche Petroleum Consultants, Ltd. prepared our reserve estimates for our U.S. and Canadian properties, respectively. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Prices include consideration of changes in existing prices provided by contractual arrangements but not of escalations based upon expected future conditions. Future production and development costs include production and property taxes.
Proved developed oil and natural gas reserves are reserves that are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and natural gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for re-completion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.
The reserve data set forth in this document represents only estimates and is subject to inherent uncertainties. The determination of oil and natural gas 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 the reserve estimates contained in this document are reasonable, reserve estimates are imprecise and are expected to change as additional information becomes available.
The following table summarizes our proved reserves and the standardized measure of discounted future net cash flows attributable to them at December 31, 2008, 2007 and 2006 in accordance with the rules established by the SEC, which includes requirements to maintain year-end pricing over the entire production horizon.
The discussion of volumes produced from revenue generated by and cost associated with operating our properties included in Managements Discussion and Analysis in Item 7 of this annual report is incorporated herein by reference.
During the periods indicated, the Company drilled the following exploratory and development wells:
The following table summarizes our acquisition, exploration and development expenditures:
The following table summarizes productive wells:
Our principal natural gas and crude oil properties consist of non-producing and producing oil and gas leases and mineral acreage, including reserves of natural gas and crude oil in place. Developed acres are defined as acreage allocated to wells that are producing or capable of producing. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial reserves, regardless of whether or not such acreage contains proved reserves. Gross acres are the total number of acres in which we have a working interest. Net acres are the sum of our fractional interests owned in the gross acres. The following table indicates our interest in developed and undeveloped acreage:
The following table summarizes information regarding the total number of net undeveloped acres as of December 31, 2008:
All of the acreage scheduled to expire can be held through drilling operations. We believe that we have the ability to retain all of the expiring acreage that we feel is prospective of economic production either through drilling activities or through the exercise of extension options.
We sell natural gas, NGLs and crude oil to a variety of customers, including utilities, major oil and natural gas companies or their affiliates, industrial companies, large trading and energy marketing companies and other users of petroleum products. Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. Accordingly, the loss of any single purchaser would not materially affect our revenue. During 2008, Targa and Total Gas and Power, the largest purchasers of our products, accounted for approximately 17% and 10% of our total natural gas, NGL and crude oil revenue, respectively.
Depending upon economic and competitive factors, we may encounter difficulty in acquiring oil and natural gas leases and properties, marketing natural gas and crude oil, securing personnel and otherwise conducting our operations. Our competitors may include the major oil and natural gas companies as well as numerous independents and individual proprietors.
Our operations are affected from time to time in varying degrees by political developments and U.S. and Canadian federal, state, provincial and local laws and regulations. In particular, natural gas and crude oil production and related operations are, or have been, subject to price controls, taxes and other laws and regulations relating to the industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the industry increases our cost of doing business and affects our profitability. We do not anticipate any significant challenges in complying with laws and regulations applicable to our operations.
Our exploration, development, production, pipeline gathering and processing operations for natural gas and crude oil are subject to stringent U.S. and Canadian federal, state, provincial and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (EPA), issue regulations to implement and enforce such laws, and compliance is often difficult and costly. Failure to comply may result in substantial costs and expenses, including possible civil and criminal penalties. These laws and regulations may:
In addition, these laws, rules and regulations may restrict the rate of natural gas and crude oil production below the rate that would otherwise exist. The regulatory burden on the industry increases the cost of doing business and consequently affects our profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, disposal or clean-up requirements could adversely affect our financial position, results of operations and cash flows. While we believe that we are in substantial compliance with current applicable environmental laws and regulations, and we have not experienced any materially adverse effect from compliance with these environmental requirements, we cannot assure you that this will continue in the future.
The U.S. Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as the Superfund law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the present or past owners or operators of the disposal site or sites where the release occurred and the companies that transported or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment. Furthermore, although petroleum, including natural gas and crude oil, is exempt from CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as hazardous substances under CERCLA and thus such wastes may become subject to liability and regulation under CERCLA. State initiatives to further regulate the disposal of crude oil and natural gas wastes are also pending in certain states, and these various initiatives could have adverse impacts on us.
Stricter standards in environmental legislation may be imposed on the industry in the future. For instance, legislation has been proposed in the U.S. Congress from time to time that would reclassify certain exploration and production by-products as hazardous wastes and make them subject to more stringent
handling, disposal and clean-up restrictions. Compliance with environmental requirements generally could have a materially adverse effect upon our financial position, results of operations and cash flows. Although we have not experienced any materially adverse effect from compliance with environmental requirements, we cannot assure you that this will continue in the future.
The U.S. Federal Water Pollution Control Act (FWPCA) imposes restrictions and strict controls regarding the discharge of produced waters and other petroleum wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of crude oil and other hazardous substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Federal effluent limitation guidelines prohibit the discharge of produced water and sand, and some other substances related to the natural gas and crude oil industry, into coastal waters. Although the costs to comply with zero discharge mandated under federal or state law may be significant, the entire industry will experience similar costs and we believe that these costs will not have a materially adverse impact on our financial condition and results of operations. Some oil and natural gas exploration and production facilities are required to obtain permits for their storm water discharges. Costs may be incurred in connection with treatment of wastewater or developing storm water pollution prevention plans.
The U.S. Resource Conservation and Recovery Act (RCRA), generally does not regulate most wastes generated by the exploration and production of natural gas and crude oil. RCRA specifically excludes from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy. However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing solid hazardous waste may be significant, we do not expect to experience more burdensome costs than would be borne by similarly situated companies in the industry.
In addition, the U.S. Oil Pollution Act (OPA) requires owners and operators of facilities that could be the source of an oil spill into waters of the United States, a term defined to include rivers, creeks, wetlands and coastal waters, to adopt and implement plans and procedures to prevent any spill of oil into any waters of the United States. OPA also requires affected facility owners and operators to demonstrate that they have at least $35 million in financial resources to pay for the costs of cleaning up an oil spill and compensating any parties damaged by an oil spill. Substantial civil and criminal fines and penalties can be imposed for violations of OPA and other environmental statutes.
In Canada, the oil and natural gas industry is currently subject to environmental regulations pursuant to municipal, provincial, and federal legislation. Environmental legislation provides for restrictions and prohibitions on industry development and environmental impact including releases or emissions of various substances associated with industry activities. In addition, legislation requires that well and facility sites be constructed, operated, abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in suspension of activities and substantial cash expenses, including possible fines and penalties.
In Alberta, environmental compliance is regulated by Alberta Environment. Industry specific regulations including some areas of environmental activities are governed and enforced by the Energy Resource Conservation Board.
In British Columbia, environmental compliance is regulated by The Ministry of the Environment. Industry specific regulations including some areas of environmental activities are governed and enforced by the Oil and Gas Commission.
