Quicksilver Resources 10-K 2007
Documents found in this filing:
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Commission file number: 001-14837
(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:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
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. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
As of June 30, 2006, the aggregate market value of the registrants common stock held by non-affiliates of the registrant was $1,849,435,922 based on the closing sale price of $36.81 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.
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.
All share and per share amounts have been adjusted to reflect a three-for-two stock split effected in the form of a stock dividend in June 2005.
Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf), million cubic feet (MMcf), billion cubic feet (Bcf) or trillion cubic feet (Tcf). Crude oil and natural gas liquids are quantified in terms of barrels (Bbl), thousands of barrels (MBbl) or millions of barrels (MMBbl). Crude oil and natural gas liquids are compared to natural gas in terms of thousands of cubic feet of natural gas equivalent (Mcfe), millions of cubic feet of natural gas equivalent (MMcfe) or billions of cubic feet of natural gas equivalent (Bcfe). One barrel of crude oil or natural gas liquids is the energy equivalent of six Mcf of natural gas. Natural gas volumes also may be expressed in terms of one million British thermal units (MMBtu), which is approximately equal to one Mcf. Daily natural gas and crude oil production is signified by the addition of the letter d to the end of the terms defined above. With respect to information relating to working interests in wells or acreage, net natural gas and crude oil wells or acreage is determined by multiplying gross wells or acreage by the working interest we own. Unless otherwise specified, all reference to wells and acres are gross.
We are a Fort Worth, Texas-based independent oil and gas company engaged in the development and production of natural gas, natural gas liquids (NGLs) and crude oil, which we attain through a combination of developmental drilling, exploitation and property acquisitions. Our efforts are principally focused on unconventional reservoirs found in fractured shales, coal seams and tight sands. We were organized as a Delaware corporation in 1997 and became a public company in 1999 through a merger with MSR Exploration Ltd. (MSR). Mercury Exploration Company (Mercury), which made significant contributions of properties to us at the time of our formation, was founded by Frank Darden in 1963 to explore for and develop conventional oil and gas properties in the United States. As of December 31, 2006, members of the Darden family, together with Quicksilver Energy, L.P., an entity controlled by members of the Darden family, beneficially owned approximately 34% of our outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self serve on our Board of Directors along with four independent directors. Thomas Darden is Chairman of our Board, Glenn Darden is our President and Chief Executive Officer and Anne Darden Self is our Vice President-Human Resources.
Our operations are concentrated in the Fort Worth, Michigan and Western Canadian Sedimentary Basins. At December 31, 2006, we had estimated proved reserves of 1.57 Tcfe, of which approximately 98% were natural gas and NGLs and approximately 63% were proved developed. Our asset base is geographically diverse, with approximately 45% of our reserves in Texas, 33% in Michigan and 20% in Canada. Since going public in 1999, we have grown our reserves and production at a compound annual growth rate of 25% and 16%, respectively. We believe that much of our future growth will be through development, exploitation and exploration of our leasehold interests, including those in the Barnett Shale formation in the Fort Worth Basin in north Texas, coal bed methane (CBM) formations in Alberta, Canada, and the Barnett Shale and Woodford Shale formations in the Delaware Basin in west Texas. Although our Michigan operations generate significant cash flow, we believe that our future reserve and production growth will come primarily from our Canadian and Texas operations. These projects represent an extension of our significant expertise in unconventional gas reserves.
We intend to focus our capital-spending program primarily on the continued development, exploitation and exploration of our properties in Texas and Alberta, Canada. For 2007, we have established a capital budget of $610 million, of which we have allocated $502 million for drilling activities, $88 million for gathering and processing facilities, $18 million for acquisition of additional leasehold interests and $2 million for other property and equipment. On a regional basis, $425 million has been allocated to the Fort Worth Basin for drilling approximately 170 wells, an increase of over 50 percent when compared to 2006 drilling activity. Canada has been allocated $54 million for drilling and is expected to increase production by approximately 10% in 2007 when compared to 2006 production. In Michigan $18 million has been allocated for drilling in 2007. The remaining $5 million of drilling capital is spread among our other operating areas, Indiana, Kentucky and Montana. The budget for gathering and processing by region is $69 million for Texas, $15 million for Canada, and $4 million for Michigan.
For the year ended December 31, 2006, we had average daily production of 167.8 MMcfed and total production of 61.3 Bcfe. The following table presents our proved reserves and our average daily production for the year ended December 31, 2006. In addition, our geographic segment information is included at note 22 of our consolidated financial statements included in Item 8 of this report.
Our operations in Texas are located in the Fort Worth Basin. Since 2003, when we began exploration and development there, 116 (96.0 net) wells have been completed and tied into sales. We drilled 111.3 net wells in the Fort Worth Basin during 2006 bringing the total number of wells we have drilled in the basin to 157 net wells through December 31, 2006. Substantially all these wells have been horizontal wells. We anticipate drilling an additional 160 to 180 net wells in the basin during 2007 and approximately 200 to 220 net wells in 2008. We expect that wells we plan to drill in 2007 and 2008 will be substantially horizontal wells. At December 31, 2006, we had 12 drilling rigs operating for us in the Fort Worth Basin, and we expect to increase the number of rigs to 16 during 2007. In 2006, sales from Texas averaged 34.7 MMcfed and at December 31, 2006, our wells in the Fort Worth Basin were producing approximately 53.9 net MMcfed. At December 31, 2006, proved reserves from our interests in the Fort Worth Basin totaled 703.9 Bcfe, and we held a net acreage position of approximately 275,000 acres in Texas.
We have constructed additional infrastructure to augment our development, exploitation and exploration of the Fort Worth Basin. At the end of 2006, we had approximately 120 miles of natural gas gathering lines, ranging from 2 inches to 20 inches, which we refer to as the Cowtown Pipeline. The Cowtown Pipeline transports natural gas produced from Quicksilver and third party wells to our natural gas processing plant in Hood County, Texas (Cowtown Plant). We also own a 22-mile NGL pipeline that runs from our Cowtown Plant to a third party pipeline interconnect. During 2007, we expect to add natural gas gathering lines as we, and other third parties, continue to drill and complete wells in the area. We have acquired right-of-way and are in the process of building a second NGL transportation line to an NGL intrastate pipeline approximately four miles east of our Cowtown Plant. Upon completion of a new state-of-the-art gas processing unit in early 2007, Cowtown Plant will have processing capacity of 200 MMcfd. We have begun planning for a third gas processing unit that we anticipate will be operational in late 2008 and bring processing capacity to 325 MMcfd.
We conduct our Canadian operations through our wholly-owned subsidiary, Quicksilver Resources Canada Inc., (QRCI), formerly known as MGV Energy Inc. Since 2003, when QRCI ended its joint venture with EnCana, we have expanded our operations in the Western Canadian Sedimentary Basin. Net gas sales from our projects in Alberta averaged 50.1 MMcfd for 2006 and were producing approximately 57.4 MMcfed at December 31, 2006. During 2006, we drilled 400 (215.2 net) productive wells with 336 gross (187.2 net) wells completed and tied into sales. Also during 2006, we installed ten CBM facilities for processing our natural gas production. During 2007, QRCI plans to drill 438 (225 net) wells and has included $3 million in its 2007 drilling budget for additional testing in its Mannville exploration project.
As of December 31, 2006, we had 308.4 Bcfe of Canadian proved reserves, which were primarily attributable to our CBM projects, and held approximately 234,300 net undeveloped acres. At December 31, 2006, Canada comprised 20% of our reserves, 30% of our annual production and approximately $69 million, or 32%, of our cash flow from operations.
In Michigan we produce gas from the Antrim Shale as well as non-Antrim reservoirs. Total production in Michigan for 2006 averaged 75.1 MMcfd and total proved reserves in Michigan were 521.4 Bcfe at December 31, 2006. In the Michigan Antrim Shale, we drilled or participated in 83 (49.3 net) Antrim wells during 2006. Net production in 2006 for our interests in the Antrim Shale averaged 55.6 MMcfd and December 31, 2006 proved reserves were 451.5 Bcf. Net production from our Michigan non-Antrim properties averaged 19.5 MMcfed. Proved reserves from our interests in our non-Antrim properties were 69.9 Bcfe.
Production from our Indiana/Kentucky properties averaged 4.7 MMcfd for 2006 while production from our properties in the Rocky Mountains averaged 3.3 MMcfed. At December 31, 2006, our proved reserves were 17.4 Bcfe from our Indiana/Kentucky interests and 16.4 Bcfe from Rocky Mountain interests in the U.S.
High quality asset base with long reserve life. We had total proved reserves of 1.57 Tcfe as of December 31, 2006, of which approximately 98% were natural gas and NGLs and approximately 63% were proved developed. The majority of these reserves are located in three core areas: the Fort Worth Basin in Texas, the Michigan Basin and the Western Canadian Sedimentary Basin in Alberta, Canada, which accounted for approximately 45%, 33% and 20%, respectively, of our proved reserves. Based on average daily production of 167.8 MMcfe for the year ended December 31, 2006, our implied reserve life (proved reserves divided by 2006 annual production) was 25.6 years
and our implied proved developed reserve life was 16.1 years. We believe our assets are characterized by long reserve lives and predictable well production profiles. As of December 31, 2006, we were the operator of approximately 78% of our proved reserves.
Significant development and exploitation drilling inventory. As of December 31, 2006, we owned leases covering over 1.4 million net acres in our core areas of operation, of which 71% were undeveloped. This drilling inventory should provide us with more than 4,000 identified drilling locations which we expect to exploit over the next eight to ten years. Our drilling success rate has averaged 98% over 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. For 2007, we have budgeted approximately $502 million for drilling projects.
Proven track record of organic reserve and production growth. Over the last three years, we have added approximately 865 Bcfe to our reserves, virtually all of which was achieved organically. This growth was the result of our ability to acquire attractive undeveloped acreage and apply our technical expertise to find and develop reserves and was accompanied by a significant increase in our overall production. In recent years, we have demonstrated this ability particularly in the Horseshoe Canyon formation in Alberta and the Barnett Shale formation in the Fort Worth Basin. We believe our current acreage position will enable us to continue our reserve and production growth.
Experienced management and technical teams. Our CEO, Glenn Darden, and our Chairman, Thomas Darden, are founding members of our company and have held executive positions at Quicksilver since we were formed in 1997. They both have been in the oil and 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 reserves. 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.
Our business strategy is designed to achieve our principal objectives of cost effective growth in reserves and production which result in growth of earnings and cash flow. Key elements of our business strategy include:
Focus on core areas of operation. We intend to continue to focus on exploiting our significant development inventory in our Barnett Shale properties in the Fort Worth Basin and our Canadian CBM properties in the Western Canadian Sedimentary Basin. We anticipate drilling approximately 400 net development wells in these formations in 2007. We also plan to continue to evaluate potential development opportunities in the Mannville CBM in Canada by drilling resource assessment wells and complete our evaluation of three resource assessment wells drilled during 2006 in the Delaware Basin in west Texas. We also plan to optimize our production in Michigan through additional horizontal recompletions and other infill drilling opportunities. We believe that operating in concentrated areas allows us to more efficiently deploy our resources and manage costs. In addition we can further leverage our base of technical expertise in these regions.
