Quicksilver Resources 10-K 2005
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2004
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
Commission file number: 001-14837
QUICKSILVER RESOURCES INC.
(Exact name of registrant as specified in its charter)
777 West Rosedale, Suite 300, Fort Worth, Texas 76104
(Address of principal executive offices) (Zip Code)
Registrants telephone number, including area code: (817) 665-5000
Securities registered pursuant to Section 12 (b) of the Act:
Securities registered pursuant to Section 12 (g) of the Act: None
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes x No ¨
As of June 30, 2004, the aggregate market value of the voting stock held by non-affiliates of Quicksilver Resources Inc. was approximately $993,572,897 based on the New York Stock Exchange composite trading closing price of $33.53 on June 30, 2004. Shares of the registrants voting stock owned by its directors, executive officers and certain Darden family members and related entities were excluded from this aggregate market value calculation; however, such exclusion does not represent a conclusion by the registrant that any or all of such directors, executive officers and certain Darden family members and related entities are affiliates of the registrant.
As of February 28, 2005, 50,233,180 shares of common stock of Quicksilver Resources Inc. were outstanding.
Documents incorporated by reference: Proxy statement of the registrant relating to the annual meeting of stockholders to be held on May 17, 2005 which is incorporated into Part III of this Form 10-K.
For the Year Ended December 31, 2004
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 two-for-one stock split effected in the form of a stock dividend in June 2004.
Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf), million cubic feet (MMcf) or billion cubic feet (Bcf). 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.
ITEM 1. Business
We are an independent oil and gas company engaged in the exploration, acquisition, development, production and sale of natural gas, crude oil and natural gas liquids (NGLs) primarily from unconventional reservoirs such as fractured shales, coal beds and tight sands. We were organized as a Delaware corporation in 1999 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 and develop conventional oil and gas properties in the United States. As of December 31, 2004, members of the Darden family, together with Mercury and another entity entirely controlled by members of the Darden family, the sons and daughter of Frank Darden, beneficially owned approximately 37% of our outstanding common stock as of December 31, 2004. 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 Michigan, Indiana/Kentucky, Texas, the Rocky Mountains and the Canadian province of Alberta. At December 31, 2004, we had estimated proved reserves of 968 Bcfe. Approximately 92% of our reserves were natural gas, 77% were classified as proved developed and we operated approximately 70% of our reserves. Approximately 62% of our estimated proved reserves are located in Michigan and are characterized by long reserve lives and predictable well production profiles. For 2005, we expect to continue exploration and development of coal bed methane reserves in Alberta, Canada where approximately 27% of our proved reserves are located. We also expect to increase our exploration and development activities in the Barnett Shale of north Texas. We believe that much of our future growth will be through exploration and development of our interests in Canadian coal bed methane and north Texas Barnett Shale.
We intend to maintain an active capital-spending program that will focus primarily on the continued development and exploration of our coal bed methane properties in Canada and our Barnett Shale projects in north Texas. We also plan to continue the development and exploitation of our properties in Michigan and Indiana/Kentucky. For 2005, we have established a company-wide base capital budget of $235 million, with additional spending approved up to a maximum of $261 million. The discretion for additional expenditures will be based upon drilling and acreage acquisition opportunities in Texas and the success of horizontal drilling in Michigan, Indiana and Canadas Mannville coals. The maximum Canadian capital budget is approximately $107 million, which includes drilling approximately 497 wells (275 net), as well as construction of gathering lines, facilities and acreage acquisition. Approximately of $115 million of the United States capital budget will focus on north Texas where we expect to drill approximately 40 net Barnett Shale wells, construct gas plant facilities and phase one of the Cowtown Pipeline and acquire additional acreage. We also plan to dedicate approximately $38 million of the 2005 capital budget to our fractured shale projects in Michigan and Indiana/Kentucky. In both these areas, a portion of that budget will be spent for exploration activity that is intended to expand the known productive fairways.
The following table presents information regarding our primary areas of operation as of December 31, 2004:
We conduct our Canadian operations through our wholly owned subsidiary, MGV Energy Inc. (MGV). In 2000, we entered into a joint venture with EnCana Corporation (EnCana) to explore for coal bed methane (CBM) reserves on an area of over three million acres of land. In January 2003, MGV entered into an asset rationalization agreement with EnCana that divided the assets and rights subject to the joint venture. The agreement allowed us to pursue independent operations. Assets and rights received as a result of the agreement included an interest or an option to drill and earn in approximately 667,000 acres in Alberta. We have continued to acquire additional working interests in those areas as well as other areas in Alberta, Canada where we held approximately 423,000 net acres as of December 31, 2004. We also have the opportunity to earn in approximately 68,000 additional net acres.
Net gas sales from our CBM development projects in Alberta, Canada averaged 21.5 MMcfd in 2004. At year-end, the exit rate production from our CBM projects was approximately 35 MMcfd. During 2004, we drilled 319.8 productive net wells and connected those wells into existing infrastructure and pipeline systems to assure the control and priority of natural gas sales. As of December 31, 2004, we had 247.9 Bcf of proved reserves from our CBM projects in addition to 13.2 Bcf of proved reserves from our other Canadian natural gas interests.
During 2004, we began exploration and testing of the Barnett Shale formation in north Texas. We drilled eight 100%-owned wells in 2004 and anticipate drilling an additional 43 net wells in 2005. Three of the wells completed in 2004 were tied-in and producing at year-end. These three wells and four non-operated offset wells drilled in 2004 were producing within a range of 600 Mcfd to 2.8 MMcfd. As of December 31, 2004, we had 36.6 Bcfe of proved reserves from our Barnett Shale area and a net acreage position of approximately 207,000 acres.