We make available free of charge on our internet website, www.qrinc.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file or furnish such material to the SEC.
Additionally, charters for the committees of our Board and our Corporate Governance Guidelines and Code of Business Conduct and Ethics can be found on our internet website under the heading Corporate Governance. Stockholders may request copies of these documents by writing to the Investor Relations Department at 777 West Rosedale Street, Fort Worth, Texas 76104.
As of January 30, 2009, we had 615 full-time employees, none of whom have collective bargaining agreements.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following information is provided with respect to our executive officers as of February 10, 2009.
Officers are elected by our Board of Directors and hold office at the pleasure of the Board until their successors are elected and qualified. Thomas F. Darden, Glenn Darden and Anne Darden Self are siblings. Messrs. P. Jeff Cook and Philip W. Cook are not related. The following biographies describe the business experience of our executive officers:
THOMAS F. DARDEN has served on our Board of Directors since December 1997 and became Chairman of the Board in March 1999. He was elected as a director of Quicksilver Gas Services GP LLC in July 2007. Mr. Darden was previously employed by Mercury Exploration Company for 22 years in various executive level positions.
GLENN DARDEN has served on our Board of Directors since December 1997 and became our Chief Executive Officer in December 1999. He was elected as a director of Quicksilver Gas Services GP LLC in March 2007. He served as our Vice President until he was elected President and Chief Operating Officer in March 1999. Prior to that time, he served with Mercury for 18 years, the last five as Executive Vice President. Mr. Darden previously worked as a geologist for Mitchell Energy Company LP (subsequently merged with Devon Energy).
ANNE DARDEN SELF has served on our Board of Directors since September 1999, and became our Vice President - Human Resources in July 2000. She is also currently President of Mercury, where she has worked since 1992. From 1988 to 1991, she was employed by Banc PLUS Savings Association in Houston, Texas, initially as Marketing Director and for three years thereafter as Vice President of Human Resources. She worked from 1987 to 1988 as an Account Executive for NW Ayer Advertising Agency. Prior to 1987, she spent several years in real estate management.
JEFF COOK became our Executive Vice President - Operations in January 2006, after serving as our Senior Vice President - Operations since July 2000. From 1979 to 1981, he held the position of Operations Supervisor with Western Company of North America. In 1981, he became a District Production Superintendent for Mercury Production Company and became Vice President of Operations in 1991 and Executive Vice President in 1998 of Mercury Production Company before joining us.
PHILIP W. COOK became our Senior Vice President - Chief Financial Officer in October 2005. From October 2004 until October 2005, Mr. Cook served as President and Chief Financial Officer of EcoProduct Solutions, a private chemical company. From August 2001 until September 2004, he served as Vice President and
Chief Financial Officer of PPI Technology Services, an oilfield service company. From August 1993 to July 2001, he served in various capacities, including Vice President and Controller, Vice President and Chief Information Officer and Vice President of Audit, of Burlington Resources Inc. (subsequently merged with ConocoPhillips), an independent oil and gas company engaged in exploration, development, production and marketing.
JOHN C. CIRONE was named as our Senior Vice President, General Counsel and Secretary in January 2006, after serving as our Vice President, General Counsel and Secretary since July 2002. Mr. Cirone was employed by Union Pacific Resources (subsequently merged with Anadarko Petroleum Corporation) from 1978 to 2000. During that time, he served in various positions in the Law Department, and from 1997 to 2000 he was the Manager of Land and Negotiations. In 2000, he became Assistant General Counsel of Union Pacific Resources. After leaving Union Pacific Resources in August 2000, Mr. Cirone was engaged in the private practice of law prior to joining us in July 2002.
JOHN C. REGAN became our Vice President, Controller and Chief Accounting Officer in September 2007. He is a Certified Public Accountant with more than 15 years of combined public accounting, corporate finance and financial reporting experience. Mr. Regan joined us from Flowserve Corporation where he held various management positions of increasing responsibility from 2002 to 2007, including Vice President of Finance for the Flow Control Division and Director of Financial Reporting. He was also a senior manager specializing in the energy industry in the audit practice of PricewaterhouseCoopers, where he was employed from 1994 to 2002.
ROBERT N. WAGNER became our Vice President - Reservoir Engineering in December 2002, after serving as our Vice President - Engineering since July 1999. From January 1999 to July 1999, he was our manager of eastern region field operations. From November 1995 to January 1999, Mr. Wagner held the position of District Engineer with Mercury. Prior to 1995, he was with Mesa, Inc. (subsequently merged with Parker and Parsley) for more than eight years and served as both drilling engineer and production engineer.
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.
Natural gas and crude oil prices fluctuate widely, and low prices could have a material adverse impact on our business.
Our revenue, profitability and future growth depend in part on prevailing natural gas, NGL and crude oil prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our Senior Secured Credit Facility is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas, NGLs and crude oil that we can economically produce.
While prices for natural gas and crude oil may be favorable at any point in time, they fluctuate widely, particularly as evidenced by price movements in the latter half of 2008. Among the factors that can cause these fluctuations are:
Due to the volatility of natural gas and crude oil prices and our inability to control the factors that influence them, we cannot predict future pricing levels.
If natural gas or crude oil prices decrease, our exploration and development efforts are unsuccessful or our costs increase substantially, we may be required to recognize impairment expenses on our oil and gas properties.
We employ the full cost method of accounting for our oil and gas properties, whereby all costs associated with acquiring, exploring for, and developing natural gas and crude oil reserves are capitalized and accumulated in separate country cost centers. These capitalized costs are amortized based on production from the reserves for each country cost center. Each capitalized cost pool cannot exceed the net present value of the underlying natural gas, NGL and crude oil reserves. Impairment to the carrying value of our oil and gas properties was recognized in the fourth quarter of 2008 and could occur again in the future if natural gas, NGL or crude oil prices at a reporting period end result in significantly decreased value of our reserves. Increased operating and capitalized costs without incremental increases in natural gas and crude oil reserves could also trigger impairment based on reduced value of our reserves. In the event of impairment, we recognize expense in the amount of the impairment, which could be material and could adversely affect our results of operations and financial condition.
Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.
The process of estimating natural gas, NGL and crude oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any
significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves disclosed in this annual report.
In order to prepare these estimates, we and independent reserve engineers engaged by us must project production rates and timing of development expenditures. 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. The process also requires economic assumptions with respect to natural gas and crude oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of natural gas, NGL and crude oil reserves are inherently imprecise.
Actual future production, natural gas, NGL and crude oil prices and revenue, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and crude oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed in this annual report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing petroleum prices and other factors, which may be beyond our control.
At December 31, 2008, approximately 37% of our estimated proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain than comparable developed reserves. Recovery of undeveloped reserves requires additional capital expenditures and successful drilling and completion operations. Our reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves and the costs associated with them in accordance with industry standards, there is risk that the estimated costs are inaccurate, that development will not occur as scheduled or that actual results will not be as estimated.