Pursue disciplined organic growth strategy. Through our activities in each of the Michigan, Western Canadian Sedimentary and Fort Worth Basins, we have developed significant expertise in developing and operating reservoirs found in fractured shales, coal seams and tight sands. We have focused on identifying and evaluating opportunities that allow us to apply this expertise and experience to the development and operation of other unconventional reservoirs. Our Barnett Shale play in Texas and our Horseshoe Canyon CBM play in Canada are the most significant examples of the success of this strategy. The Delaware Basin in Texas and the Mannville CBM in Canada represent our most recent opportunities to apply this strategy again in areas that are today considered exploration plays.
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 natural gas and crude oil from the areas where we have production to third-party distribution pipelines. We seek to achieve this by continuing to improve upon and add to our processing and distribution 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-party providers. We also monitor on a daily basis the spot markets and seek to sell our uncommitted production into the most attractive markets.
Maintain conservative financial profile. We believe that maintaining a conservative financial structure will position us to capitalize on opportunities to limit our financial risk. We have also established return thresholds for new projects. In addition, to help ensure a level of predictability in the prices we receive for our natural gas and crude oil production, we have entered into natural gas sales contracts with price floors and natural gas and crude oil financial hedges.
We own significant natural gas and crude oil production interests in the following geographic areas:
Our operations in the Fort Worth Basin in northern Texas comprised approximately 45% of our estimated proved reserves and approximately 21% of our average daily production for the year ended December 31, 2006. The 2007 capital budget allocated to our Texas interests is approximately $425 million for drilling 191 (171 net) wells. We anticipate drilling approximately 200 to 220 net wells in 2008.
During 2006, we drilled 111.3 net wells in the Fort Worth Basin Barnett Shale and at December 31, 2006, we had drilled a total of 157 net wells in the basin and were producing from 116 (96.0 net) wells. Our interests are spread over an area stretching north-to-south from central Tarrant County to central Bosque County, and west-to-east from eastern Erath County through Hill County. At December 31, 2006, we held approximately 275,000 net acres in the Fort Worth Basin Barnett Shale play with approximately 2,000 drilling locations.
In April 2006, we began operation of a 75 MMcfd natural gas processing unit in Hood County, Texas. Completion of a newly constructed state-of-the-art processing unit with processing capacity of 125 MMcfd is expected in early 2007. At our Cowtown Plant, we process natural gas to extract the NGLs from the natural gas stream and deliver the residue gas to third party intrastate pipelines. We have begun planning for a third processing unit that we expect to become operational in the fourth quarter of 2008. We expect the third unit to provide 125 MMcfd of additional capacity and bring the total processing capacity to 325 MMcfd.
Our pipeline system located in the southern portion of the Fort Worth Basin includes approximately 120 miles of natural gas gathering pipelines, ranging from 2 inches to 20 inches in diameter and a 22-mile NGL pipeline that runs from the Cowtown Plant to an interconnecting third party pipeline. The pipeline system gathers and delivers natural gas produced by our wells and those of third parties to the Cowtown Plant. We expect to continue to construct additional pipelines to gather and transport natural gas to the Cowtown Plant as additional wells in the Fort Worth Basin are drilled and completed. We have acquired right-of-way and are in the process of building a second NGL transportation line to an NGL intrastate pipeline four miles east of our Cowtown Plant. The budget for 2007 includes approximately $69 million for our Fort Worth Basin pipelines and natural gas processing facility.
During 2005, we acquired approximately 310,000 net acres in a contiguous block of west Texas. We drilled three resource assessment wells on that acreage to evaluate the Barnett and Woodford Shales in the Delaware Basin during 2006. We are continuing to evaluate these resource assessment wells and hope to complete that evaluation during 2007.
Our Michigan operations comprised approximately 33% of our estimated proved reserves and approximately 45% of our average daily production for the year ended December 31, 2006. Michigan has favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas and currently imports approximately 75% of its demand. This supply/demand situation has allowed us to sell our natural gas production at a slight premium to industry benchmark prices.
The Antrim Shale underlies a large percentage of our Michigan acreage and is fairly homogeneous in terms of reservoir quality; wells tend to produce relatively predictable amounts of natural gas in this reservoir. Subsurface fracturing can increase reserves and production attributable to any particular well. On average, Antrim Shale wells have a total productive life of more than 20 years. As new wells produce and the de-watering process takes place, they tend to reach a maximum production level in six to 12 months, remaining at these levels for one to two years, and then declining at 8% to 10% per year thereafter. The wells tend to produce the best economic results when drilled in large numbers in a fairly concentrated area. This well concentration provides for a more rapid de-watering of a specific area, which decreases the time to natural gas production and increases the amount of natural gas production. It also enables us to maximize the use of existing production infrastructure, which decreases per unit operating costs. Since reserve quantities and production levels over a large number of wells are fairly predictable, maximizing per well recoveries and minimizing per unit production costs through a sizeable well-engineered drilling program are the keys to profitable Antrim development.
Our non-Antrim interests are located in several reservoirs including the Prairie du Chien (PdC), Richfield, Detroit River Zone III (DRZ3) and Niagaran pinnacle reefs. Depending upon the area and the particular zone, the PdC will produce dry gas, gas and condensate or oil with associated gas. Our PdC production is well established, and there are numerous proved non-producing zones in existing well bores that provide recompletion opportunities, allowing us to maintain or, in some cases, increase production from our PdC wells as currently producing reservoirs deplete.
Our Richfield/Detroit River wells are located in Kalkaska and Crawford counties in the Garfield and Beaver Creek fields. The Garfield Richfield has seven wells producing under primary solution gas drive. Potential exploitation of the Garfield Richfield either by secondary waterflood and/or improved oil recovery with CO2 injection is under evaluation; however, because this concept has not been proved there are no recorded reserves related to these techniques.
The DRZ3 at Beaver Creek lies approximately 200 feet above the Richfield reservoir. We had 26 producing wells as of December 31, 2006. Production from the DRZ3 at Beaver Creek consists of oil with associated natural gas. While there is the opportunity for improving production and proved reserve quantities, we have determined that our resources are better allocated to continued development, exploitation and exploration of our many unconventional gas projects.
Our Niagaran wells produce from numerous Silurian-age Niagaran pinnacle reefs located in nine northern Michigan counties. Depending upon the location of the specific reef in the pinnacle reef belt of the northern shelf area, the Niagaran reefs will produce dry gas, gas and condensate or oil with associated gas.
We began to focus on the potential of Canadian CBM through QRCI in 2000. In late 2000, we entered into a joint venture with EnCana to explore for and develop CBM reserves initially in the West Palliser block in Alberta. In January 2003, we entered into an asset rationalization agreement with EnCana that divided the assets and rights subject to the joint venture and allowed us to pursue independent operations. Since that time, QRCI held interests in
1,924 (925.3 net) productive wells at December 31, 2006. Our total Canadian proved reserves at December 31, 2006 were estimated to be 308.4 Bcf while our average daily production in Canada for 2006 was 50.1 MMcfed.
During 2007, we expect to drill 438 (225 net) wells and install five new CBM processing facilities. Each plant will be capable of processing five to ten MMcfd of natural gas production. Approximately $54 million will be committed to Canadian drilling including approximately $3 million for additional testing of the Mannville coals with an additional $20 million budgeted in 2007 for gathering lines, gas processing facilities and leasehold costs.
We began our operations in the New Albany Shale of southern Indiana and north Kentucky in 2000 with the acquisition of 36 producing wells and an eight-mile 12-inch GTG gas pipeline that runs from southern Indiana to northern Kentucky. Our New Albany production is transported through an extension of our GTG gas pipeline that we constructed in 2003 and connects to the Texas Gas Pipeline in northern Kentucky. For 2006, natural gas sales from our properties in the area averaged 4.7 MMcfd.
Our Rocky Mountain properties are located in Montana and Wyoming. Production from those properties is primarily crude oil from well-established producing formations at depths ranging from 1,000 feet to 17,000 feet. At December 31, 2006, our Rocky Mountain proved reserves were 2.4 MMBbls of crude oil and 1.9 Bcfe of natural gas and NGLs for total equivalent reserves of 16.4 Bcfe. Daily production from our properties in the Rocky Mountain region averaged 3.3 MMcfed for 2006.
We sell natural gas, NGLs and crude oil to a variety of customers, including utilities, major oil and 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 a single purchaser in the areas in which we sell our products would not materially affect our sales. During 2006, the largest purchaser of our products was DTE Energy Trading Inc., which accounted for approximately 10% of our total natural gas, NGL and crude oil sales.
We encounter substantial competition in acquiring oil and gas leases and properties, marketing natural gas and crude oil, securing personnel and conducting our drilling and field operations. Our competitors in development, exploitation, exploration, acquisitions and production include the major oil and gas companies as well as numerous independents and individual proprietors. See Item 1A. Risk Factors.
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. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted so we are unable to predict the future cost or impact of complying with such laws and regulations.
Our natural exploration, development, production and pipeline gathering 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 wastes as hazardous wastes and make the reclassified wastes 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 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 gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be constructed, abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in substantial cash expenses, including possible fines and penalties.
In Alberta, environmental compliance has been governed by the Alberta Environmental Protection and Enhancement Act (AEPEA) since September 1, 1993. AEPEA imposes environmental responsibilities on oil and gas operators in Alberta and also imposes penalties for violations.
We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission, or SEC. Our SEC filings are available to the public over the Internet at the SECs website at www.sec.gov or from our website at www.qrinc.com. You may also read and copy any document we file at the SECs public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operations of the public reference room. In addition, we make available free of charge through our Internet website at http://www.qrinc.com, our annual report 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 Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
Additionally, charters for the committees of our Board of Directors and our Corporate Governance Guidelines and Code of Business Conduct and Ethics can be found on our Internet website at http://www.qrinc.com under the heading Corporate Governance. Stockholders may request copies of these documents by writing to the Investor Relations Department at 777 West Rosedale Street, Suite 300, Fort Worth, Texas 76104.
As of February 15, 2007, we had 488 full time employees and 6 part time employees. There are no collective bargaining agreements.
The following information is provided with respect to our executive officers as of February 15, 2007.
Executive officers are elected by our Board of Directors and hold office at the pleasure of the Board until their successors are elected and qualified. Thomas F. Darden, Glenn Darden and Anne Darden Self are siblings. The following biographies describe the business experience of our executive officers.