Including 35 wells drilled in Indiana and Kentucky during 2004, we have 225 total wells and 29.2 Bcf of proved reserves from our New Albany Shale area. Including sales to a local end-user, our natural gas production averaged 5.9 MMcfd from the New Albany shale area. Our 12-mile Cardinal Pipeline, which transports our Indiana/Kentucky production to the interstate pipeline market, was placed into service at the end of September 2003 and allowed us to increase our exploration and development activities in the area.
During the third quarter, we sold certain natural gas and crude oil properties in Wyoming and Michigan. The divestitures were primarily crude oil reserves from properties in Wyoming with estimated proved reserves of 20 Bcfe. Net proceeds were approximately $8.3 million, net of closing adjustments. Also in the third quarter, we purchased additional interests in certain of our Antrim Shale properties in Michigan with approximately 5 Bcfe of proved reserves for approximately $10.4 million.
Our business strategy is designed to achieve our principal objectives of growth in reserves, production and cash flow to increase stockholder value. Key elements of our business strategy include:
Focus on Unconventional Natural Gas Reserves. We focus our exploration and development efforts on unconventional natural gas reservoirs. Unconventional reservoirs such as natural gas produced from fractured shales, coal beds and tight sands will not produce at commercial flow rates unless the formation is successfully stimulated with fracturing. The majority of our Michigan production is from the Antrim Shale where we, and Mercury prior to our formation, have been active drillers and producers for over fifteen years. Our Antrim Shale activities have allowed us to develop a technical and operational expertise in the acquisition, development and production of unconventional natural gas reserves. Our Canadian CBM, New Albany Shale and Barnett Shale projects represent an extension of our expertise in unconventional natural gas reserves.
Low-Cost Development of Existing Property Base. We attempt to increase production and reserves through aggressive management of operations and relatively low-risk development drilling. Our principal properties possess geological and reservoir characteristics that make them well suited for production increases through
exploitation activities and development drilling. We perform workovers and infrastructure improvement projects to reduce operating costs and increase current and ultimate production. We regularly review operations and mechanical data on operated properties to determine if additional actions can profitably be taken to increase reserves and production.
Pursuit of Selective Complementary Acquisitions. We seek to acquire long-lived producing properties with a high degree of operating control that contain opportunities to profitably increase natural gas and crude oil reserves and production levels through exploitation. Our reservoir enhancement techniques include the implementation of technically advanced reservoir management and aggressive cost management of field operations. We target acreage that we believe will expose us to high potential prospects located in areas that are geologically similar to neighboring areas with large developed fields. Consistent with our primary operating strategy, our acquisition focus is on unconventional reserves, including additional interests in properties we currently operate. Our significant operating position in Michigan uniquely positions us for further consolidation in that state through acquisitions that would provide additional economies of scale.
Management of Commodity Price Risk. We are focused on growing our oil and gas operations while seeking to moderate the effect of commodity price swings on net income and cash flow from operations. Our commodity price risk management strategy helps to ensure a predictable base level of cash flow, which enhances our ability to execute our drilling and exploitation programs, meet debt service requirements and pursue acquisition opportunities despite price fluctuations. 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. The sales contracts and financial hedges covered approximately 77% and 67% of our daily natural gas and crude oil production, respectively, or 68% of our total daily production, for the fourth quarter of 2004. As our five-year fixed price natural gas swaps terminate in 2005, we have begun to modify our hedging programs. We anticipate that those programs will make use of hedges with terms generally no longer than 12 to 18 months that allow us to realize a portion of any market increases in natural gas or crude oil prices over their term. Presently, about 50% of our budgeted 2005 natural gas production is hedged using the sales contracts and financial hedges. Additionally, almost 60% of our budgeted crude oil production for 2005 is hedged using price collars.
Participation in Exploratory Drilling Projects. We will continue to focus the bulk of our activities on lower risk exploitation activity and development drilling, including future activities in Canada; however, we will continue additional exploratory drilling in Canada, exploration and evaluation of the Barnett Shale formation in north Texas, and to pursue additional leasehold acquisitions and joint venture opportunities aimed at providing us with opportunities to explore for unconventional gas, including fractured shales, coal beds and tight sands, to which our technical and operational expertise is well suited.
We sell natural gas 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, refineries and other users of petroleum products, and we are not dependent upon one purchaser or a small group of purchasers. Accordingly, the loss of a single purchaser in areas in which we sell natural gas or crude oil would not materially affect our sales. During 2004, the two largest purchasers of our total consolidated natural gas and crude oil sales were Encana Corporation and CoEnergy Trading Company.
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. Many competitors have financial and other resources, which substantially exceed ours. Our competitors in development, exploration, acquisitions and production include the major oil and gas companies as well as numerous independents and
individual proprietors. Resources of our competitors may enable them to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties or prospects. Our ability to replace and expand our reserve base is dependent upon our ability to select and acquire suitable producing properties and prospects for future drilling.
Our acquisitions and exploration and drilling programs have been financed primarily through the issuance of debt and equity and internally generated cash flow. There is competition for capital to finance oil and gas acquisitions and drilling. Our ability to obtain such financing is uncertain and can be affected by numerous factors beyond our control. The inability to raise capital in the future could have an adverse effect on our business.
Our operations are affected from time to time in varying degrees by political developments and United States 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 gas and crude oil exploration, development, production and pipeline gathering operations are subject to stringent United States 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 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 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 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 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 limitations 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 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.
As of March 1, 2005, we had 331 full time employees and 11 part time employees. There are no collective bargaining agreements in effect.