The present value of future net cash flows disclosed in Item 8 of this annual report is not necessarily the fair value of our estimated proved natural gas and crude oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of period end. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by natural gas, NGL and crude oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of natural gas and crude oil 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 required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, 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 natural gas industry in general will affect the appropriateness of the 10% discount factor in arriving at the reserves actual fair value.
Approximately 75% of our 2008 production was from Texas and approximately 24% was from Alberta, Canada. Because of our concentration in these geographic areas, any regional events that increase costs, reduce availability of equipment or supplies, reduce demand or limit production, including weather and natural disasters, may impact us more than if our operations were more geographically diversified.
Our Canadian operations present unique risks and uncertainties, different from or in addition to those we face in our domestic 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, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations. Laws and policies of the United States affecting foreign trade and taxation may also adversely affect our Canadian operations.
We have experienced capital expenditure and working capital needs, particularly as a result of our property acquisition and drilling activities. For 2009, we plan to operate our capital program within our operating cash flows. However, in the future, we may require additional financing above the level of cash generated by our operations to fund our growth. If revenue decreases as a result of lower petroleum prices or otherwise, our ability to expend the capital necessary to replace our reserves or to maintain production of current levels may be limited, resulting in a decrease in production over time. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, we cannot be certain that additional financing will be available to us on acceptable terms or at all. In the event 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.
We are vulnerable to operational hazards, transportation dependencies, regulatory risks and other uninsured risks associated with our activities.
The oil and natural gas business involves operating hazards such as well blowouts, explosions, uncontrollable flows of crude 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. Also, the availability of a ready market for our natural gas and crude oil production depends on the proximity of reserves to, and the capacity of, natural gas and crude oil gathering systems, treatment plants, pipelines and trucking or terminal facilities.
U.S. and Canadian federal, state and provincial regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could adversely affect our ability to produce and market our natural gas, NGLs and crude oil. In addition, we may be liable for environmental damage caused by previous owners of properties purchased or leased by us.
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. Generally, environmental risks are not fully insurable. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.
Our future success depends upon our ability to find, develop or acquire additional reserves that are economically recoverable. Our proved reserves will generally decline as reserves are produced, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves. In order to increase reserves and production, we must continue our development drilling and recompletion programs or undertake other replacement activities. Our current strategy is to maintain our focus on low-cost operations while increasing our reserve base and production through exploration and development of our existing properties. Our planned exploration or development projects or any acquisition activities that we may undertake might not result in meaningful additional reserves and we might not have continuing success drilling productive wells. Furthermore, while our revenue may increase if prevailing petroleum prices increase materially, our finding costs also could increase.
We own a 41% limited partner interest in BBEP from which we expect to receive distributions. We have no management oversight over BBEP, its financial condition, its operating results or its financial reporting process and are subject to the risks associated with BBEPs business and operations. Moreover, the management of BBEP has discretion over the amount, if any, that they distribute to unitholders.
The nature of our ownership interest in a publicly-traded entity subjects us to market risks associated with most ownership interests traded on a public exchange. Sales of substantial amounts of BBEP limited
partner units, or a perception that such sales could occur, could adversely affect the market price of our BBEP limited partner units, which could result in an impairment to the value of our limited partner interest in BBEP.
Through our ownership interest in KGS, we share in KGS results of operations and may be entitled to distributions from KGS. Accordingly, we have diminished control over assets owned by KGS and assets which KGS has a right to acquire. We are also subject to the risks associated with KGS business and operations, including, but not limited to:
We cannot control the operations of gas processing and transportation facilities we do not own or operate.
We deliver our Canadian production to market primarily by either the TransCanada or ATCO systems. We have no influence over the operation of these facilities and must depend upon their owners to minimize any loss of processing and transportation capacity.
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 have an adverse effect on us.
Competition in our industry is intense, and we are smaller and have a more limited operating history than many of our competitors.
We compete with major and independent oil and natural gas companies for property acquisitions. We also compete 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. In addition, larger competitors may be able to absorb the burden of any changes in federal, state, provincial and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and productive natural gas and crude oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and crude oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to complete transactions in this highly competitive environment. Furthermore, the oil and natural gas industry competes with other industries in supplying the energy and fuel needs of industrial, commercial, and other consumers.
To reduce our exposure to petroleum price fluctuations, we have entered into financial hedging arrangements which may limit the benefit we would receive from increases in petroleum prices. These hedging arrangements also expose us to risk of financial losses in some circumstances, including the following:
The result of natural gas market prices exceeding collar ceilings requires us to make monthly cash payments. If we choose not to engage in hedging arrangements in the future, we could be more affected by changes in natural gas, NGL and crude oil 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 and our results of operations.
At higher natural gas, NGL and oil prices, increased demand results in increased costs for drilling equipment, crews and associated supplies, equipment and services. We cannot be certain that we could obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services during periods of high petroleum prices. Any such delays and price increases could adversely affect our ability to pursue our drilling program and our results of operations.
Our activities are regulated by complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.
Natural gas, NGL and crude oil 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:
From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and crude oil wells below actual production capacity to conserve supplies of natural gas and crude oil. We also are subject to changing and extensive tax laws, the effects of which cannot be predicted.
The development, production, handling, storage, transportation and disposal of natural gas and crude oil, by-products and other substances and materials produced or used in connection with our operations are also subject to laws and regulations primarily relating to protection of human health and the environment. The discharge of natural gas, crude oil or pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may result in the assessment of civil or criminal penalties or require us to incur substantial costs of remediation.
Legal 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.
The risks associated with our debt could adversely affect our business, financial condition and results of operations, and such risk could increase if we incur more debt.
Subject to the limits contained in our various loan agreements and indentures, we may incur additional debt. Our ability to borrow under our Senior Secured Credit Facility is subject to the quantity and value of our proved reserves and other assets, including our units owned in BBEP. If we incur additional debt or fail to increase the quantity and value of our proved reserves, the risks that we now face as a result of our indebtedness could intensify.
We have demands on our cash resources in addition to interest expense, including operating expenses, principal payments under our debt and funding of our capital expenditures. Our level of debt relative to our proved reserves and these significant demands on our cash resources could have important effects on our business and on the value of our securities. For example, they could:
Our ability to pay principal and interest on our long-term debt and to satisfy our other liabilities will depend upon our future performance and our ability to refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital markets conditions then prevailing and other factors which may be beyond our control. If we are unable to service our debt and fund our operating costs, we will be forced to adopt alternative strategies that may include:
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 the holders of our securities to experience a partial or total loss of their investment in us.
Our debt agreements restrict our ability to, among other things:
Our debt agreements, among other things, also require the maintenance of financial covenants that are more fully described in Note 14 to the consolidated financial statements in Item 8 of this annual report. Our ability to satisfy these covenants may be affected by events beyond our control, and we may be unable to satisfy such covenants and requirements in the future. In addition, our ability to borrow under our Senior Secured Credit Facility is dependent upon the quantity and value of our proved reserves.