THOMAS F. DARDEN has served on our Board of Directors since December 1997. He also served at that time as President of Mercury Exploration Company (Mercury). During his term as President of Mercury, Mercury developed and acquired interests in over 1,200 producing wells in Michigan, Indiana, Kentucky, Wyoming, Montana, New Mexico and Texas. Prior to joining us, Mr. Darden was employed by Mercury or its parent corporation, Mercury Production Company, for 22 years. He became a director and the President of Mountain States Resources, Inc. (MSR) on March 7, 1997. On January 1, 1998, he was named Chairman of the Board and Chief Executive Officer of MSR. He was elected our President when we were formed and then Chairman of the Board and Chief Executive Officer on March 4, 1999, the date of our acquisition of MSR. He served as our Chief Executive Officer until December 1999.
GLENN DARDEN has served on our Board of Directors since December 1997. Prior to that time, he served with Mercury for 18 years, and for the last five of those 18 years was the Executive Vice President of Mercury. Prior to working for Mercury, Mr. Darden worked as a geologist for Mitchell Energy Company LP (subsequently merged with Devon Energy). Mr. Darden became a director and Vice President of MSR on March 7, 1997, and was named President and Chief Operating Officer of MSR on January 1, 1998. He served as our Vice President until he was elected President and Chief Operating Officer on March 4, 1999. Mr. Darden then became our Chief Executive Officer in December 1999.
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 with Banc PLUS Savings Association in Houston, Texas. She was employed as Marketing Director and then spent three years 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 and became Vice President of Operations in 1991 and Executive Vice President in 1998 of Mercury before joining us.
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. He was employed by Union Pacific Resources 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 was promoted to the position of
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.
PHILIP COOK became our Senior Vice President Chief Financial Officer in October 2005. From October 2004 until October 2005, Mr. Cook served as President, Chief Financial Officer and Director of EcoProduct Solutions, a Houston-based 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.
D. WAYNE BLAIR became our Vice President, Controller and Chief Accounting Officer in 2002, after serving as our Vice President Controller since July 2000. He is a Certified Public Accountant with over 25 years of experience in the oil and gas industry. He was employed by Sabine Corporation from 1980 through 1988 where he held the position of Assistant Controller. From 1988 through 1994, he served as Controller for a group of private businesses involved in the oil and gas industry. Prior to joining us in April 2000 as Vice President Controller, he served as Controller for Mercury since 1996.
WILLIAM S. BUCKLER became our Vice President U.S. Operations in August 2005. He joined us in September 2003 as an Engineering Manager. Prior to that, he was an Operations/Engineering Supervisor with Mitchell Energy Company LP (subsequently merged with Devon Energy) from January 2002 until August 2003, and held various other positions with Mitchell Energy, including Region Engineer, from July 1997 until January 2002.
ROBERT N. WAGNER became our Vice President Reservoir Engineering in December 2002. He had served 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. for over eight years and served as both drilling engineer and production engineer.
MARLU HILLER became our Vice President Treasurer in January 2007. Since May 2000, she had served as our Treasurer. She is a Certified Public Accountant with over 20 years of experience in public and oil and gas accounting. Prior to joining us in August of 1999 as Director of Financial Reporting and Planning, she was employed at Union Pacific Resources serving in various capacities, including Manager of Accounting for Union Pacific Fuels, which was Union Pacific Resources marketing company.
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. In evaluating us, you should consider carefully, among other things, the factors and the specific risks set forth below, and in documents we incorporate by reference. This annual report contains forward-looking statements that involve risks and uncertainties.
Because we have a limited operating history in certain of our operating areas, our future operating results are difficult to forecast, and our failure to sustain profitability in the future could adversely affect the market price of our common stock.
We may not maintain the current level of revenues, natural gas and crude oil reserves or production we now attribute to the properties contributed to us when we were formed and those developed and acquired since our formation. Any future growth of our natural gas and crude oil reserves, production and operations could place significant demands on our financial, operational and administrative resources. Our failure to sustain profitability in the future could adversely affect the market price of our common stock.
Natural gas and crude oil prices fluctuate widely, and low prices could have a material adverse impact on our business.
Our revenues, profitability and future growth depend in part on prevailing natural gas 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 facilities is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas 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. For example, the closing New York Mercantile Exchange (NYMEX) wholesale price of natural gas was at a six-year low of approximately $2.98 per Mcf for August of 2002 and reached an all-time high of approximately $13.91 per Mcf for October of 2005. During 2006, the closing NYMEX wholesale natural gas price ranged from $11.45 per Mcf for January of 2006 to a low of $4.20 per Mcf for October of 2006. 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 affect natural gas and crude oil prices, we cannot predict whether prices will remain at current levels, increase or decrease in the future.
If natural gas or crude oil prices decrease or our exploration and development efforts are unsuccessful, we may be required to take writedowns.
Our financial statements are prepared in accordance with generally accepted accounting principles. The reported financial results and disclosures were developed using certain significant accounting policies, practices and estimates, which are discussed in the Managements Discussion and Analysis of Financial Condition and Results of Operations section in this annual report. We employ the full cost method of accounting 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 and crude oil reserves. A write down of these capitalized costs could be required if natural gas and/or crude oil prices were to drop precipitously at a reporting period end. Future price declines or increased operating and capitalized costs without incremental increases in natural gas and crude oil reserves could also require us to record a write down.
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 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 and crude oil reserves are inherently imprecise.
Actual future production, natural gas and crude oil prices and revenues, 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 natural gas and crude oil prices and other factors, many of which are beyond our control.
At December 31, 2006, approximately 37% of our estimated proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our natural gas and crude oil reserves and the costs associated with these reserves in accordance with industry standards and SEC requirements, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that actual results will be as estimated.
You should not assume that the present value of future net revenues disclosed in this annual report is the current market value of our estimated natural gas and crude oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. 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 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 accurate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the accuracy of the 10% discount factor.
Approximately 45% of our 2006 production was from Michigan, approximately 30% was from Alberta, Canada and approximately 21% was from Texas. 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.
If our production levels were significantly reduced to levels below those for which we have entered into contractual delivery commitments, we would be required to purchase natural gas at market prices to fulfill our obligation under certain long-term contracts. This could adversely affect our cash flow to the extent any such shortfall related to our sales contracts with floor pricing.
Our Canadian operations present unique risks and uncertainties, different from or in addition to those we face in our domestic operations.
We conduct our Canadian operations through Quicksilver Resources Canada Inc. At December 31, 2006, our proved Canadian reserves were estimated to be 308 Bcf. Capital expenditures relating to QRCIs operations are budgeted to be approximately $74 million in 2007, constituting approximately 12% of our total 2007 budgeted capital expenditures.
We expect that our 2007 Canadian capital budget will be funded from Canadian operating cash flow. If our revenues decrease as a result of lower natural gas or crude oil prices or otherwise, we may be unable to fund our entire 2007 Canadian capital budget, or may opt to increase our Canadian debt levels to fund 2007 capital expenditures. While our results to date indicate that net recoverable reserves on CBM lands could be substantial, we can offer you no assurance that development will occur as scheduled or that actual results will be in accordance with estimates.
Other risks of our operations in Canada include, among other things, 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 and expect to continue to experience substantial capital expenditure and working capital needs, particularly as a result of increases in our property acquisition and drilling activities. In the future, we will likely require additional financing in addition to cash generated from our operations to fund our planned growth. If revenues decrease as a result of lower natural gas or crude oil 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 acquisition, development drilling and other 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 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 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 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, the payment of which could reduce or eliminate funds available for exploration, development or acquisitions. 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.
We may be unable to make additional acquisitions of producing properties or successfully integrate them into our operations.
A portion of our growth in recent years has been due to acquisitions of producing properties. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers to be favorable to us. We cannot assure you that we will be able to identify suitable acquisitions in the future, or that we will be able to finance these acquisitions on favorable terms or at all. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will be successful in the acquisition of any material producing property interests. Further, we cannot assure you that any future acquisitions that we make will be integrated successfully into our operations or will achieve desired profitability objectives.
The successful acquisition of producing properties requires an assessment of recoverable reserves, exploration potential, future natural gas and crude oil prices, operating costs, potential environmental and other liabilities and other factors beyond our control. These assessments are inexact and their accuracy inherently uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.
In addition, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geological characteristics or geographic location than existing properties. While our current operations are located primarily in Michigan, Alberta, Canada, Texas, Indiana, Kentucky and Montana, we cannot assure you that we will not pursue acquisitions of properties in other locations.
Our future success depends upon our ability to find, develop or acquire additional natural gas and crude oil reserves that are economically recoverable. Our proved reserves, a majority of which are in the mature Michigan Basin, will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. 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, production and cash flow through development and exploration of our existing properties and acquisitions of producing properties. We cannot assure you, however, that our planned exploration and development projects and acquisition activities will result in significant additional reserves or that we will have continuing success drilling productive wells. Furthermore, while our revenues may increase if prevailing natural gas and crude oil prices increase significantly, our finding costs for additional reserves also could increase.
As of December 31, 2006, other companies operated properties that included approximately 22% of our proved reserves. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. As a result, the success and timing of our drilling and development activities on properties operated by others depend upon a number of factors that are outside of our control, including:
We cannot control the operations of gas processing and transportation facilities we do not own or operate.
At December 31, 2006, other companies owned processing plants and pipelines that delivered approximately 64% of our natural gas production to market in Michigan. Our Canadian production is delivered to market primarily by either the TransCanada or ATCO systems. We have no influence over the operation of these facilities and must depend upon the owners of these facilities to minimize any loss of processing and transportation capacity.
Our operations are dependent on a relatively small group of key management personnel, including our Chairman, our Chief Executive Officer and our other executive officers and key technical personnel. We cannot assure you that the services of these individuals will be available to us in the future. Because competition for experienced personnel in the oil and gas industry is intense, we cannot assure you that we would be able to find acceptable replacements with comparable skills and experience in the oil and gas industry. Accordingly, the loss of the services of one or more of these individuals could have a detrimental effect on us.
Competition in our industry is intense, and we are smaller and have a more limited operating history than most of our competitors.
We compete with major and independent oil and gas companies for property acquisitions. We also compete for the equipment and labor required to develop and operate these 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 gas industry competes with other industries in supplying the energy and fuel needs of industrial, commercial, and other consumers.
Several companies have entered into purchase contracts with us for a significant portion of our production and, if they default on these contracts, we could be materially and adversely affected.
Our long-term natural gas contracts, which extend through March 2009, accounted for the sale of approximately 27% of our natural gas production and for a significant portion of our total revenues in 2006. We cannot assure you that the other parties to these contracts will continue to perform under the contracts. If the other parties were to default after taking delivery of our natural gas, it could have a material adverse effect on our cash flows for the period in which the default occurred. A default by the other parties prior to taking delivery of our natural gas could also have a material adverse effect on our cash flows for the period in which the default occurred depending on the prevailing market prices of natural gas at the time compared to the contractual prices.