The following information is provided with respect to our officers.
The following biographies describe the business experience of our executive officers and the other officers named above.
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. 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. Mr. Darden graduated from Tulane University with a BA in Economics in 1975. 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 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 November 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 Corporation. He graduated from Tulane University in 1979 with a BA in Earth Sciences. 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 became our Chief Executive Officer in November 1999.
BILL LAMKIN is a Certified Management Accountant and a Certified Cash Manager with over 20 years of experience in the oil and gas industry. He graduated from Texas Wesleyan University with a BBA in Accounting in 1968. He served as Controller/Chief Financial Officer at Whittaker Corporation and Sargeant Industries, Inc. between 1970 and 1978. He worked as Treasurer, Controller, and Director of Financial Services at Union Pacific Resources from 1978 until he became our Executive Vice President and Chief Financial Officer when he joined us in June 1999.
JEFF COOK became our Senior Vice President Operations in 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 before joining us. Mr. Cook graduated from Texas Christian University with a BA in Finance in 1979.
MARK D. WHITLEY became our Vice President Operations in August 2003. He has more than 28 years of oil and gas production and operations experience including 20 years with Mitchell Energy Company LP, as its Vice President and General Manager of North Texas Production prior to its 2002 merger with Devon Energy. While at Devon from January 2002 to October 2002, Mr. Whitley served as Operations Manager Fort Worth Basin and directed the production and operations activity in the exploration of the Fort Worth Basins Barnett Shale gas play. After leaving Devon, he was an independent consultant until joining us. He graduated with a MS in chemical engineering from the University of Kentucky in 1975 after receiving his undergraduate degree from Worcester Polytechnic Institute.
ROBERT N. WAGNER was named as our Vice President Reserve Group 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. Mr. Wagner received a BS in Petroleum Engineering from the Colorado School of Mines in Golden, Colorado in 1986.
D. WAYNE BLAIR is a Certified Public Accountant with over 25 years of experience in the oil and gas industry. He graduated from Texas A&M University in 1979 with a BBA in Accounting. 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 and Controller, he was the Controller for Mercury from 1996.
JOHN C. CIRONE was named as our Vice President, General Counsel and Secretary on July 1, 2002. He graduated from St. Louis University School of Law in 1974 and 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.
ANNE DARDEN SELF has served on our board of directors since September 1999, and she became our Vice President-Human Resources in July 2000. She is also currently President of Mercury, where she has worked since 1992 as its Vice President Human Resources. 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. She attended Sweet Briar College and graduated from the University of Texas in Austin in 1980 with a BA in history.
J. MICHAEL GATENS is Chairman/CEO of MGV Energy Inc., which he co-founded in September 1997 in Calgary, Alberta. MGV became a wholly owned subsidiary of Quicksilver Resources Inc. in December 2000. Mr. Gatens is also Chairman of the Canadian Society for Unconventional Gas, and is MGVs liaison with the Coal Association of Canada and the Canadian Association of Petroleum Producers. Prior to starting MGV in 1997, he worked for S.A. Holditch & Associates, Inc. for 15 years, leaving as Director and Vice President of the Eastern Division in Pittsburgh. Mr. Gatens received BS and MS degrees in Petroleum Engineering from Texas A&M University in 1980 and 1987.
GEORGE W. VONEIFF co-founded MGV Energy Inc. in Calgary, Alberta in September 1997 to pursue unconventional gas opportunities, primarily in Western Canada. MGV became a wholly owned subsidiary of Quicksilver Resources Inc. in December 2000 and Mr. Voneiff continued in his role as President and Chief Operating Officer until January 2005 when he relinquished the role of Chief Operating Officer. Prior to founding MGV, he was with the petroleum consulting firm S.A. Holditch & Associates, Inc. from 1991 to 1997 and worked for Enserch Exploration Inc. from 1984 to 1990. Mr. Voneiff received BS and MS degrees in Petroleum Engineering from Texas A&M University in 1983 and 1991.
DANA W. JOHNSON became Senior Vice President and Chief Operating Officer of MGV Energy Inc. in January 2005. He joined us as U.S. Eastern Region Manager in early 2004 after serving 22 years in a variety of managerial, business development and engineering positions with Shell Exploration & Production Company. Mr. Johnson received a BS in Metallurgical Engineering from California Polytechnic State University in 1982 and a MBA from the University of Houston in 1992.
MARLU HILLER is a Certified Public Accountant with over 15 years of experience in public and oil and gas accounting. She graduated from Baylor University with a BBA in Accounting in 1985, and was with Ernst & Young for three years before joining Union Pacific Resources. At Union Pacific Resources, she served in various capacities, including financial reporting, financial system implementations, and manager of accounting for Union Pacific Fuels, which was Union Pacific Resources marketing company. Ms. Hiller joined us in August of 1999 as Director of Financial Reporting and Planning and was named Treasurer in May of 2000.
You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report or in any other of our filings with the Securities and Exchange Commission (SEC) 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.
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, 2004, we had total consolidated debt of $399.5 million. Subject to the limits contained in the loan agreements governing our senior secured revolving credit facilities and our second lien mortgage 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 interest and principal payments under our senior secured revolving credit facilities and our second lien mortgage notes. 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 comes due. Our future operating performance and ability to refinance will be affected by prevailing economic conditions at that time and financial, business 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 second lien mortgage notes restrict our ability and the ability of some of our subsidiaries to engage in certain activities that require the maintenance of specified financial ratios.