The covenants contained in the agreements governing our debt may affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a breach of the restrictive or financial covenants in our debt agreements could result in an event of default. Upon the occurrence of such an event of default, the applicable creditors could, subject to the terms and conditions of the applicable agreement, elect to declare the outstanding principal of that debt, together with 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, there can be no assurance that our assets would be sufficient to repay such debt in full. The above restrictions could limit our ability to obtain future financing and may prevent us from taking advantage of attractive business opportunities.
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.
A small number of existing stockholders exercise significant control over our company, which could limit your ability to influence the outcome of stockholder votes.
Members of the Darden family, together with entities controlled by them, beneficially own approximately 30% of our common stock as of December 31, 2008. 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.
A large number of our outstanding shares and shares to be issued upon conversion of our outstanding convertible debentures or exercise of our outstanding options may be sold into the market in the future, which could cause the market price of our common stock to drop significantly, even if our business is performing well.
Our shares that are eligible for future sale may adversely affect the price of our common stock. There were more than 167 million shares of our common stock outstanding at December 31, 2008. Approximately 116 million of these shares are freely tradable without substantial restriction or the requirement of future registration under the Securities Act. In addition, when the necessary restrictions for our contingently convertible debentures are satisfied and become convertible at the holders option, based on the conversion rate, an aggregate of 9,816,270 shares of our common stock could be issued. We also had 1,103,336 options outstanding to purchase shares of our common stock at December 31, 2008 as detailed in Note 20 to the consolidated financial statements in Item 8 of this annual report.
Sales of substantial amounts of common stock, or a perception that such sales could occur, and the existence of conversion and option rights to acquire shares of common stock at prices that may be below the then current market price of the common stock, could adversely affect the market price of our common stock and could impair our ability to raise capital through the sale of our equity securities.
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:
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.
A detailed description of our significant properties and associated 2008 developments can be found in Item 1 of this annual report, which is incorporated herein by reference.
Information required with respect to this item is set forth in Note 17 to the consolidated financial statements included in Item 8 of this annual report, which is incorporated herein by reference.
There were no matters submitted to a stockholder vote during the fourth quarter of 2008.
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 sales prices of our common stock for the periods indicated below.
As of January 31, 2009, there were approximately 845 common stockholders of record.
We have not paid 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 prohibit payments of dividends.
The following performance graph compares the cumulative total stockholder return on Quicksilver common stock with the Standard & Poors 500 Stock Index (the S&P 500 Index) and the Standard & Poors 500 Exploration and Production Index (the S&P 500 E&P Index) for the period from December 31, 2003 to December 31, 2008, assuming an initial investment of $100 and the reinvestment of all dividends, if any.
Comparison of Cumulative Five Year Total Return
The following table summarizes the Companys repurchases of its common stock during the quarter ended December 31, 2008.
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 Managements 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:
The following Managements Discussion and Analysis (MD&A) is intended to help the reader understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this annual report. We conduct our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller gathering and processing segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis.
Our MD&A includes the following sections:
We are a Fort Worth, Texas-based independent oil and gas company engaged in the acquisition, exploration, exploitation, development and production of natural gas, NGLs, and crude oil. We focus primarily on unconventional reservoirs where hydrocarbons may be found in challenging geological conditions such as fractured shales, coal beds and tight sands. We generate revenue, income and cash flows by producing and selling natural gas, NGLs and crude oil. Our production generates earnings and cash flow that allow us to conduct acquisition, exploration, exploitation, development and production activities to replace the reserves that we produce.
At December 31, 2008, approximately 99% of our proved reserves were natural gas and NGLs. Consistent with one of our business strategies, we have developed and applied the expertise gained in developing our now divested Northeast Operations to our projects in Alberta, Canada and our Barnett Shale interests in Texas. Our Texas and Alberta reserves made up approximately 84% and 15%, respectively, of our proved reserves at December 31, 2008. Our acreage in the Horn River Basin in British Columbia will provide additional opportunity for further application of this expertise.
For 2009, we plan to continue our focus on the development and exploitation of our properties in Texas and Alberta and to begin exploration in the Horn River Basin. We have allocated $400 million of our 2009 consolidated capital budget of $600 million for drilling and completion activities. Approximately $330 million is allocated to projects in Texas and approximately $57 million is allocated to our Canadian projects. Approximately $155 million of the 2009 capital budget has been allocated to construction of natural gas processing and gathering assets, including $35 million to be funded directly by KGS.
Our Company focuses on three key value drivers:
Our reserve growth relies on our ability to apply our technical and operational expertise in our core operating areas to develop, exploit and explore unconventional natural gas reservoirs. We strive to increase
reserves and production through aggressive management of operations and through relatively low-risk development and exploitation 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 and exploit unconventional natural gas reservoirs which align our technical and operational expertise.
Our core operating areas and the acreage that we hold are well suited for production increases through development and exploitation drilling. We perform workover and infrastructure projects to reduce ongoing operating costs and increase current and future production rates. We regularly review our operated properties to determine if steps can be taken to profitably increase reserves and production.
In evaluating the result of our efforts, we consider the capital efficiency of our drilling program and also measure the following key indicators: reserve growth; production volumes; cash flow from operating activities; and earnings per share.
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 crude oil production is among the several risks that we face. We seek to manage this risk by entering into financial hedges. We have mitigated the downside risk of adverse price movements through the use of derivatives but, in doing so, have also limited our ability to benefit from favorable price movements. This commodity price strategy enhances our ability to execute our development, exploitation and exploration programs, meet debt service requirements and pursue acquisition opportunities even in periods of price volatility.
RESULTS OF OPERATIONS
Natural Gas, NGL and Crude Oil
Average Daily Production Volumes:
Average Realized Prices:
The following table summarizes the changes in our natural gas, NGL and crude oil revenue:
Our natural gas revenue for 2008 increased as a result of both a $1.37 per Mcf increase in realized prices and a 22.8 MMcfd increase in volumes as compared to 2007. Natural gas production in the
U.S. increased 78.5 MMcfd as a result of the impact of new wells placed into production partially offset by production declines for existing wells, primarily in the Fort Worth Basin. The November 2007 divestiture of our Northeast Operations reduced our natural gas production by 56.1 MMcfd and the Alliance Acquisition increased production by 17.0 MMcfd on an annualized basis. Additional wells on our Canadian interests increased production by 6.2 MMcfd from 2007.
NGL revenue for 2008 increased as a result of production increases and realized prices that were $2.21 per Bbl higher than 2007 NGL realized prices. Additional Texas natural gas production in the high-BTU area of the Barnett Shale and processing improvements during 2008 increased NGL volumes 5,030 Bbld when compared to 2007. Partially offsetting the Texas production and pricing increases was the absence of production due to the divestiture of the Northeast Operations.