To reduce our exposure to fluctuations in the prices of natural gas and crude oil, we have entered into natural gas and crude oil hedging arrangements. These hedging arrangements tend to limit the benefit we would receive from increases in the prices of natural gas and crude oil. These hedging arrangements also expose us to risk of financial losses in some circumstances, including the following:
The result of natural gas and crude oil market prices exceeding our swap prices requires us to make payment for the settlement of our hedge derivatives on the fifth day of the production month for natural gas hedges and the fifth day after the production month for crude oil hedges. We do not receive market price cash payments from our customers until 25 to 60 days after the end of the production month. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.
If we choose not to engage in hedging arrangements in the future, we may be more adversely affected by changes in natural gas 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.
There is currently a high demand for and a general shortage of drilling equipment and supplies. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. We believe that these shortages could continue. Accordingly, we cannot assure you that we will be able to 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 in the future. 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 and crude oil operations are subject to various U.S. and Canadian federal, state, provincial and local government laws and regulations that may be changed from time to time 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 natural gas and crude oil 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.
We have a substantial amount of debt and the cost of servicing that debt could adversely affect our business; and such risk could increase if we incur more debt.
We have a substantial amount of indebtedness. At December 31, 2006, we had total consolidated debt of $919.5 million. Subject to the limits contained in the loan agreements governing our senior secured revolving credit facilities and the indenture governing our senior subordinated notes, we may incur additional debt. Our ability to borrow under our senior secured revolving credit facilities is subject to the quantity of proved reserves attributable to our natural gas and crude oil properties. One of our senior secured revolving credit facilities enables us to borrow significant amounts in Canadian dollars to fund and support our operations in Canada. Such indebtedness exposes us to currency exchange risk associated with the Canadian dollar. If we incur additional indebtedness or fail to
increase the quantity of proved reserves attributable to our natural gas and crude oil properties, 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 on our indebtedness, including, among others, operating expenses and principal payments under our senior secured revolving credit facilities, our senior subordinated notes and our convertible subordinated debentures. Our level of indebtedness relative to our proved reserves and these significant demands on our cash resources could have important effects on our business and on your investment in Quicksilver. 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, our financial condition, results of operations and prospects and other factors, many of which are beyond our control.
If we are unable to service our indebtedness and fund our operating costs, we will be forced to adopt alternative strategies that may include:
There can be no assurance that any such strategies could be implemented on satisfactory terms, if at all.
Our senior secured revolving credit facilities and senior subordinated notes restrict our ability and the ability of some of our subsidiaries to engage in certain activities.
The loan agreements governing our senior secured revolving credit facilities and the indenture governing our senior subordinated notes restrict our ability to, among other things:
The loan agreements for our senior secured revolving credit facilities and the indentures governing our senior subordinated notes contain certain covenants, which, among other things, require the maintenance of a minimum current ratio, a minimum collateral coverage ratio, a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio, and a minimum earnings (before interest, taxes, depreciation, depletion, accretion and amortization, non-cash income and expense and exploration costs) to fixed charges ratio. Our ability to borrow under our senior secured revolving credit facilities is dependent upon the quantity of proved reserves attributable to our natural gas and crude oil properties. Our ability to meet these covenants or requirements may be affected by events beyond our control, and we cannot assure you that we will satisfy such covenants and requirements.
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 covenants in our loan agreements or the indenture governing our senior subordinated notes, or any instrument governing our future indebtedness, or our inability to maintain the financial ratios described above could result in an event of default under the applicable instrument. Upon the occurrence of such an event of default, the applicable creditors could, subject to the terms and conditions of the applicable instrument, 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 that would be triggered by such default or acceleration would also be subject to acceleration upon the occurrence of such default or acceleration. If we were unable to repay amounts due under our senior secured revolving credit facilities, the creditors could proceed against the collateral granted to them to secure such indebtedness. If the payment of our indebtedness is accelerated, there can be no assurance that our assets would be sufficient to repay in full such indebtedness and our other indebtedness that would become due as a result of any acceleration. The above restrictions could limit our ability to obtain future financing and may prevent us from taking advantage of attractive business opportunities.
A small number of existing stockholders control our company, which could limit your ability to influence the outcome of stockholder votes.
Members of the Darden family, together with Quicksilver Energy, L.P., which is primarily owned by members of the Darden family, beneficially own on the date of this annual report approximately 34% of our common stock. As a result, these entities and individuals will generally be able to control 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 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 doing well.
Our shares that are eligible for future sale may have an adverse effect on the price of our common stock. There were 77,601,922 shares of our common stock outstanding at December 31, 2006. Approximately 49,821,419 of these shares are freely tradable without substantial restriction or the requirement of future registration under the Securities Act. In addition, our contingently convertible debentures are convertible upon the satisfaction of certain conditions. Based on the conversion rate in effect at December 31, 2006, if the conditions permitting the conversion of all of our outstanding contingently convertible debentures are satisfied and all of the outstanding debentures are
converted, an aggregate of 4,908,135 shares of our common stock would be issued. At December 31, 2006 we had the following options outstanding to purchase shares of our common stock:
Sales of substantial amounts of common stock, or a perception that such sales could occur, and the existence of options to purchase 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, such as:
In addition, we have adopted a stockholder rights plan. The provisions described above and the stockholder rights plan could impede a merger, consolidation, takeover or other business combination involving us or discourage a potential acquirer from making a tender offer or otherwise attempting to take control of 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 portion of the information called for by this Item is incorporated herein by reference to the information in Item 1 of this report under the heading Properties. U.S. borrowings under our senior secured credit facility are secured by our and certain of our domestic subsidiaries oil and gas properties, and Canadian borrowings under our senior secured credit facility are secured by QRCIs, our and certain of our domestic subsidiaries oil and gas properties.
The following reserve quantity and future net cash flow information concerns our proved reserves that are located in the United States and Canada. Independent petroleum engineers with Schlumberger Data and Consulting Services and LaRoche Petroleum Consultants, Ltd. prepared our reserve estimates for our United States and Canadian properties, respectively. Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10(a) 2(i), 2(ii), 2(iii), (3) and (4), are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided by contractual arrangements, but not of escalations based upon expected future conditions. Prices include the effect of our derivative instruments. Future production and development costs include production and property taxes.
Proved developed oil and gas reserves are reserves that are expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped oil and 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 gas reserves is based on estimates that are highly complex and interpretive. Reserve engineering is a subjective process that is dependent on 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, 2006, 2005 and 2004.
The following table sets forth certain information regarding production, average unit prices and costs for the periods indicated:
During the periods indicated, the Company drilled or participated in the drilling of the following exploratory and development wells:
The following table summarizes productive oil and gas wells attributable to our direct interests as of December 31, 2006:
Our principal natural gas and crude oil properties consist of non-producing and producing natural gas and crude oil leases, including reserves of natural gas and crude oil in place. The table found below indicates our interest in developed and undeveloped acreage held directly by us. Developed acres are defined as acreage spaced or 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 quantities of crude oil, condensate or natural gas, 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 lists the total number of net undeveloped acres as of December 31, 2006, and, with respect to those acres for 2007, 2008 and 2009, the number of net acres expiring, and, where applicable, the number of net acres expiring that are subject to options to extend. The option to extend varies from lease to lease and covers periods from one to five years; however, the majority of the options to extend are for two years.
All of the acreage scheduled to expire can be held through drilling operations. We believe that we have the ability to hold all of the expiring acreage that we feel is prospective of economic production through the drilling of wells and, where applicable, through the exercise of extension options to be followed by drilling prior to final expiration.
In August 2001, a group of royalty owners, Athel E. Williams et al., brought suit against the Company and three of its subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd., one of Quicksilvers subsidiaries, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who have yet to be determined. The pleadings of the plaintiffs seek damages in an unspecified amount and injunctive relief against future underpayments. On January 21, 2005, the Circuit Court issued an order certifying certain claims to proceed on behalf of a class. On July 25, 2006, the Michigan Court of Appeals reversed the certification of all claims on appeal and remanded the case to the trial court for further proceedings. Based on information currently available to us, we believe that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.
On October 13, 2006, we filed suit in the 342nd Judicial District Court in Tarrant County, Texas against Eagle Drilling, LLC and Eagle Domestic Drilling Operations, LLC (successor in interest to Eagle Drilling, together Eagle) regarding three contracts for drilling rigs in which we allege that the first rig furnished by Eagle exhibited operating deficiencies and safety defects. We seek a declaratory judgment that (i) the contracts are void and (ii) that Eagle is not entitled to early termination compensation provided for in the contracts. We also seek rescission of the contracts and claim we are entitled to recover damages incurred due to Eagles failure to perform. On October 23, 2006, Eagle Domestic Drilling sued us in District Court of Cleveland County, Oklahoma for (i) breach of contract as to each of the three drilling contracts alleging damages of $29 million plus punitive damages and interest and (ii) tortious breach of contract alleging damages in an unspecified amount in excess of $10,000. Eagle Domestic Drilling also sought a declaratory judgment that, among other things, the contracts are valid and binding. Subsequently, on January 19, 2007, Eagle Domestic Drilling and its parent, Blast Energy Services, Inc., filed for Chapter 11 bankruptcy the United States Bankruptcy Court for the Southern District of Texas, Houston Division. At the date of this filing, the suit in Tarrant County is still pending, but is stayed. On February 21, 2007, the lawsuit in Cleveland County was dismissed. Based upon information currently available, we believe that the final resolution of this matter will not have a material effect on our financial condition, results of operations, or cash flows.
There were no matters submitted to a stockholder vote during the fourth quarter of 2006.
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 February 15, 2007, there were approximately 561 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, our senior secured credit facility prohibits payments of dividends on our common stock and purchases of common stock. The indenture for our senior subordinated notes prohibits payments on our common stock.
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) and the Dow Jones U.S. Exploration and Production Index (formerly the Dow Jones Secondary Oils Index) for the period from December 31, 2001 to December 31, 2006, 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, 2006.
The following table sets forth, as of the dates and for the periods indicated, our selected financial information. Our financial information 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 document. The following information is not necessarily indicative of our future results.
Selected Financial Data
The following Managements Discussion and Analysis (MD&A) is intended to help the reader understand our business, financial condition, results of operations, 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 on Form 10-K, including: Item 1. Business, Item 2. Properties, Item 6. Selected Financial Data, and Item 8. Financial Statements and Supplementary Data. Our MD&A includes the following sections:
We are a Fort Worth, Texas-based independent oil and gas company engaged in the development, exploitation, exploration, acquisition, and production of natural gas, NGLs, and crude oil primarily from unconventional reservoirs where hydrocarbons are 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. We produce these products in quantities and at prices that, in addition to generating operating income, allow us to conduct development, exploitation, exploration and acquisition activities to replace the reserves that have been produced.