The loan agreements for our senior secured revolving credit facilities and second lien mortgage 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 and second lien mortgage notes 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 our inability to maintain the financial ratios described above could result in an event of default under our senior secured revolving credit facilities and/or our second lien mortgage notes. Upon the occurrence of such an event of default, the applicable lenders could, subject to the terms and conditions of the applicable security agreement, elect to declare all amounts outstanding under the applicable facility or notes, together with accrued interest, to be immediately due and payable. If we were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure such indebtedness. If our lenders accelerate the payment of our indebtedness, there can be no assurance that our assets would be sufficient to repay in full such indebtedness and our other indebtedness. The above restrictions could limit our ability to obtain future financing and may prevent us from taking advantage of attractive business opportunities.
Because we have a limited operating history in certain 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 cannot assure you that we will 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 credit facility is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas 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 wholesale price of natural gas rose from approximately $2.00 per thousand cubic feet in January of 2002 to over $10.00 in February of 2003. Among the factors that can cause this fluctuation are:
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 such as 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, 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, 2004, approximately 23% 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, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the 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. A more accurate discount factor will take into consideration effective interest rates at the time of the valuation, estimated future prices and costs and consider the risks associated with us, our oil and gas reserves and the oil and gas industry in general.
Our key assets are concentrated in a small geographic area.
Approximately 70% of our 2004 production was from Michigan and approximately 20% was from Alberta, Canada. Because of our concentration in these geographic areas, any regional events that increase costs, reduce availability of equipment or supplies, reduce demand or limit production, including weather and natural disasters, may impact us more than if our operations were more geographically diversified.
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 MGV. At December 31, 2004 we estimated our proved Canadian reserves to be 261.1 Bcf. We expect MGV to continue the current pace of its scheduled activities, expand into other areas and increase its capital expenditures. Capital expenditures relating to MGVs operations are budgeted to be approximately $107 million in 2005, constituting approximately 41% of our total 2005 budgeted capital expenditures.
If our revenues decrease as a result of lower natural gas or crude oil prices or otherwise, we may have limited ability to maintain this level of capital expenditures. In the event additional capital resources are unavailable to us, we may curtail our acquisition, development drilling and other activities outside of Canada in order to keep pace with Canadian drilling activities. 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 may have difficulty financing our planned growth.
We have experienced and expect to continue to experience substantial capital expenditure and working capital needs, particularly as a result of our property drilling and acquisition activities. In the future, we will most 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, we may have limited ability to expend the capital necessary to replace our reserves or to maintain production at current levels, 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.
United States 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. According to customary industry practices, we maintain insurance against some, but not all, of such risks and losses. 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 necessarily 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, Indiana/Kentucky, Texas, the Rocky Mountains and Alberta, Canada, we cannot assure you that we will not pursue acquisitions of properties in other locations.
The failure to replace our reserves could adversely affect our production and cash flows.
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, which are primarily 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 where we can utilize our experience as a low-cost operator. 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 at low finding and development costs. 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.
We cannot control the activities on properties we do not operate.
As of December 31, 2004, other companies operated properties that included approximately 27% 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, 2004, other companies owned processing plants and pipelines that delivered approximately 63% of our natural gas production to market in Michigan. In addition, all of our Canadian natural gas production is transported through third party pipelines. As a result, 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. This risk was highlighted in 2003 by the shutdown of CMS Energy Inc. and Michigan Consolidated Gas Co. processing plants in Michigan that resulted in an approximate 725 Mmcf decrease in our 2003 production.
The loss of key personnel could adversely affect our ability to operate.
Our operations are dependent on a relatively small group of key management and technical personnel. We cannot assure you that these individuals will remain with us for the immediate or foreseeable future. The unexpected 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 operate and develop 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 in 2004 for the sale of approximately 28% of our natural gas production and for a significant portion of our total revenues. 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.
Hedging our production may result in losses.
To reduce our exposure to fluctuations in the prices of natural gas and crude oil, we have entered into long-term natural gas and crude oil hedging arrangements. These hedging arrangements expose us to risk of financial loss in some circumstances, including the following:
In addition, these hedging arrangements may limit the benefit we would receive from increases in the prices for natural gas and crude oil in the following instances:
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 production months end. 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.
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 United States 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.
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 Mercury and Quicksilver Energy, L.P., entities primarily owned by members of the Darden family, beneficially own on the date of this annual report approximately 37% 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 stock. There were 50,122,360 shares of our common stock outstanding at December 31, 2004, including 172,626 shares issuable
upon exchange of exchangeable shares issued by MGV. Approximately 30,608,710 of these shares are freely tradable without substantial restriction or the requirement of future registration under the Securities Act. In addition, at December 31, 2004 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.
We file annual, quarterly and special reports, proxy statements and other information with the SEC. Our SEC filings are available to the public over the Internet at the SECs web site at http://www.sec.gov. You may also read and copy any document we file at the SECs public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. You may obtain information on the operation of the SECs public reference room in
Washington, D.C. by calling the SEC at 1-800-SEC-0330. 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.
We own significant natural gas and crude oil production interests in the following geographic areas:
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 generally allows Michigan producers to sell their natural gas at a slight premium to typical 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. 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, 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.
At December 31, 2004, we owned working interests in 2,956 producing Antrim wells and operated 50% of those wells. Since 1998, we have drilled 479 Antrim wells and successfully completed 473 for a success rate of 99%. In 2004, we drilled and successfully completed 44.3 (net) Antrim wells. For 2005, we have budgeted for the drilling of 51 (net) Antrim wells, including several horizontal wells.