Crude oil revenue for 2008 was higher than 2007 due to a $14.96 per Bbl increase in realized prices. Production increases of 524 Bbld from the Fort Worth Basin in 2008 partially offset the divested production from the Northeast Operations.
Our natural gas revenue for 2007 increased from 2006 as a result of both a $0.68 per Mcf increase in realized natural gas prices and a 17.4 MMcfd increase in volumes as compared to 2006. Natural gas revenue in the U.S. increased 10.6 MMcfd as a result of new wells placed into production, primarily in the Fort Worth Basin. The November 2007 divestiture of our Northeast Operations reduced our natural gas production as did natural production declines in this area. Additional wells on our Canadian interests increased production by 6.8 MMcfd from 2006.
NGL revenue for 2007 was almost three times higher than 2006, which primarily resulted from an incremental 1,724 MBbl increase in NGL production resulting from additional Texas natural gas production in the high-BTU area of the Barnett Shale during 2007. Also, more favorable pricing of $4.38 per Bbl contributed to the increase when compared to 2006 NGL revenue.
Crude oil revenue for 2007 was higher than 2006 due to a $3.88 per Bbl increase in realized prices. Fort Worth Basin production in 2007 increased to partially offset the impact of the divestiture of our Northeast Operations.
Other revenue, consisting primarily of revenue from the processing, gathering and marketing of natural gas, was $19.9 million for 2008, an increase of $3.7 million compared with 2007. Throughput from third parties in our gathering and processing assets operated by KGS increased other revenue by $6.2 million. Partially offsetting the increase was the absence of $4.3 million of Canadian government grants for new drilling techniques we received in 2007.
Other revenue was $16.2 million for 2007, an increase of $12.3 million compared with 2006. This increase is primarily due to $5.1 million from higher throughput from third parties in our gathering and processing assets operated by KGS and $4.3 million more in Canadian government grants for new drilling techniques compared to 2006. Hedge ineffectiveness in 2007 also increased other revenue $1.0 million compared to 2006.
Oil and gas production expense for 2008 was almost unchanged from 2007. The absence of production expense of $48.9 million for the divested Northeast Operations was offset by the growth of our operations in the Fort Worth Basin and Canada that increased production expense $39.2 million and $5.5 million, respectively, as production volumes increased 117% and 11%, respectively, for 2008 as compared to 2007, as discussed previously.
Although oil and gas production expense for our Fort Worth Basin operations were $39.2 million higher for 2008, production expense per Mcfe decreased 21% to $1.30 per Mcfe when compared to 2007. The improvement in production expense on a Mcfe-basis was primarily the result of higher production levels, cost containment initiatives, new completion techniques used in our capital program and higher utilization of automation during 2008. Canadian production expense increased primarily as a result of the 11% increase in production volumes and an increase in personnel costs plus higher prevailing exchange rates during 2008.
Oil and gas production expense for 2007 increased by $41.7 million from 2006 levels, primarily due to costs associated with higher production levels. On a Mcfe-basis, our costs increased 14% compared to 2006 levels. Although overall costs increased in Texas, our production and number of producing properties increased
while our cost per Mcfe of production decreased. Our 2007 production costs for the Northeast Operations reflected $6.3 million of employee severance cost associated with its divestiture. Northeast Operations unit costs were also impacted by production declines. The total cost increases reflect salary increases of $3.7 million associated with headcount increases. Canadian production expense increased $8.5 million due to an estimated $1.4 million for currency effects of the strengthening Canadian dollar, $1.2 million higher gathering and processing costs, $2.0 million in increased direct operating cost associated with new producing properties and more than $5.0 million of overhead costs, including higher salaries, stock-based compensation, incentive compensation and rent.
Production and ad valorem tax expense for 2008 increased slightly as compared to 2007. Production and ad valorem taxes increased $11.2 million due to the development of our Fort Worth Basin properties and increased production. This increase was nearly offset by the absence of production and ad valorem taxes associated with the divested Northeast Operations. We have historically experienced low severance tax expense for our Texas production as a result of exemptions and rate reductions for development of our acreage positions with wells deemed by the taxing authorities to be high cost wells. We expect severance tax rates in Texas to increase in future quarters as fewer of our wells to be drilled in 2009 and beyond will qualify for severance tax exemptions and rate reductions because we expect our Fort Worth Basin drilling and completion costs to continue to decrease while the cost threshold for exemptions and rate reductions will increase.
Production and ad valorem tax expense for 2007 was relatively flat when compared to 2006 as a $2.1 million increase in ad valorem tax expense was mostly offset by a decrease in production taxes. Ad valorem tax expense increased primarily as a result of the growth in our Texas and Canadian property values associated with our 2007 capital expenditure program while production tax expense decreased as a result of a higher percentage of our production in Texas that is partially or fully exempted from production taxes.
Higher depletion expense for 2008 resulted from a 31% increase in the depletion rate and a 23% increase in production volumes. Our 2008 depletion rate was impacted by the addition of the proved oil and gas properties obtained in the Alliance Acquisition as well as the capital costs incurred for proved reserves added from our existing properties and increases in estimated future capital expenditures. Depreciation expense for 2008 was $10.4 million higher than 2007 primarily due to additions of Fort Worth Basin field compression and KGS midstream infrastructure, partially offset by the absence of $4.1 million of depreciation expense associated with the divested Northeast Operations depreciable assets. We expect depreciation expense will further increase when KGS places its $110 million Corvette Plant into service in the first quarter of 2009 and we expect that depletion for our U.S. properties will be approximately $1.80 per Mcfe after the impairment recognized in the fourth quarter of 2008.
Depletion expense in 2007 increased from 2006 primarily as a result of a 27% increase in production. Our 2007 consolidated depletion rate increased $0.21 per Mcfe as a result of increased future development costs due in part to a higher percentage of undeveloped proved reserves for 2007 year-end as compared to 2006, and higher finding costs in 2007 in Texas. Depreciation expense for 2007 was $7.7 million higher than 2006 primarily resulting from increased capacity at our Cowtown Gas Plant, additions to our Cowtown Pipeline and new Canadian gas processing facilities.
We recognized a noncash pretax charge of $633.5 million ($411.8 million after tax) for impairment related to our U.S. oil and gas properties in December 2008. As required under full cost accounting rules, we performed a ceiling test by comparing the book value of our oil and gas properties, net of related deferred tax liability and asset retirement obligations, to the year-end ceiling limitation, which is the after-tax value of the future net cash flows from proved oil and gas reserves, including the effect of hedges. As also required under full cost accounting rules prescribed by the SEC, the ceiling amount was based upon year-end prices and costs, discounted at 10% per year. Under these rules, management has little ability to influence the ceiling amounts with respect to such factors as pricing, discount rate, cost structure and timing. Consequently, the ceiling amount is not necessarily indicative of the fair value of our oil and gas properties, which could have a wide range of potential fair values. Included below is an alternate valuation of our oil and gas reserves that supplements the ceiling amount and which management believes is more indicative of our oil and gas properties fair value as it incorporates the valuation techniques we employ in making investment decisions.