At December 31, 2006, approximately 98% of our proved reserves were natural gas and natural gas liquids. Approximately 33% of our proved reserves were located in Michigan. Our activities in the Michigan Basin Antrim shale have allowed us to develop a technical and operational expertise in the development, exploitation, exploration, acquisition and production of unconventional natural gas reserves. Consistent with one of our business strategies, we have applied the expertise gained in our Michigan activities to our Canadian projects in Alberta, Canada and our Barnett Shale interests in the Fort Worth Basin in Texas. Our Texas and Alberta reserves made up about 45% and 20%, respectively of our proved reserves at December 31, 2006. The Delaware Basin in west Texas and the Mannville CBM in Alberta represent our most recent opportunities to apply this expertise.
For 2007, we plan to continue our focus on the continued development, exploitation and exploration of our properties in Texas and Alberta. We have allocated $502 million of our 2007 capital budget of $610 million for drilling activities. Approximately $425 million is allocated to our Barnett Shale position in the Forth Worth Basin in Texas and approximately $54 million is allocated to our Canadian CBM projects. Approximately $18 million of the 2007 drilling budget has been dedicated to our fractured shale projects in the Michigan Basin, with the remaining $5 million planned for our projects in Indiana/Kentucky and the Rockies.
Our Company focuses on three key value drivers:
The Companys reserve growth is dependent upon our ability to apply the Companys 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 relatively low-risk development and exploitation drilling. We will also continue to identify high potential exploratory projects with higher levels of financial risk. Both our lower-risk development programs and higher-risk exploratory projects are aimed at providing the Company with opportunities to develop and exploit unconventional natural gas reservoirs to which our technical and operational expertise is well suited.
Our principal properties are well suited for production increases through development and exploitation drilling. We perform workover and infrastructure projects to reduce operating costs and increase current and future production. We regularly review operations on operated properties to determine if steps can be taken to profitably increase reserves and production.
As these elements are implemented, our results are measured through the following key measurements: reserve growth; production growth; cash flow from operating activities; and earnings per share.
The possibility of decreasing prices received for production is among the several risks that we face. We seek to manage this risk by entering into natural gas sales contracts with price floors and natural gas and crude oil financial hedges. Our use of pricing collars and, to a lesser degree, fixed price swaps for both natural gas and crude oil helps to ensure a predictable base level of cash flow while allowing us to participate in a portion of any favorable price increases. This commodity price strategy enhances our ability to execute our development, exploitation and exploration programs, meet debt service requirements and pursue acquisition opportunities despite price fluctuations. If our revenues were to decrease significantly as a result of presently unexpected declines in natural gas prices or otherwise, we could be forced to curtail our drilling and acquisition activities. We might also be forced to sell some of our assets on an untimely or unfavorable basis.
Prices for natural gas and crude oil fluctuate widely. For example, the closing NYMEX wholesale price of natural gas was at an all-time high of approximately $13.91 per Mcf for October 2005 before dropping to approximately $4.20 per Mcf for October 2006. For February 2007 natural gas production, the wholesale price of natural gas was approximately $6.92 Mcf. Assuming natural gas prices remain at relatively favorable levels, we expect to fund more of our capital expenditures with cash flow from operating activities; however, we do not expect our cash flow from operating activities to be sufficient to satisfy our total budgeted capital expenditures. We plan to use cash flows from operations, credit facility utilization, possible sales of assets and issuance of debt or equity securities to fund our total budgeted capital expenditures in 2007.
Our wholly-owned subsidiary that will hold Cowtown Plant and the Cowtown Pipeline has filed a registration statement on Form S-1 relating to the offering of approximately 19% of its limited partner interests to the public. Numerous factors, such as general market conditions and market conditions in the oil and gas industry in particular, could result in this offering not being completed.
We have established policies and procedures for managing risk within our organization, including internal controls. The level of risk assumed by us is based on our objectives and capacity to manage risk.
Our primary risk exposure is related to natural gas and crude oil commodity prices. We have mitigated the downside risk of adverse price movements through the use of long-term sales contracts, swaps and collars; however, in doing so, we have also limited future gains from favorable price movements.
Commodity Price Risk
We enter into long-term natural gas sales contracts and financial derivative contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas production. We sell approximately 10 MMcfd and 25 MMcfd of natural gas under long-term contracts with floor prices of $2.47 per Mcf and $2.49 per Mcf, respectively, through March 2009. Approximately 31.2 MMcfd of our natural gas production was sold under these contracts in 2006 and the remainder were third-party volumes controlled by us. We also enter into financial derivative contracts that include price floors, no-cost collars and fixed price swaps to hedge our exposure to commodity price risk associated with anticipated future production of natural gas, crude oil and condensate and NGLs.
Currently, natural gas price collars have been put in place to hedge 2007 anticipated production of approximately 123 MMcfd. Additionally, we have used price collar agreements to hedge approximately 1,250 Bbld of its crude oil, condensate and NGL anticipated production for 2007. Anticipated 2008 natural gas production of approximately 35 MMcfd has also been hedged using price collars and an additional 40 MMcfd of natural gas production has been hedged using fixed price swaps. We believe we will have more predictability of our natural gas and crude oil revenues as a result of these long-term sales and financial derivative contracts.
The following table summarizes our open financial derivative positions as of December 31, 2006 related to natural gas and crude oil production.
Utilization of our financial hedging program may result in natural gas and crude oil realized prices varying from market prices that we receive from the sale of natural gas and crude oil. Our revenue from natural gas and crude oil production was $15.5 million higher, $41.8 million lower and $43.9 million lower for 2006, 2005 and 2004, respectively.
We have also entered into financial derivative contracts to hedge exposure to commodity price risk associated with future contractual natural gas sales at fixed prices to third parties. As a result of our firm sale commitments, the associated financial derivative contracts qualified as fair value hedges for accounting purposes. Marketing revenues were $0.2 million lower and $0.1 million and $0.5 million higher as a result of our hedging activities in 2006, 2005 and 2004, respectively.
The following table summarizes our open financial swap positions and hedged firm commitments as of December 31, 2006 related to natural gas marketing.
Hedge ineffectiveness resulted in $0.1 million of net losses, $0.1 million of net gains and $0.1 million of net losses recorded to other revenue for 2006, 2005 and 2004, respectively.
Our remaining anticipated production for 2007 and beyond is subject to commodity price fluctuations. Under long-term sales contracts, natural gas volumes of 16.5 MMcfd are committed at market price through September 2008. During 2006, approximately 8.9 MMcfd of our natural gas production was sold under these contracts. The remaining contractual volumes were third-party volumes controlled by us.
Based on our 2006 average production and long-term natural gas sales contracts with floor prices of $2.47 per Mcf and $2.49 per Mcf, each $1.00 per Mcf increase/decrease in the price of natural gas would increase/decrease our revenue by approximately $42.0 million.
At December 31, 2006, we had no interest rate derivatives in effect. On September 10, 2003, we entered into an interest rate swap to hedge the $40.0 million of fixed-rate second lien notes issued on June 27, 2003. The swap converted the debts 7.5% fixed-rate debt to a floating six-month LIBOR base. In January 2004, the swap position was cancelled, and we received a cash settlement of $0.3 million that was recognized over the original term for the swap until the associated debt was retired in March 2006. At that time, the remaining deferred gain was recognized.
Interest expense for the years ended December 31, 2006, 2005 and 2004 was $0.1 million lower, $0.3 million lower and $0.8 million higher, respectively, as a result of the interest rate swaps.
If interest rates on our variable interest-rate debt of $421.1 million, as of December 31, 2006, increase or decrease by one percentage point, our annual pretax income will decrease or increase by $4.2 million.
Credit risk is the risk of loss as a result of non-performance by counterparties of their contractual obligations. We sell a portion of our natural gas production directly under long-term contracts with the remainder of our natural gas and crude oil production sold at spot or short-term contract prices. All our natural gas and crude oil production is sold to large trading companies and energy marketing companies, refineries and other users of petroleum products. We also enter into hedge derivatives with financial counterparties. We monitor exposure to counterparties by reviewing credit ratings, financial statements and credit service reports. Exposure levels are limited and parental guarantees and collateral to support the obligations of our counterparty are required according to our established policy. Each customer and/or counterparty is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. In this manner, we reduce credit risk.
While we follow our credit policies at the time we enter into sales contracts, the credit-worthiness of counterparties could change over time. The credit ratings of the parent companies of the two counterparties to our long-term gas contracts were downgraded in early 2003 and remain below the credit ratings required for the extension of credit to new customers. Please see Item 1A. Risk Factors.
Performance risk results when a financial counterparty fails to fulfill its contractual obligations such as commodity pricing or volume commitments. Typically, such risk obligations are defined within the trading agreements. We manage performance risk through management of credit risk. Each customer and/or counterparty is reviewed as to credit-worthiness prior to the extension of credit and on a regular basis thereafter.
Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. In 2005, foreign currency transaction losses of $0.1 million were recorded as a result of losses in the Canadian-$ value of U.S.-$ bank balances in 2005. During October and November 2004, Quicksilver loaned QRCI approximately $11.4 million. To reduce its exposure to exchange rate risk, QRCI entered into a forward contract that fixed the Canadian-to-US exchange rate. The balance of the loan was repaid at the end of November 2004 and upon settlement of the forward contract, a gain of $0.2 million was recognized.
While cross-currency transactions are minimized, the result of a ten percent change in the Canadian-U.S. exchange rate would increase or decrease stockholders equity by approximately $15.8 million at December 31, 2006.
Management discusses with our Audit Committee the development, selection and disclosure of our critical accounting policies and estimates and the application of these policies and estimates. Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States. We believe our accounting policies are appropriately selected and applied.
In preparing the financial statements, our management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including asset retirement obligations, litigation, income taxes and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
We use the full cost method of accounting 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. Effective with the adoption of SFAS No. 143 in 2003, the carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The application of the full cost method of accounting for oil and gas properties generally results in higher capitalized costs and higher depletion rates compared to the successful efforts method of accounting for oil and gas properties. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production basis using proved oil and gas reserves as determined by independent petroleum engineers.
We are required to perform the ceiling test each quarter because we use the full cost method of accounting for oil and gas properties. Pursuant to SEC Regulation S-X Rule 4-10, the ceiling test is an impairment test performed
on a country-by-country basis. The test determines a full cost limitation, or ceiling, on the book value of oil and gas properties, which is generally the after-tax value of the future net cash flows from proved natural gas and crude oil reserves, including the effect of cash flow hedges, discounted at ten percent per annum. Applying the test, we compare the full cost ceiling limitation to the net book value of our oil and gas properties reduced by the related net deferred income tax liability and asset retirement obligations. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the full cost ceiling limitation, an impairment or noncash write down is required. A charge to income for impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced.