Our non-Antrim reserves include interests in several reservoirs that include the Prairie du Chien (PdC), Garfield Richfield, Detroit River Zone III (DRZ3) and Niagaran pinnacle reefs. Our PdC wells produce from several Ordovician age reservoirs with the majority being in the 1,000 feet to 1,200 feet thick PdC Group that has three major sands: the Lower PdC, Middle PdC and Upper PdC. Many of these wells also can produce from the
St. Peter sandstone and the Glenwood formations, both of which lie directly above the PdC. Some of the wells are producing from two or more of these zones. 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 three development wells were drilled in 2003 and 2004 to increase production from existing fields. At year-end we had 32 gross (25.9 net) PdC wells producing. 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 Richfield zone consists of seven dolomite reservoirs spread over a 200-foot interval. The Garfield Richfield has seven wells producing under primary solution gas drive. Additional potential exists in the Garfield Richfield either by secondary waterflood and/or improved oil recovery with CO2 injection. The potential upside is under evaluation and has not been included in our booked reserves. The Beaver Creek Richfield is currently being waterflooded, with 96 producing wells and 58 water injection wells.
The Detroit River Zone III (DRZ3) at Beaver Creek lies approximately 200 feet above the Richfield. The DRZ3 is a six-foot dolomite zone that covers approximately 10,000 acres on the Beaver Creek structure. We had 28 producing wells as of December 31, 2004. While there is the opportunity for improving production and proved reserve quantities, we have determined that our resources are better allocated to continued exploration and development of our many unconventional gas projects.
Our Niagaran wells produce from numerous Silurian-age Niagaran pinnacle reefs located in nine counties in Northern Michigan. The depth of these wells range from 3,400 feet to 7,800 feet with reservoir thickness from 300 feet to 600 feet. 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. As of December 31, 2004, we had 68 gross (31.7 net) producing Niagaran wells.
In 2000, we began to focus on the potential of Canadian CBM through MGV. 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 the province of Alberta. By January 2003, the joint venture had drilled 175 exploratory, pilot and development wells. 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, we have drilled 468.3 successful net wells, most as operator, including significant developments in the Gayford and Beiseker areas. By December 31, 2004, we had proved reserves of 247.9 Bcf from our CBM projects and had ongoing field operations in all our joint ventures.
During 2005, we expect to drill 497 wells (275 net) and install nine new CBM facilities. Each plant will be capable of processing five to ten MMcfd of natural gas production. A portion of our 2005 capital budget of $107 million will be committed to CBM drilling including testing of the Mannville coals.
Including its interests in other conventional natural gas properties located in southern Alberta, MGV held interests in 1,266 gross (572.3 net) wells as of December 31, 2004. Our total Canadian proved reserves at December 31, 2004 were estimated to be 261.1 Bcf including 13.2 Bcf from our conventional gas properties. Our average daily production in Canada for 2004 was 23.8 MMcfd. As of December 31, 2004, however, we had increased total Canadian production to approximately 38 MMcfd.
In 2000, we acquired a 100% working interest in 36 New Albany Shale producing wells. Included with the acquisition of these producing wells, we also acquired the eight-mile 12-inch GTG gas pipeline that runs from
southern Indiana to northern Kentucky. We acquired 35 wells in 2003. At December 31, 2004, we had 192 producing wells in Indiana/Kentucky. In September 2003, we commenced transportation of New Albany production through a pipeline extension that connects to the Texas Gas Pipeline in northern Kentucky. Natural gas sales from our properties in the area averaged 5.9 MMcfd during 2004.
During 2004, we began testing and exploration in the Barnett Shale of north Texas. As of December 31, 2004, we had completed drilling on eight 100%-owned wells and owned non-working interests in four others wells. Initial production rates from the first wells completed ranged from 600 Mcfd to 1.8 MMcfd. Modifications to the fracturing techniques have resulted in improvements in each successive well drilled. Initial rates from the last four operated wells have ranged from 2.0 to 2.8 MMcfd. As of December 31, 2004, our production from the Barnett Shale was approximately 1 MMcfd. Our wells are spread over an area stretching from northwest Johnson County to southeastern Hood County, approximately 20 miles in a north-south direction and we held approximately 207,000 net acres in the Barnett Shale play as of year-end.
Our plans for 2005 include drilling approximately 40 net wells in the Barnett Shale and beginning on construction of the initial phase of the Cowtown Pipeline in the second quarter of 2005. This pipeline will transport both Quicksilver and third party volumes. In addition, we plan to install a natural gas liquids extraction plant that will be operational in the fourth quarter of 2005.
Rocky Mountain Region
Our Rocky Mountain properties are located in Montana and Wyoming. Production from those properties is primarily crude oil that is from well-established producing formations at depths ranging from 1,000 feet to 17,000 feet. As of December 31, 2004, our Rocky Mountain proved reserves were 6.0 MMbbls of crude oil and 4.0 Bcfe of natural gas and NGLs for total equivalent reserves of 40.0 Bcfe after our third quarter divestiture of properties with reserves of approximately 3.4 MMbbls of crude oil and 0.2 Bcfe of natural gas. In 2004, our daily production averaged 5.9 MMcfed. After the sale of most of our Wyoming properties in the third quarter of 2004, fourth quarter production averaged 3.4 MMcfed.
Oil and Gas Reserves
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, LaRoche Petroleum Consultants, Ltd. and Netherland, Sewell & Associates, Inc. prepared our reserve estimates. 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 only by contractual arrangements, but not on escalations based upon future conditions. Prices do not include the effect of derivative instruments we have entered into. Future production and development costs include production and property taxes.
Proved developed oil and gas reserves are reserves that can be 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, 2004, 2003 and 2002.