The alternate value presented below would have, if permitted in place of the ceiling amount, eliminated any recognition of impairment during 2008. This valuation was calculated in the same manner as the scenario used in the ceiling test, except for the following changes:
Managements alternate pretax valuation related to its proved oil and gas reserves at December 31, 2008 as described above was as follows:
We recognized a charge of $9.6 million in 2008 as a result of the settlement of litigation as discussed in Note 17 to our consolidated financial statements in Item 8 of this annual report. The most significant increase in recurring general and administrative expense for 2008 was a $14.4 million increase in employee compensation and benefits, including increases of $4.2 million of non-cash expense for vesting of stock-based compensation and $1.3 million in performance-based compensation. The remaining $8.9 million increase in employee compensation is related to additional headcount which was necessary to bring our infrastructure to a level needed to accommodate growth in our operations and production. After consideration of the BreitBurn Transaction investment banking fees of $2.0 million recognized in 2007, fees for legal, accounting and other professional services increased general and administrative expense by approximately $2.8 million, which resulted from additional regulatory filing requirements, litigation costs, expenses associated with evaluation of complex business transactions and the full year effect of KGS being a publicly-traded partnership.
General and administrative expense for 2007 increased due to a $4.1 million increase in stock-based compensation and $1.9 million in performance-based compensation. These increases relate to increased
headcount at our corporate offices to develop additional capabilities necessary to support our growth. General and administrative costs increased year over year by $4.1 million for legal and professional fees which relate to professional services provided for the KGS IPO and our Northeast Operations divestiture.
During 2007, we recognized a gain of $628.7 million as a result of our divestiture of the Northeast Operations, and we recorded a loss on the Michigan Sales Contract related to delivery of volumes in Michigan. Further information regarding these transactions is included in Item 8 of this annual report, which is incorporated herein by reference.
During 2008, we recognized $93.3 million associated with the equity earnings in our investment in BBEP for the period from November 1, 2007, when we acquired the BBEP units, through September 30, 2008. This amount reflects our prevailing ownership interests for the applicable period before and after our ownership increased from 32% to 41% by virtue of BBEPs purchase and retirement of units during 2008. BBEP has experienced significant volatility in their net earnings due to changes in value of their derivative instruments, for which they do not employ hedge accounting.
During the fourth quarter of 2008, the Company considered the fair value of the BBEP units along with the fair value trend of its peers, the trend and future petroleum strip prices and the limited availability of credit which occurred in the latter half of 2008. Based on these factors, the Company determined that the decrease in fair value of BBEP units was other-than-temporary and recorded a pretax charge of $320.4 million to reduce the carrying value of our investment in BBEP to its fair value. Management believes that certain alternative fair value measures, such as BBEPs liquidation value, the estimated value of its properties and reserves, the present value of existing distribution levels and other calculations would have eliminated or materially lowered the impairment charge. However, the prescriptive nature of the relevant GAAP requires the Company to ignore these alternative measures based upon availability of Level 1 inputs as described in SFAS No. 157.
Interest costs for 2008 were higher than 2007 primarily because of higher average debt outstanding due to the issuance of our Senior Notes and our Senior Secured Second Lien Facility due in 2013, partially offset by a decrease in our average consolidated interest rate. The higher debt levels in 2008 relate to the Alliance Acquisition and the funding of our 2008 capital program. The increase in capitalized interest relates to more projects and costs within those projects being subject to capitalization. Interest was capitalized in 2008 for our exploration projects in the Horn River Basin and West Texas and construction of the Corvette Plant by KGS.
For 2007, interest expense increased $26.5 million from 2006 primarily as a result of both higher debt balances and higher prevailing rates on the variable portion of our debt. The increases in 2007 debt balances primarily relate to the drilling and midstream expansion programs undertaken in 2007, but were partially offset by our debt reductions in November, funded by proceeds from our Northeast Operations divestiture.
The 2008 provision for income taxes changed dramatically from 2007 due to the loss generated by U.S. operations for 2008. Pretax results for 2008 compared with 2007 were most significantly influenced by the impairment charges recognized on U.S. oil and gas properties and on our investment in BBEP. Also, 2007 results included the gain resulting from our divestiture of our Northeast Operations. Higher Canadian pretax income and the absence of tax credits received in 2007 increased the provision for income taxes in Canada by $11.1 million. In 2008, the effective rate exceeds the statutory rate of 35% due to the benefit of lower taxes in Canada partially offset by impact of permanent differences for executive compensation and meals and entertainment.
Income tax expense for 2007 was $256.5 million which yielded the effective rate of 34.9%. The 600 basis point increase in the effective rate is principally due to taxes on the gain associated with the divestiture of our Northeast Operations at the U.S. statutory rate, which is higher than the comparable Canadian rate. Thus our taxable income was more heavily weighted toward the U.S.in 2007 compared with 2006. Also, the recognition in 2007 of tax expenses pursuant to FIN 48 and a decrease in the tax credits generated by our Canadian operations increased the effective rate, offset in part by a reduction for the effect of a future tax rate reduction in Canada. Our U.S. income tax expense of approximately 35.5% was established using the statutory U.S. federal rate of 35% plus the effects of the Texas margin tax that was enacted in May 2006. Our Canadian tax expense was established using the combined federal and provincial rate of 29% and the effects of tax rate reductions that were enacted in 2007.
LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION
Cash Flow Activity
Cash flows provided by operating activities in 2008 were $456.6 million, an increase of $137.5 million or 43% from 2007. The increase in operating cash flows results from a 23% production increase and a 16% increase in realized price per Mcfe. Payments of $46.6 million for income taxes and other uses of working capital partially offset the increase in cash earnings.
Cash flows provided by operating activities in 2007 were $319.1 million, an increase of $76.9 million or 32% from 2006. The cash flows increased due to a 27% production increase, an 11% realized price increase and higher cash flows provided by working capital.
For each of the three years ended December 31, 2008, we have spent significant cash resources for the development of our large acreage positions in our core areas in the Fort Worth Basin and the CBM properties in Alberta. In addition, our expenditures for gas processing and gathering assets have grown significantly as part of our growth in the Barnett Shale. In 2008 and 2007, our investing cash flows included the $1.0 billion cash portion of the Alliance Acquisition and net cash proceeds of $741.1 million from the divestiture of our Northeast Operations, respectively. Of the $2.3 billion of cash paid for property, plant and equipment during 2008, 88% was invested in our oil and natural gas properties and 12% was invested in our gas processing and gathering operations.