The ceiling test is affected by a decrease in net cash flow from reserves due to higher operating or capital costs or reduction in market prices for natural gas and crude oil. These changes can reduce the amount of economically producible reserves. At December 31, 2006, our net capitalized exploration and production fixed asset costs, inclusive of future development costs, for U.S. and Canadian reserves were $1.07 per Mcfe and $1.53 per Mcfe, respectively.
Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10(a) 2(i), 2(ii), 2(iii), (3) and (4), 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 (i.e., prices and costs as of the date the estimate is made). 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 using available geological and reservoir data as well as production performance data. These estimates, made by our engineers, are reviewed annually and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits sooner. A material change in the estimated volumes of reserves could have an impact on the depletion rate calculation and the financial statements.
We enter into financial derivative instruments to hedge risk associated with the prices received from natural gas, crude oil and condensate and NGL production. We also utilize financial derivative instruments to hedge the risk associated with interest rates on our debt outstanding. We account for our derivative instruments under the provisions of Statement of Financial Accounts Standard (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities. Under this statement, derivative instruments, other than those meeting the normal purchases and sales exception, are recorded on our balance sheet as either assets or liabilities measured at fair value determined by reference to published future market prices and interest rates. The cash settlement of all derivative instruments is recognized as income or expense in the period in which the hedged transaction is recognized. Gains or losses on 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. The ineffective portion of hedges is recognized currently in earnings.
The fair value of our natural gas and crude oil derivatives and associated firm sales commitments as of December 31, 2006 was estimated based on published market prices of natural gas and crude oil for the periods covered by the contracts. The net differential between the prices in each derivative and commitment and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. As a result, the fair value of our derivatives and commitments does not necessarily represent the value a third party would pay or require payment of to assume our contract positions.
At December 31, 2006, portions of our hedge derivatives were classified as current based upon the maturity of the derivative instruments. Based upon the estimated fair values of those hedge derivatives as of December 31, 2006, our revenues for 2007 will increase approximately $64.1 million. Net income, after income taxes, will be approximately $42.7 million. These amounts will be reclassified from accumulated other comprehensive income in 2007.
We have significant obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities. We adopted SFAS No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. Under SFAS No. 143, the estimated fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets is recorded in the periods in which it is incurred. When the liability is recorded, we increase the carrying amount of the related long-lived asset. The liability is accreted to the fair value at the time of the settlement over the useful life of the asset, and the capitalized cost is depleted or depreciated over the useful life of the related asset.
The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflation of these costs, the productive life of the asset and our risk adjusted costs to settle such obligations discounted using our risk- adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates.
We adopted SFAS 123(R) on January 1, 2006. We previously accounted for stock awards under the recognition and measurement principles of APB No. 25, Accounting for Stock Issued to Employees, and related Interpretations. Prior to January 1, 2006, stock-based employee compensation expense for restricted stock and stock unit grants was reflected in net income, but no compensation expense was recognized for options granted with an exercise price equal to the market value of the underlying common stock on the date of grant. This statement requires the cost resulting from all share-based payment transactions be recognized in the financial statements at their fair value on the grant date.
We adopted SFAS 123(R) using the modified prospective application method described in the statement. Under the modified prospective application method, we have applied the standard to new awards. Additionally, compensation cost for the unvested portion of stock awards outstanding as of January 1, 2006 has been recognized as compensation expense as the requisite service is rendered after January 1, 2006. The compensation cost for unvested stock awards granted before adoption of SFAS 123(R) shall be attributed to periods beginning January 1, 2006 using the attribution method that was used under SFAS 123. At January 1, 2006, we had total compensation cost of $1.1 million related to unvested stock options with a weighted average remaining vesting period of 1.5 years. We recorded expense of $0.7 million for stock option grants during 2006.
Prior to the adoption of SFAS 123(R), we presented any tax benefits of deductions resulting from the exercise of stock options within operating cash flows in the condensed consolidated statements of cash flow. SFAS 123(R) requires tax benefits resulting from tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified and reported as both an operating cash outflow and a financing cash inflow upon adoption of SFAS 123(R). As a result of our net operating losses, the excess tax benefits that would otherwise be available to reduce income taxes payable have the effect of increasing our net operating loss carry forwards. Accordingly, because we are unable to realize these excess tax benefits, such benefits have not been recognized in the condensed consolidated statement of cash flows for the year ended December 31, 2006.
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 will be in effect in years in which the temporary differences are expected to reverse. QRCI computes taxes at rates in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested by QRCI and thus are not considered available for distribution to us.
Included in our net deferred tax liability are $117.8 million of future tax benefits from prior unused tax losses. Realization of these tax assets depends on sufficient future taxable income before the benefits expire. We believe we will have sufficient future taxable income to utilize the loss carry forward benefits before they expire; however, if not, we could be required to recognize a loss for some or all of these tax assets. Net operating loss carry forwards and other deferred tax assets are reviewed annually for recoverability and are recorded net of a valuation allowance, if necessary.
We have no off-balance sheet arrangements within the meaning of Item 303(a)(4) of SEC Regulation S-K.
RESULTS OF OPERATIONS
Summary Financial Data
Years Ended December 31, 2006, 2005 and 2004
Net income for the years ending December 31, 2006, 2005 and 2004 was $93.7 million ($1.15 per diluted share), $87.4 million ($1.08 per diluted share), and $31.3 million ($0.41 per diluted share), respectively. Net income for 2005 included a gain of $0.2 million from discontinued operation relating to the sale of drilling rigs purchased and sold during the year.
Our 2006 revenues were $390.4 million as compared to $310.4 million for 2005, primarily as a result of additional revenue originating from our expanded operations in the Fort Worth Basin of northern Texas and Alberta, Canada. The additional revenue from our Texas and Canadian operations was the result of a net increase in sales volumes of 8.8 Bcfe and 3.7 Bcfe, respectively, and an increase in our realized prices, on a consolidated basis, of $0.36 per Mcfe.
Total revenues for 2005 were $310.4 million, a $130.7 million increase from the $179.7 million reported in 2004. Higher realized prices and additional sales volumes increased revenue $129.0 million. The increase was primarily the result of sales volumes added from new wells placed into production in our Canadian CBM and Texas Barnett Shale development projects and a 49% increase in realized sales prices.
Gas, Oil and NGL Sales
Our sales volumes, revenues and average prices for the years ended December 31, 2006, 2005 and 2004 are as follows:
Our natural gas sales for 2006 were $322.4 million and increased 20%, or $52.8 million, from 2005 natural gas sales of $269.5 million. Realized prices in 2006 (including hedge settlements and our sales contracts with $2.48 per Mcf floors) increased 5% and were responsible for $13.5 million of the increase in natural gas revenue from the prior year. The remaining increase in 2006 natural gas revenue as compared to 2005 was due to a 14% increase in sales volumes. Natural gas sales in the U.S. increased 6.8 Bcf as a result of new Fort Worth Basin wells placed into production throughout 2006 and 0.7 Bcf from new Antrim wells in Michigan placed into production during 2006.
Drilling on our Canadian interests increased production 5.1 Bcf from the 2005 period. These increases were partially offset by natural production rate declines for existing wells.
Crude oil and condensate revenue for 2006 was $35.2 million and $7.3 million higher than crude oil and condensate sales of $27.9 million for 2005. A realized $9.49 per Bbl increase in prices contributed almost $5.3 million of the $7.3 million increase. Production in 2006 from our Fort Worth Basin interests increased 61.2 MBbl as a result of additional wells placed into production during the year. The increase was partially offset by natural production rate declines for existing wells.
Sales of NGLs for 2006 were $29.0 million. As compared to 2005, 2006 sales were $20.3 million higher than 2005 NGL sales of $8.7 million. The increase was the result of an incremental 509.7 MBbl of NGL production resultant from Texas natural gas production and processing during 2006.
Natural gas sales for 2005 were $269.5 million and increased $118.8 million from 2004 natural gas revenue of $150.7 million. Higher natural gas prices in 2005 increased revenue $76.1 million. Realized natural gas prices (including contracts with price floors of $2.48 and settlements for natural gas price hedges) rose 54% and 32%, respectively, for U.S. and Canadian natural gas. Our natural gas production in 2005 increased nearly 7.4 Bcf from 2004 to almost 46.8 Bcf. Continued drilling on our Horseshoe Canyon and other Canadian interests increased production 8.8 Bcf, partially offset by natural declines in production rates for existing Canadian wells. U.S. sales volumes for 2005 were approximately 5% higher than 2004. Our drilling program in the Barnett Shale of the Fort Worth Basin resulted in a production increase of over 3.0 Bcf from Barnett Shale wells drilled and placed into production in the latter half of 2004 and all of 2005. Wells placed into production in the Antrim and New Albany Shales increased production approximately 0.6 Bcf and 0.8 Bcf for 2005. Wells placed into production on our Michigan non-Antrim interests, as well as other work performed on existing wells, increased production approximately 0.3 Bcf for 2005. Natural production rate declines partially offset these increases.
Revenue from crude oil and condensate in 2005 increased $5.1 million despite a decrease of 150 MBbl resulting primarily from the sale of Wyoming crude oil properties in the third quarter of 2004 to Meritage Partners LLC. Price increases of approximately 53% from 2004 realized prices resulted in an average 2005 realized price of $50.50 and increased revenue approximately $12.0 million.
NGL revenue for 2005 was $8.7 million as compared to $3.7 million for 2004. NGL volumes for 2005 increased approximately 94 MBbl primarily as a result of natural gas processing in the Barnett Shale that began in the second quarter of 2005. These additional volumes increased revenue approximately $3.7 million from 2004 while a 37% increase in realized prices provided $1.3 million of additional revenue in 2005.
Other revenue, consisting primarily of revenue from the processing, gathering and marketing of natural gas, was $4.2 million for 2005. The $1.6 million increase from 2004 was primarily the result of revenue earned from the sale of NGLs earned from gas processed through our interim processing facility in the Barnett Shale. This revenue was not earned for 2006 as the final gas processing agreements entered into in October 2005 do not provide for the facility to earn a portion of the NGLs produced from the plant.
Operating expenses for 2006 were $216.7 million, or $54.5 million higher than operating expenses for 2005. Production expenses in 2006 were $24.0 million higher than 2005 production expense due primarily to higher sales volumes from new wells placed into production in Texas and Canada. Depletion and depreciation expense for 2006 increased $23.6 million as a result of higher sales volumes and depletion rates as well as additional depreciation associated with new gas processing and gathering assets in Texas and Canada. General and administrative expense for 2006 also increased $6.0 million compared to 2005.
Operating expenses for 2005 were $162.2 million, a $41.9 million increase from 2004 operating expense. Nearly half of the increase was due to higher sales volumes and new wells placed into production in Canada and Texas as well as an increase in maintenance and repairs for our Michigan properties. Depletion expense for 2005 increased as a result of higher sales volumes and depletion rates. Depreciation also increased as a result of gathering
and processing facilities added in Canada and Texas during 2005. There was also a $6.0 million increase in general and administrative costs for 2005 when compared to 2004.