Volumes, Sales Prices and Oil and Gas Production Expense
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:
Acquisition, Exploration and Development Capital Expenditures
Productive Oil and Gas Wells
The following table summarizes productive oil and gas wells attributable to our direct interests as of December 31, 2004:
Oil and Gas Acreage
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 following table 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 oil or 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.
In August 2001, a group of royalty owners, Athel E. Williams et al., brought suit against us and three of our subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd, one of our 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. The court heard arguments on class certification on November 8, 2002, and on December 6, 2002 the court issued a memorandum opinion granting class certification in part and denying it in part. On December 20, 2002, we filed a motion for clarification and reconsideration of the courts order. That motion was denied on March 9, 2003. After an extended delay resulting from the retention of new counsel by the plaintiffs and the initiation of settlement discussions, on January 21, 2005, the Circuit Court issued an order certifying certain claims to proceed on behalf of a class. The Circuit Court also entered a scheduling order setting trial for January 2007, and declined Defendants request to stay proceedings in that court pending an appeal of the certification order.
Defendants have sought leave to appeal the certification order by filing an Application for Leave to Appeal on February 11, 2005 with the Michigan Court of Appeals. Defendants have also requested that the Court of Appeals stay proceedings in the Circuit Court pending the consideration of its appeal, and have requested that the Court of Appeals consider all matters in an expedited manner. We are currently awaiting a ruling from that court on the application and the requests for stay and immediate consideration.
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 condition, results of operations, or cash flows.
There were no matters submitted to a stockholder vote during the fourth quarter of 2004.
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 28, 2005, there were approximately 488 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.
The following tables set 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
(in thousands, except for per share data)
The following Managements Discussion and Analysis (MD&A) is intended to help the reader understand Quicksilver Resources Inc. 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 an independent oil and gas company engaged in the exploration, acquisition, development, production and sale of natural gas, crude oil and natural gas liquids primarily from unconventional reservoirs such as fractured shales, coal beds and tight sands. We generate revenue, income and cash flows by producing and selling natural gas, crude oil and natural gas liquids. We produce these products in quantities and at prices that, in addition to generating operating income, allow us to conduct exploration, development and acquisition activities to replace the reserves that have been produced.
At December 31, 2004, approximately 92% of our proved reserves were natural gas. Our Michigan reserves make up approximately 62% of those reserves. Our Michigan activities in the Antrim shale have allowed us to develop a technical and operational expertise in the acquisition, development and production of unconventional natural gas reserves. Consistent with one of our business strategies, we have applied our expertise gained in our Michigan activities to our Canadian coal bed methane (CBM) projects in Alberta, Canada. Our Canadian reserves made up about 27% of our proved reserves at December 31, 2004. Our Indiana/Kentucky New Albany Shale and Texas Barnett Shale projects represent additional extensions of that expertise.
For 2005, we plan to continue our focus on the exploration and development of CBM properties in Alberta, Canada and our Barnett Shale acreage in Texas. We expect budgeted capital expenditures in 2005 to be as much as $261 million, of which about $107 million is allocated to our Canadian CBM projects and approximately $115 million is allocated to our Barnett Shale position in north Texas. The remainder is allocated to our fractured shale projects in Michigan and Indiana/Kentucky.
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 exploration and development of unconventional natural gas reservoirs. We strive to increase reserves and production through aggressive management of operations and relatively low-risk development drilling. We will also continue to identify high potential exploratory projects with higher levels of financial risk. Both our low-risk development programs and exploratory projects are aimed at providing the Company with opportunities to explore for, and develop, unconventional natural gas reservoirs to which our technical and operational expertise is well suited.
Our principal properties are well suited for production increases through exploitation activities and development 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 these key measurements: earnings; cash flow from operating activities; production and overhead costs per unit of production; production volumes; reserve growth; and finding costs per unit of reserve addition.
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 Quicksilver to participate in all, or a portion, of any favorable price increases. This commodity price strategy enhances our ability to execute our drilling 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 development and exploratory drilling and acquisition activities. We might also be forced to sell some of our assets on an untimely or unfavorable basis.
Natural gas prices were favorable throughout 2004 and 2003 and industry analysts expect them to remain favorable for the foreseeable future. With continued favorable gas prices, the expiration of our remaining fixed price natural gas hedges in April 2005 and increasing natural gas production, we expect to fund more of our capital expenditures with cash flow from operations; however, we do not expect our cash flow from operations to be sufficient to satisfy our total budgeted capital expenditures. We plan to use cash flows from operations, credit facility utilization and possible issuance of debt or equity securities to fund our total budgeted capital expenditures in 2005.
FINANCIAL RISK MANAGEMENT
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 sell approximately 25,000 Mcfd and 10,000 Mcfd of natural gas under long-term contracts with floor prices of $2.49 per Mcf and $2.47 per Mcf, respectively, through March 2009. Approximately 5,300 Mcfd sold under these contracts in 2004 were third party volumes controlled by us. We also enter into financial contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas and crude oil production. These contracts have included price ceilings and floors, no-cost collars and fixed price swaps.
Natural gas sales volumes of 30,000 Mcfd are hedged for the first four months of 2005 using fixed price swap agreements entered into in May 2000. The weighted average price for natural gas volumes under those agreements is $2.79. Natural gas price collars hedge approximately 20,000 Mcfd of our budgeted natural gas sales volumes for the first quarter of 2005. Natural gas price collars hedge nearly 33,000 Mcfd of our budgeted natural gas sales volumes for the remainder of 2005. Additionally, price collars hedge approximately 750 Bbld of our 2005 budgeted crude oil sales.
The following table summarizes our open financial derivative positions as of December 31, 2004 related to natural gas and crude oil production.