Our 2008 purchases of property, plant and equipment reflect our expansion in our two core operating areas, the Fort Worth Basin and the Western Canadian Sedimentary Basin in Alberta. In 2008, we purchased approximately 90 producing wells in the Alliance Acquisition and drilled 296 (259.7 net) wells in the Fort Worth Basin and 373 (156.9 net) wells in Canada. Additionally, the assets purchased in the Alliance Acquisition included a gathering system and we invested $230.4 million and $4.3 million for Fort Worth Basin and Canadian gas processing and gathering facilities, respectively.
Capital costs incurred for development, exploitation and exploration activities in 2007 were $852.5 million, primarily for expansion in our two core operating areas. In 2007, we drilled 244 (219.4 net) wells in the Fort Worth Basin and an additional 356 (184.1 net) wells in Canada. Additionally, we invested $168.5 million and $3.4 million for Fort Worth Basin and Canadian gas processing and gathering facilities, respectively.
Capital costs incurred for development, exploitation and exploration activities in 2006 were $544.7 million. Those expenditures also reflect our two core operating areas. In 2006, we drilled 123 (111.3 net) wells in the Fort Worth Basin and an additional 400 (215.2 net) wells in Canada. Additionally, we invested $82.3 million and $7.6 million for Fort Worth Basin and Canadian gas processing and gathering facilities, respectively.
We currently estimate that our spending for property, plant and equipment in 2009 will be approximately $600 million, of which we have allocated $400 million for drilling activities, $155 million for gathering and processing facilities (including $35 million to be funded directly by KGS), $40 million for acquisition of additional leasehold interest and $5 million for other property and equipment.
Net cash flows from financing activities during 2008 were significantly impacted by the Alliance Acquisition and our 2008 capital program. We funded our capital program in excess of operating cash flow through the issuance of our Senior Notes and additional borrowing under our Senior Secured Credit Facility. The Alliance Acquisition was funded by a $700 million five-year Senior Secured Second Lien Facility and additional borrowing under our Senior Secured Credit Facility.
Net cash flows from financing activities during 2007 were significantly impacted by the KGS IPO and the divestiture of our Northeast Operations. The KGS IPO resulted in cash proceeds of $110 million primarily used to repay debt. The divestiture of our Northeast Operations generated net cash proceeds of $741.1 million included in investing activities, however those proceeds were used to pay down debt previously outstanding which affected financing cash flows.
On February 9, 2007, we extended our Senior Secured Credit Facility to February 9, 2012. The facility provides for revolving loans, swingline loans and letters of credit from time to time in an aggregate amount not to exceed the borrowing base which is calculated based on several factors. As of December 31, 2008, the borrowing base was equal to $1.2 billion, and is subject to annual redeterminations and certain other redeterminations. The lenders agreed to provide $1.2 billion of revolving credit commitments and the Company has an option to increase the facility to $1.45 billion. The lenders commitments under the facility are allocated between U.S. and Canadian funds, with U.S. currency available for borrowing by the Company and either U.S. or Canadian currency available for borrowing in Canada. The facility offers the option to extend the maturity up to two additional years with lender approval. U.S. borrowings under the facility are secured by, among other things, Quicksilvers and its domestic subsidiaries oil and gas properties including applicable reserves. Canadian borrowings under the facility are secured by, among other things, all of our oil and gas properties including applicable reserves. The Company also pledged the equity interests in BBEP it received as part of the BreitBurn Transaction to secure its obligations under the Senior Secured Credit Facility.
The credit facility contain covenants that are more fully described in Note 14 to the consolidated financial statements in Item 8 of this annual report. At December 31, 2008, approximately $369 million was available for borrowing under our Senior Secured Credit Facility and we were in compliance with all covenants. As of January 31, 2009, we had borrowed an additional $130 million under the credit facility. Our ability to remain in compliance with the financial covenants in our credit facility 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.
In connection with the KGS IPO, KGS entered into a five-year $150 million senior secured revolving credit facility (KGS Credit Agreement). In October 2008, the lenders increased the facility to $235 million. Additionally, the revised KGS Credit Agreement features an accordion option of $115 million that allows for the facility to increase to $350 million upon lender approval. KGS must maintain certain financial ratios that can limit its borrowing capacity. The KGS Credit Agreement contains covenants that are more fully described in Note 14 to the consolidated financial statements in Item 8 of this annual report. At December 31, 2008, KGS borrowing capacity was $235 million, and KGS had $175 million in borrowings outstanding under the KGS Credit Agreement. KGS was in compliance with all covenants as of December 31, 2008. KGSs ability to remain in compliance with the financial covenants in its credit facility may be affected by events beyond our control. Any future inability to comply with these covenants, unless waived by the requisite lenders, could adversely affect our liquidity by rendering KGS unable to borrow further under its credit facility and by accelerating the maturity of its indebtedness.
As of December 31, 2008, 2007 and 2006, our total capitalization was as follows:
We believe that our capital resources are adequate to meet the requirements of our existing business. We anticipate that our 2009 capital expenditure budget of approximately $600 million will be funded by cash flow from operations, including application of anticipated income tax refunds and cash distributions received from BBEP. We may, from time to time during 2009, make borrowings under the credit facility, but expect that for all of 2009 to require no incremental borrowings from ending 2008 levels.
Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or other securities, other possible capital markets transactions or the sale of assets, the proceeds of which could be used to refinance current indebtedness or for other corporate purposes. We will also consider from time to time additional acquisitions of, and investments in, assets or businesses that complement our existing asset portfolio. Acquisition transactions, if any, are expected to be financed through cash on hand and from operations, bank borrowings, the issuance of debt or other securities or a combination of those sources.
The following impacted our balance sheet as of December 31, 2008, as compared to our balance sheet as of December 31, 2007:
Contractual Obligations. Information regarding our contractual and scheduled interest obligations, at December 31, 2008, is set forth in the following table.
Commercial Commitments. We had the following commercial commitments as of December 31, 2008:
Our consolidated financial statements are prepared in accordance with GAAP. In connection with the preparation of our financial statements, we are required to make assumptions and estimates about future events, and apply judgments that affect the reported amounts of assets, liabilities, revenue, expenses and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.
Our significant accounting policies are discussed in Note 2 to the consolidated financial statements, included in Item 8 of this annual report. Management believes that the following accounting estimates are the most critical in fully understanding and evaluating our reported financial results, and they require managements most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain. Management has reviewed these critical accounting estimates and related disclosures with our Audit Committee.
We use the full cost method to account for our oil and gas properties. Under the full cost method, all costs associated with the development, exploration and acquisition of oil and gas properties are capitalized and accumulated in cost centers on a country-by-country basis. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The application of the full cost method generally results in higher capitalized costs and higher depletion rates compared to its alternative, the successful efforts method. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production basis using estimated proved oil and gas reserves. Excluded from amounts subject to depletion are costs associated with unevaluated properties.
Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenue, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge the Companys oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, (iii) the lower of cost or market value of unproved properties included in the cost being amortized less (iv) income tax effects related to differences between the book and tax bases of the oil and gas properties. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required.
The discounted present value of future net revenue for our proved oil, natural gas and NGL reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of reserve estimation requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data.
The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. In the past five years, annual revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 1% of the previous years estimate (excluding revisions due to price changes). However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a ceiling test-related impairment. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling limitation, estimation of proved reserves is also a significant component of the calculation of depletion expense.
While the quantities of proved reserves require substantial judgment, the associated prices of natural gas, NGL and crude oil reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation requires that a 10% discount factor be used and that prices and costs in effect as of the last day of the period are held constant indefinitely. Therefore, the future net revenue associated with the estimated proved reserves is not based on our assessment of future prices or costs. Rather, they are based on such prices and costs in effect as of the end of each period when the ceiling calculation is performed. In calculating the ceiling, we adjust the period-end price by the effect of derivative contracts in place that hedge future prices. This adjustment requires little judgment as the period-end price is adjusted using the contract prices for such hedges.
Because the ceiling calculation dictates that prices in effect as of the last day of the applicable year are held constant indefinitely, and requires a 10% discount factor, the resulting value is not necessarily indicative of the fair value of the reserves or the oil and gas properties. Oil and natural gas prices have historically been volatile. At any period end, prices can be either substantially higher or lower than our long-term price forecast. Also, marginal borrowing rates may be well below the required 10% used in the calculation. Rates below 10%, if they could be utilized, would have the effect of increasing the otherwise calculated ceiling amount. Therefore, oil and gas property ceiling test-related impairments that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Prices include consideration of changes in existing prices provided only by contractual arrangements, which do not include financial derivatives that hedge our oil and gas revenue. Our estimates of proved reserves are made and reassessed at least annually using available geological and reservoir data as well as production performance data. Revisions may result from changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions.
All of the reserve data in this annual report are based on estimates. Estimates of our crude oil, natural gas and NGL reserves are prepared in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil, natural gas and NGLs that are ultimately recovered. Estimates of proved crude oil, natural gas and NGL reserves significantly affect our depletion expense. For example, if estimates of proved reserves decline, the depletion rate will increase, resulting in a decrease in net income.
We enter into financial derivative instruments to mitigate risk associated with the prices received from our production. We may also utilize financial derivative instruments to hedge the risk associated with interest rates on our outstanding debt. We account for our derivative instruments by recognizing qualifying derivative instruments on our balance sheet as either assets or liabilities measured at their fair value determined by reference to published future market prices and interest rates. For derivative instruments that qualify as cash flow hedges, the effective portions of gains or losses are deferred in other comprehensive income and recognized in earnings during the period in which the hedged transactions are realized. Gains or losses on qualified derivative instruments terminated prior to their original expiration date are deferred and recognized as income or expense in the period in which the hedged transaction is recognized. If the hedged transaction becomes probable of not occurring, the deferred gain or loss would be immediately recorded to earnings. The ineffective portion of the hedge relationship is recognized currently as a component of other revenue.
The fair value of our natural gas derivatives and associated firm sales commitments as of December 31, 2008 was estimated based on published market prices of natural gas for the periods covered by the contracts. Estimates were determined by applying the net differential between the prices in each derivative and commitment and market prices for future periods, to the volumes stipulated in each contract to arrive at an estimated value of future cash flow streams. These estimated future cash flow values were then discounted for each contract at rates commensurate with federal treasury instruments with similar contractual lives to arrive at estimated fair value.
The estimates of the fair values of our commodity derivative instruments require substantial judgment. Valuations are based upon multiple factors such as futures prices, volatility data from major oil and gas trading points, time to maturity and interest rates. We compare our estimates of fair value for these instruments with valuations obtained from independent third parties and counterparty valuation confirmations. The values we report in our financial statements change as these estimates are revised to reflect actual results.
SFAS No. 123 (revised 2004), Share-Based Payment (SFAS 123R) requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors based on estimated fair value.
Option-pricing models and generally accepted valuation techniques require management to make assumptions and to apply judgment to determine the fair value of our awards. These assumptions and
judgments include estimating the future volatility of our stock price, expected dividend yield, future employee turnover rates and future employee stock option exercise behaviors. Changes in these assumptions can materially affect the fair value estimate.
We do not believe there is a reasonable likelihood that there will be a material change in the future estimates or assumptions that we use to determine stock-based compensation expense. However, if actual results are not consistent with our estimates or assumptions, we may be exposed to changes in stock-based compensation expense that could be material. If actual results are not consistent with the assumptions used, the stock-based compensation expense reported in our financial statements may not be representative of the actual economic cost of the stock-based compensation.
Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that we expect will be in effect during years in which we expect the temporary differences will reverse. Canadian taxes are computed at rates in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested in Canada and thus are not considered available for distribution to us. Net operating loss carry forwards and other deferred tax assets are reviewed annually for recoverability, and if necessary, are recorded net of a valuation allowance.
We must assess the likelihood that deferred tax assets will be recovered from future taxable income and provide judgment on the amount of financial statement benefit that an uncertain tax position will realize upon ultimate settlement. To the extent that we believe that a more than 50% probability exists that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. Significant management judgment is required in determining any valuation allowance recorded against deferred tax assets and in determining the amount of financial statement benefit to record for uncertain tax positions. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed and consider the amounts and probabilities of the outcomes that could be realized upon ultimate settlement of an uncertain tax position using the facts, circumstances and information available at the reporting date to establish the appropriate amount of financial statement benefit. Evidence used for the valuation allowance includes information about our current financial position and results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax assets and liabilities and tax planning strategies available to the Company. To the extent that a valuation allowance or uncertain tax position is established or changed during any period, we would recognize expense or benefit within our consolidated tax expense.
We have no off-balance sheet arrangements within the meaning of Item 303(a)(4) of SEC Regulation S-K.
The information regarding recent accounting pronouncements is included in Note 2 to our consolidated financial statements in Item 8 of this annual report, which incorporated herein by reference.
The information required by this Item is incorporated herein by reference to the information in Note 7 to our consolidated financial statements in Item 8 of this annual report, which is incorporated herein by reference.
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, 2008 and 2007, and the related consolidated statements of income (loss) and comprehensive income (loss), stockholders equity and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Quicksilver Resources Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Companys internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2009 expressed an unqualified opinion on the Companys internal control over financial reporting.
/s/ Deloitte & Touche LLP
Fort Worth, Texas
March 2, 2009
QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006
In thousands, except for per share data
The accompanying notes are an integral part of these consolidated financial statements.
QUICKSILVER RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2008 AND 2007
In thousands, except for share data
The accompanying notes are an integral part of these consolidated financial statements.
QUICKSILVER RESOURCES INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006
In thousands, except for share data