Expense for oil and gas production for 2006 was $95.2 million and $24.0 million higher than 2005 production expense of $71.2 million. Canadian production expense was $21.9 million in 2006. The $6.6 million increase from 2005 Canadian production expense was primarily the result of a $3.7 million increase in compensation and benefits expense and an increase of $1.7 million for gas processing expense. The increase in compensation costs was made up of additional stock compensation expense of $0.8 million due to 2006 grants of restricted stock, an increase of $0.5 million for matching contributions to employees retirement savings accounts and a 20% increase in the number of Canadian employees as compared to 2006. Operation of gas processing facilities built in 2005 and 2006 increased expense $1.7 million in 2006 compared to 2005.
Production expense for the U.S. increased $17.4 million in 2006 to $73.3 million as compared to 2005. Production expense for Texas increased $16.3 million for 2006 compared to 2005. Start-up of our Cowtown Plant and expansion of our Cowtown Pipeline System increased expense $8.4 million due in part to a net 8.8 Bcfe increase in production volumes. Remaining Texas production expense increased $7.9 million for 2006 when compared to 2005 as a result of larger operations including an increase in production and drilling operations that have required additional employees in our Texas field office. Production overhead expense for Texas in 2006 increased approximately $1.8 million, net of overhead recoveries, as a result of compensation for additional employees and an increase in office-related expenses, including rent. Lease operating expense increases of $4.9 million, net of approximately $1.0 million for clean-up of a saltwater spill that occurred in the second quarter, made up the remaining increase for 2006 Texas production expense when compared to 2005. Additional producing wells and increases in rates charged by third-parties were the primary causes of the $4.9 million increase in 2006 lease operating expense. The remaining expense increases included higher stock compensation expense for field employees of $0.6 million in 2006 as compared to 2005 and additional workover expense of approximately $0.4 million in our Michigan operating area.
Oil and gas production expense for 2005 was $71.2 million and $18.6 million higher than 2004 production expense. U.S. production expense increased $12.3 million, excluding expense for stock-based compensation expense, when compared to 2004 production expense. U.S. production expense for 2005 is also net of a $2.4 million reduction in Wyoming production expense as a result of the sale of most of our Wyoming properties in the third quarter of 2004. Operating expense for our Barnett Shale projects in the Fort Worth Basin increased nearly $7.9 million from 2004 to 2005. We had 36.6 net operated wells in operation at the end of 2005 compared to 3 net operated wells at the end of 2004. The growth of our operations increased lease operating expenses $4.7 million, which included $2.9 million for contract labor, equipment rentals and salt water disposal. Initial operating expenses for these items are typically greater when production begins as initial production includes high water production from the fracture stimulations. Operating costs for each well tends to decrease following the period of initial production; however, these expenses remained high for 2006 due to our drilling program in the Fort Worth Basin. Expense for the gathering and processing of our Barnett Shale natural gas production increased $3.2 million.
Production expense for our Michigan projects increased $5.4 million from 2004 production expense. Approximately $3.2 million of the increase for 2005 resulted from efforts to perform preventive equipment maintenance and repairs. Michigan environmental compliance and remediation expense increased almost $1.4 million for 2005. Salary and wages expense increased almost $0.6 million for personnel in Michigan, Indiana and Kentucky as a result of annual raises, the hiring of additional personnel and a small increase in 2005 bonuses compared to 2004.
Canadian production expense for 2005 increased $6.3 million from 2004 production expense, exclusive of stock-based compensation expense. We drilled 483 (259.1 net) wells during 2005 and net natural gas production increased 6.1 Bcf. Canadian production expense on a Mcfe-basis decreased $0.01/Mcfe. The decrease reflected additional improvement in the economies of scale for our Canadian operations.
Production and ad valorem tax expense for 2006 was relatively flat when compared to 2005 as a $1.9 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 property values while production tax expense decreased as a result of lower prices in 2006 compared to 2005.
Production and ad valorem tax expense increased $2.5 million from 2004 to 2005 due primarily to higher prices for natural gas, crude oil and condensate as well as an increase in U.S. sales volumes. Canadian expense for production and ad valorem taxes was virtually unchanged from 2004 to 2005.
Our 2006 depletion expense increased $19.1 million from 2005 depletion expense. Our 2006 consolidated depletion rate increased $0.16 per Mcfe, and our production increased 9.8 Bcfe. The increase in our consolidated depletion rate was a result of increased future development costs due in part to a higher percentage of undeveloped proved reserves for 2006 year-end as compared to 2005. Depreciation expense for 2006 was $11.8 million and $4.2 million higher than 2005 depreciation expense of $7.6 million. The increase in depreciation is primarily the result of our new Cowtown Gas Plant, additions to our Cowtown Pipeline and new Canadian gas processing facilities.
Higher production volumes and an increase in our depletion rate for 2005 increased depletion expense $12.1 million from 2004 depletion expense. The $0.13 per Mcfe increase in our consolidated depletion rate was the result of a higher percentage increase for estimated future development costs as compared to proved reserve increases for 2005 as compared to 2004. Depreciation expense for 2005 increased $2.4 million when compared to 2004 expense. The increase is primarily the result of additional gas processing facilities in Canada and the U.S. as well as a full years operation of the Cowtown Pipeline in the Barnett Shale.
General and administrative expense for 2006 was $24.9 million and an increase of $5.9 million from 2005 general and administrative expense of $19.0 million. Expense for compensation and benefits grew $5.3 million when compared to 2005. The increase included $3.4 million for stock compensation expense associated with 2006 grants of restricted stock, $1.5 million resulting from additional employees and annual raises and an increase of $0.4 million for additional matching of employees retirement plan contributions. The remaining increase was
primarily the result of a $0.9 million increase in 2006 office-related expenses, primarily rent for additional office space, partially offset by decreases in several expense categories.
For 2005, general and administrative expense was $19.0 million. The total was $6.0 million higher than 2004 general and administrative expense. During 2005, employee compensation expense increased approximately $5.6 million including nearly $1.0 million of expense for restricted stock granted to executives and employees during 2005. Additional management and administrative personnel increased compensation expense approximately $1.7 million. Bonuses paid to employees for 2005 were $1.9 million higher than 2004 and included $0.6 million for retention and hiring of key personnel. Annual raises and other compensation expenses, including the our contribution to employees retirement accounts for 2005, increased general and administrative expense approximately $1.0 million while outside directors compensation increased over $0.2 million including almost $0.1 million for vesting of restricted stock granted during 2005. Legal fees were $0.9 million higher due largely to work performed by outside attorneys on various corporate matters and litigation. These increases were partially offset by a $0.4 million decrease in contract labor expense and small decreases in various other expenses from 2004.
For 2006, interest expense was $44.1 million after interest capitalization of $1.9 million, an increase of $22.3 million from 2005 interest expense and primarily the result of higher debt balances including the issuance of our $350 million in principal amount senior subordinated notes in March of 2006. Interest expense for 2006 included a prepayment penalty of $0.8 as a result of the early retirement of $70.0 million in principal amount of our second lien mortgage notes payable with a portion of the proceeds from the issuance of $350 million in principal amount of our senior subordinated notes. Recurring interest expense increased $14.0 million as a result of higher debt levels throughout 2006. Higher interest rates, including the Canadian prime rates paid on the Canadian debt outstanding under the senior credit facility, during 2006 contributed approximately $8.4 million to increased interest expense. These increases in 2006 interest expense were partially offset by an additional $0.8 million of interest capitalization relating to gas processing facilities in Texas and Canada.
Interest expense for 2005 was $21.7 million after interest capitalization of $1.1 million. The $6.1 million increase from 2004 was the result of higher debt balances that resulted from capital expenditures for our 2005 development, exploitation and exploration programs in Canada and Texas and was partially offset by a decrease in the average interest paid on our total debt balance. The decrease in our average interest rate was primarily the result of the 1.875% interest rate borne by our $150.0 million contingently convertible debentures issued in November 2004. Capitalized interest recorded in 2005 was associated with the construction of gathering and processing facilities in the Fort Worth Basin of Texas and in Canada.
Our income tax provision for 2006 was $38.1 million. Our U.S. deferred federal income tax provision of $27.5 million was established using the statutory U.S. federal rate of 35%. Expense for the 2006 period included the reversal of a deferred federal income tax liability of $0.9 million as a result of the completion of IRS audits of a wholly-owned subsidiary for years prior to its acquisition by us. We also recognized a deferred state income tax provision of $1.6 million as a result of the Texas Margin Tax that was enacted in May 2006. The Canadian tax provision was approximately $9.0 million for 2006 which included a reduction of $3.8 million for the effect of federal and provincial tax rate reductions that were enacted in the second quarter of 2006.
For 2005, our income tax provision was $40.7 million. Our U.S. income tax provision of $26.3 million was established using the statutory U.S. federal rate of 35%. The Canadian tax provision of approximately $14.3 million was accrued at a Canadian combined federal and provincial statutory rate of 33.6% and included a current tax provision of $0.5 million.
Our statements of cash flows are summarized as follows:
Cash flows provided by operating activities in 2006 were $220.6 million and a $76.1 million increase from operating cash flow for 2005. The 53% increase in operating cash flow was primarily the result of a 19% increase in production, a 6% increase in realized product prices and more aggressive cash management.
Operating activities in 2005 generated $144.5 million of cash flows, or a 70% increase from 2004 operating cash flows. The primary factor in our increased operating cash flow was a $56.2 million increase in 2005 net income that reflected a 49% increase in our realized product prices and a 16% increase in 2005 production volumes.
Purchases of property, plant and equipment accounted for the most significant cash outlays for investing activities in each of the three years ended December 31, 2006, 2005 and 2004. We currently estimate that our spending for property, plant and equipment in 2007 will be approximately $610 million, of which we have allocated $502 million for drilling activities, $88 million for gathering and processing facilities, $18 million for acquisition of additional leasehold interests and $2 million for other property and equipment. Total property, plant and equipment
costs incurred (purchases of property, plant and equipment plus net working capital changes related to acquisition of property, plant and equipment) by geographic segment for 2006, 2005 and 2004 are as follows:
Property and Equipment Costs Incurred
Capital costs incurred for 2006 development, exploitation and exploration activities in 2006 were $544.7 million. Those expenditures reflect our focus in two operating areas, the Fort Worth Basin in northern Texas and our Canadian projects in the Western Sedimentary Basin in Alberta, Canada. In 2006, we drilled 123 (111.3 net) wells in northern Texas 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.