Utilization of our financial hedging program may result in realization of natural gas and crude oil prices that vary from the actual prices that we receive from the sale of natural gas and crude oil. As a result of the hedging programs, revenues from production were lower than if the hedging programs had not been in effect by $43.9 million in 2004, $39.8 million in 2003 and $7.4 million in 2002.
Commodity price fluctuations affect our remaining natural gas and crude oil volumes as well as our NGL volumes. Up to 4,500 Mcfd of natural gas is committed at market price through May 2005. Additional natural gas volumes of 16,500 Mcfd are committed at market price through September 2008. During 2004, approximately 6,400 Mcfd of our natural gas production was sold under these contracts. The remaining Mcfd contractual volumes were third-party volumes controlled by us.
Based on our 2004 average production and long-term natural gas sales contracts with floor prices of $2.49 per Mcf and $2.47 per Mcf, and our 2004 average production, each $1.00 per Mcf increase/decrease in the price of natural gas would increase/decrease our revenue by approximately $28.1 million. Should additional revenue of $28.1 million be realized, approximately $3.6 million would be required for settlement of our remaining fixed price hedges.
We have entered into various financial contracts to hedge exposure to commodity price risk associated with future contractual natural gas sales and purchases with derivative instruments. These contracts include either fixed and floating price sales to, or purchases from, third parties. As a result of these firm sale and purchase commitments and associated financial price swaps, the hedge derivatives qualified as fair value hedges for accounting purposes. Marketing revenues were $0.5 million and $0.3 million higher and lower by $2.2 million as a result of our hedging activities in 2004, 2003 and 2002, respectively. Hedge ineffectiveness resulted in $118,000 of net losses, $188,000 of net gains and $26,000 net losses recorded to other revenue for 2004, 2003 and 2002, respectively.
The following table summarizes our open financial derivative positions and hedged firm commitments as of December 31, 2004 related to natural gas marketing.
The fair value of fixed price and floating price natural gas and crude oil derivatives and associated firm commitments as of December 31, 2004 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 to assume our contract positions.
Interest Rate Risk
We manage our exposure associated with interest rates by entering into interest rate swaps. As of December 31, 2004, the interest payments for $75.0 million notional variable-rate debt are hedged with an interest rate swap that converts a floating three-month LIBOR base to a 3.74% fixed-rate through March 31, 2005. Our liability associated with the swap was $0.2 million at December 31, 2004 and $2.0 million at December 31, 2003.
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 is being recognized over the original term for the swap, which ends December 31, 2006. A deferred gain of $0.2 million remains at December 31, 2004.
Interest expense for the years ended December 31, 2004, 2003 and 2002 was $0.8 million, $1.4 million and $2.6 million higher, respectively, as a result of the interest rate swaps.
If interest rates on our variable interest-rate debt of $112.8 million, as of February 28, 2004, and $75 million of variable rate debt hedged through March 31, 2005 increase or decrease by one percentage point, our annual pretax income will decrease or increase by $1.7 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 1. BusinessRisk 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.
Foreign Currency Risk
Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. During October and November 2004, Quicksilver loaned MGV approximately $11.4 million. To reduce its exposure to exchange rate risk, MGV 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 and upon settlement of the forward contract, MGV recognized a gain of $0.2 million.
While cross-currency transactions are minimized, the result of a ten percent change in the Canadian-U.S. exchange rate would increase or decrease equity by approximately $6.4 million at December 31, 2004.
APPLICATION OF CRITICAL ACCOUNTING POLICIES
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.
Use of Estimates
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.
Oil and Gas Properties
We employ the full cost method of accounting for our oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in cost centers on a country-by-country basis. This includes any internal costs that are directly related to exploration and development 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.
Net capitalized costs are limited to the lower of unamortized cost net of related deferred tax or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge our oil and gas revenue and asset retirement obligations; (ii) the cost of properties not being amortized; (iii) the lower of cost or market value of unproved properties included in the costs being amortized less (iv) income tax effects related to differences between the book and tax basis of the oil and gas properties. Such limitations are imposed separately for the U.S. and Canadian cost centers.
Oil and Gas Reserves
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 include financial derivatives that hedge our oil and gas revenue.
The Companys estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates, made by the Companys 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 DD&A rate calculation and the financial statements.
Companies that use the full cost method of accounting for oil and gas properties are required to perform the ceiling test each quarter. The ceiling is an impairment test performed on a country-by-country basis as prescribed by SEC Regulation S-X Rule 4-10. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically 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. This ceiling is compared to the net book value of the 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 ceiling, an impairment or noncash writedown is required. A ceiling test impairment can give the Company 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, 2004, capitalized costs, inclusive of future development costs, for U.S. and Canadian reserves were $1.18 per Mcfe and $0.78 per Mcfe, respectively.
We enter into financial derivative instruments to hedge risk associated with the prices received from natural gas and crude oil production and marketing. 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 that meet 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.
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, 2004, our revenues for 2005 will decrease approximately $10.2 million and interest expense will increase approximately
$0.2 million. Net income, after income taxes, will be approximately $6.8 million lower. These amounts will be reclassified from accumulated other comprehensive income in 2005.
Asset Retirement Obligations
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 Statement of Financial Accounting Standard (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.
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. MGV, the Companys Canadian subsidiary, 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 MGV and thus are not considered available for distribution to the parent Company.
Included in our net deferred tax liability are $51.8 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.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements within the meanings of Item 303(a)(4) of SEC Regulation S-K.