Capital expenditures for our 2005 development, exploitation and exploration activities were focused in two areas. Canadian development and exploration costs were $97.6 million. Our 2005 expenditures in Canada were focused on the development and exploitation of our ongoing CBM projects as well as exploration of additional CBM acreage. Canadian expenditures for gas processing facilities were $20.4 million. Our U.S. capital expenditures were primarily spent on development, exploitation and development of the Barnett Shale in the Fort Worth Basin. Total expenditures for our Texas projects were $153.6 million, including approximately $51.7 million for acreage in the Fort Worth and Delaware Basins. Expenditures for completion of the first phase of our Cowtown Pipeline and construction of our Cowtown Plant in the Fort Worth Basin were over $49.2 million.
Our 2004 capital expenditures for development, exploitation and exploration activities were focused in four areas. Expenditures for Canadian development, exploitation and exploration projects were approximately $104.6 million. Those expenditures continued exploration and development of our initial CBM projects as well as exploration of several additional CBM projects. Included in the $104.6 million of Canadian expenditures was $7.1 million for acquisition of additional acreage in several areas of Alberta. Expenditures for Texas development, exploitation and exploration activities were approximately $55.1 million, including approximately $29.3 million
for additional acreage in north Texas. An additional $6.0 million was expended for the first phase of the Cowtown Pipeline. We spent approximately $31.5 million for continued development of our Michigan properties and an additional $2.1 million was spent on gathering and processing infrastructure. New wells and associated infrastructure in southern Indiana and northern Kentucky accounted for approximately $20.6 million of our expenditures for exploration and development activities. An additional $1.1 million was expended for the construction of plant and pipeline infrastructure in the Indiana/Kentucky area.
Net cash provided by financing activities in 2006 was $361.3 million. On March 16, 2006, we issued $350 million in principal amount of Senior Subordinated Notes due in 2016. The Senior Subordinated Notes are unsecured, senior subordinated obligations and bear interest at an annual rate of 7.125% payable semiannually on April 1 and October 1 of each year. The terms and conditions of the Senior Subordinated Notes require us to comply with certain covenants, which primarily limit certain activities, including, among other things, levels of indebtedness, restricted payments, payments of dividends, capital stock repurchases, investments, liens, restrictions on restricted subsidiaries to make distributions, affiliate transactions, transfers or sales of assets and mergers and consolidations. Based upon our 2006 year-end reserves, the indenture agreement limits us to $750 million of borrowing under our senior secured credit facility. At December 31, 2006, we were in compliance with such restrictions.
We used $70 million of the proceeds of the Senior Subordinated Notes to retire our second lien mortgage notes in March 2006. As a result of the early retirement, we were required to pay a premium of $0.8 million for early repayment of the notes. We also used approximately $192.5 million of the proceeds to repay the borrowings then outstanding under the U.S. portion of our senior secured credit facility. For 2006, we have increased our borrowings under our U.S. and Canadian senior secured credit facilities approximately $133.1 million.
As of December 31, 2006, our borrowing base under our senior secured credit facility was $600 million, of which approximately $178 million was available for borrowing. The loan agreements for the senior credit facility prohibit the declaration or payment of dividends by us and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion, amortization, non-cash income and expense and exploration costs) to interest ratio. We were in compliance with all such covenants at December 31, 2006.
On February 9, 2007, we extended the senior secured credit facility to February 9, 2012 and to provide for revolving loans, swingline loans and letters of credit from time to time in an aggregate amount not to exceed the lesser of the borrowing base which is calculated based on several factors and is initially equal to $850 million. The borrowing base is subject to annual redeterminations and certain other redeterminations. The lenders have agreed to initial revolving credit commitments in an aggregate amount equal to $1.2 billion, and we have an option to increase the facility to $1.45 billion with the consent of the lenders. The lenders commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. funds available for borrowing by the Company and Canadian funds being available for borrowing by the Companys Canadian subsidiary, QRCI in U.S. or Canadian funds. The facility offers the option to extend the maturity up to two additional years with requisite lender consent. U.S. borrowings under the facility are guaranteed by most of our domestic subsidiaries and are secured by, among
other things, certain of our domestic subsidiaries oil and gas properties. Canadian borrowings under the facility are secured by, among other things, QRCIs, our and certain of our domestic subsidiaries oil and gas properties. The loan agreements for the credit facility prohibit the declaration or payment of dividends by us and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio. As of December 31, 2006, 2005 and 2004, 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 2007 capital expenditure budget of approximately $610 million will be funded by cash flow from operations, credit facility utilization and proceeds we expect to receive in connection with the anticipated sale to the public of approximately 19% of the limited partner interests of Quicksilver Gas Services LP (QGSLP), our subsidiary that will hold Cowtown Plant and the Cowtown Pipeline. Although QGSLP has filed a registration on Form S-1 relating to this offering, numerous factors, such as general market conditions and market conditions in the oil and gas industry in particular, could result in the offering not being completed. We may also consider the possible sale of assets and the possible issuance of debt or equity securities to fund our 2007 capital expenditure budget.
Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or other securities, or other possible capital markets transactions, 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 assets and businesses. 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 two or more of those sources.
The following impacted our balance sheet as of December 31, 2006, as compared to our balance sheet as of December 31, 2005:
Information regarding our contractual obligations (within the scope of Item 303(a)(5) of Regulations S-K), as well as scheduled interest obligations, at December 31, 2006 is set forth in the following table.
We have the following commercial commitments as of December 31, 2006.
Certain statements contained in this 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:
All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.
The Financial Accounting Standards Board (FASB) issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments an amendment of FASB Statements No. 133 and 140, in February 2006. SFAS No. 155 addresses accounting for beneficial interests in securitized financial instruments. The guidance allows fair value remeasurement for any hybrid financial instrument containing an embedded derivative that would otherwise require bifurcation and clarifies which interest-only and principal-only strips are not subject to SFAS No. 133. SFAS No. 155 also established a requirement to evaluate interests in securitized financial assets to identify any interests that are either freestanding derivatives or contain an embedded derivative requiring bifurcation. The statement is effective for all financial instruments issued or acquired after the beginning of the first fiscal year that begins after September 15, 2006. Management does not believe application of this statement will have a material impact on our financial position, results of operations or cash flows.
SFAS No. 157, Fair Value Measurements, was issued by the FASB in September 2006. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP) and expands disclosures about fair value measurements. The statement applies under other accounting pronouncements that require or permit fair value measurement. No new requirements are included in SFAS No. 157, but application of the statement will change current practice. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Management does not expect adoption of SFAS No. 157 will have a material impact on our financial position, results of operations or cash flows.
The FASB issued FASB Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109, in June 2006. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprises financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. FIN 48 defines a criterion that an individual tax position must meet for any part of the benefit of that position to be recognized in an enterprises financial statements. FIN 48 also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We estimate that in the first quarter of 2007, we will recognize an adjustment to retained earnings of approximately $0.4 million to provide for additional deferred income tax liabilities.
On February 15, 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The FASB believes the statement will improve financial reporting by providing companies the opportunity to mitigate volatility in reported earnings by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Use of the statement will expand the use of fair value measurements for accounting for financial instruments. We do not believe SFAS No. 159 did not have a material impact on our financial position or results of operations.
In September 2006, the SEC issued Staff Accounting Bulletin No. 108 (SAB 108). Due to diversity in practice among registrants, SAB 108 expresses the SEC staffs views regarding the process by which misstatements in financial statements are evaluated to determine whether financial statement restatement is necessary. SAB 108 is effective for fiscal years ending after November 15, 2006. SAB 108 did not have a material impact on our financial position or results from operations.
The information called for by this Item is incorporated herein by reference to the information in Item 7 of this report under the heading Financial Risk Management.
QUICKSILVER RESOURCES INC.
To the Stockholders of
Quicksilver Resources Inc.:
Management of Quicksilver Resources Inc. is responsible for the preparation, integrity and fair presentation of its published consolidated financial statements. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles and, as such, include amounts based on judgments and estimates made by management. The Company also prepared the other information included in the annual report and is responsible for its accuracy and consistency with the consolidated financial statements.
Management is also responsible for establishing and maintaining effective internal control over financial reporting. The Companys internal control over financial reporting includes those policies and procedures that pertain to the Companys ability to record, process, summarize and report reliable financial data. The Company maintains a system of internal control over financial reporting, which is designed to provide reasonable assurance to the Companys management and board of directors regarding the preparation of reliable published financial statements and safeguarding of the Companys assets. The system includes a documented organizational structure and division of responsibility, established policies and procedures, including a code of conduct to foster a strong ethical climate, which are communicated throughout the Company, and the careful selection, training and development of our people.
The Board of Directors, acting through its Audit Committee, is responsible for the oversight of the Companys accounting policies, financial reporting and internal control. The Audit Committee of the Board of Directors is comprised entirely of outside directors who are independent of management. The Audit Committee is responsible for the appointment and compensation of the independent registered public accounting firm. It meets periodically with management, the independent registered public accounting firm and the internal auditors to ensure that they are carrying out their responsibilities. The Audit Committee is also responsible for performing an oversight role by reviewing and monitoring the financial, accounting and auditing procedures of the Company in addition to reviewing the Companys financial reports. Internal auditors monitor the operation of the internal control system and report findings and recommendations to management and the Audit Committee. Corrective actions are taken to address control deficiencies and other opportunities for improving the system as they are identified. The independent registered public accounting firm and the internal auditors have full and unlimited access to the Audit Committee, with or without management, to discuss the adequacy of internal control over financial reporting, and any other matters which they believe should be brought to the attention of the Audit Committee.
Management recognizes that there are inherent limitations in the effectiveness of any system of internal control over financial reporting, including the possibility of human error and the circumvention or overriding of internal control. Accordingly, even effective internal control over financial reporting can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect misstatements. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.
Management assessed the Companys internal control system as of December 31, 2006 in relation to criteria for effective internal control over financial reporting described in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the Company has determined that, as of December 31, 2006, the Companys system of internal control over financial reporting was effective.
The consolidated financial statements have been audited by the independent registered public accounting firm, Deloitte & Touche LLP, which was given unrestricted access to all financial records and related data, including minutes of all meetings of stockholders, the Board of Directors and committees of the Board. Reports of the independent registered public accounting firm, which includes the independent registered public accounting firms attestation of managements assessment of internal controls, are also presented within this document.
Fort Worth, Texas
February 28, 2007
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, 2006 and 2005 and the related consolidated statements of income and comprehensive income, stockholders equity and cash flows for each of the three years in the period ended December 31, 2006. 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 the Quicksilver Resources Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (Revised 2004), Share-Based Payment.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Companys internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2007 expressed an unqualified opinion on managements assessment of the effectiveness of the Companys internal control over financial reporting and an unqualified opinion on the effectiveness of the Companys internal control over financial reporting.
/s/ Deloitte & Touche LLP
Fort Worth, Texas
February 28, 2007
QUICKSILVER RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
As of December 31, 2006 and 2005
In thousands, except for share data
The accompanying notes are an integral part of these consolidated financial statements.