RESULTS OF OPERATIONS
Summary Financial Data
Years Ended December 31, 2004, 2003 and 2002
Net income for each of the years ending December 31, 2004, 2003 and 2002 was $31.3 million ($0.62 per diluted share), $16.2 million ($0.35 per diluted share) and $13.8 million ($0.34 per diluted share), respectively. Included in 2003 was a $2.3 million charge ($0.05 per diluted share), net of tax, for the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003. The 2003 period also included a $3.8 million pre-tax charge ($2.5 million after tax) to interest expense as a result of our early redemption of $53 million in principal amount of our subordinated notes payable.
Our 2004 revenues were $179.7 million as compared to $141.0 million for 2003, primarily as a result of additional Canadian revenue in 2004. The additional Canadian revenue was from a 5,776,000 net Mcfe increase in Canadian production from coal bed methane (CBM) projects and a 24% increase in realized prices. U.S. production revenue increased by approximately 5% over 2003 revenue with an 11% increase in realized prices being partially offset by a decrease in production of 1,711,000 Mcfe.
Total revenues for 2003 were $141.0 million, a $19.0 million increase from the $122.0 million reported in 2002. Higher realized prices and additional sales volumes increased revenue $26.7 million. The increase was primarily the result of sales volumes added from our Canadian CBM development projects and an 84% increase in Canadian realized sales prices. Additionally, U.S. realized prices increased approximately 19%. Additional revenue associated with U.S. prices increases was partially offset by an approximately 1,000,000 Mcfe decrease in U.S. sales volumes. Other revenue for 2003 was $7.8 million lower from the prior year. Revenue of $5.1 million was recognized from the sale of Section 29 tax credits in 2002. The tax credits expired in 2002. In 2003, a $0.5 million decrease in other revenue was the result of the completion of our negotiations to purchase the tax credit properties.
Gas, Oil and NGL Sales
Our sales volumes, revenues and average prices for the years ended December 31, 2004, 2003 and 2002 are as follows:
Our natural gas sales for 2004 were $150.7 million and increased $34.1 million from 2003 natural gas sales of $116.6 million. Our realized gas prices in the U.S. and Canada increased 6% and 24%, respectively. Increased prices contributed $23.8 million of the increase in 2004 sales. Natural gas sales volumes showed a net increase of 4,815,000 Mcf for 2004. Canadian 2004 sales volumes were nearly 5,760,000 Mcf over 2003 production of 2,935,000 Mcf; an increase of almost 200%. U.S. sales volumes were increased by production from new wells drilled in the New Albany Shale in Indiana and Kentucky, 1,380,000 Mcf; the Michigan Antrim Shale, 975,000 Mcf; the Michigan Prairie du Chien formation, 185,000 Mcf; and our initial production from the Barnett Shale in north Texas, 130,000 Mcf. Declining production rates on existing wells was the primary factor in production decreases that partially offset the production from new wells.
Our 2004 revenue from crude oil was $22.8 million and $3.2 million higher than 2003 crude oil revenue of $19.6 million. A 36% increase in realized crude oil prices from $24.23 to $33.07 per barrel boosted revenue $7.1 million. Lower volumes partially offset the increase due to prices by $3.9 million. The sale of Wyoming crude oil properties to Meritage Energy Partners LLC in the third quarter of 2004 lowered volumes by approximately 53,200 barrels. The remainder of the decrease was primarily due to natural declines from existing wells.
Sales of NGLs increased $0.8 million for 2004 to $3.7 million. The additional revenue was primarily the result of a 33% increase in realized NGL prices to $28.52 per barrel for 2004. A decrease in NGL volumes of approximately 6,000 barrels partially offset the increase from higher prices. Property dispositions in the third quarter of 2004 caused approximately 1,100 barrels of the volume decrease.
Natural gas sales for 2003 increased $26.3 million from 2002 to $116.6 million. Our average realized natural gas price increased 23% to $3.38 per Mcf for 2003 and increased sales $20.6 million. Volumes increased 1,690,000 Mcf from 2002 to 2003 and increased sales $5.7 million. Sales volumes for 2003 increased approximately 5,856,000 Mcf as a result of our drilling programs in the U.S. and Canada. Sales volumes from our Canadian CBM projects, which started production in January 2003, were approximately 2,113,000 Mcf for 2003. U.S. sales volumes increased 2,434,000 Mcf as a result of the additional interests in Michigan properties purchased from Enogex in December 2002. New wells drilled in the Michigan Antrim and Indiana New Albany formations increased sales volumes 1,071,000 Mcf and 239,000 Mcf, respectively. These increases were offset by curtailments in sales volumes as a result of extremely cold weather in the first quarter of 2003 and shutdowns of third party processing plants and pipelines in the second through fourth quarters of 2003. These events reduced sales volumes by approximately 260,000 Mcf and 814,000 Mcf, respectively. Additionally, March through September 2003 sales from our Indiana properties were curtailed when our local end-user reduced its deliveries of gas by approximately 161,000 Mcf. The remaining decreases were the result of natural decline in production from our existing natural gas wells.
Crude oil sales were $19.6 million for 2003 compared to $19.7 million in 2002. The $2.49 per barrel increase in our average realized crude oil price increased sales $2.3 million, which was nearly offset by the decrease in oil sales volumes for 2003. The 11% decrease in sales volumes to 808,000 barrels for the year was the result, in part, of a decrease of approximately 20,300 barrels due to the sale of Wyoming and Texas oil properties in June 2002. Natural production declines on existing wells contributed most of the remaining decreases. These reductions were partially offset by a full years production from wells drilled in the Beaver Creek Detroit River Zone 3 development that increased sales volumes 31,800 barrels.
NGL sales for 2003 increased $0.6 million to $2.9 million. NGL prices increased $6.53 from 2002 to $21.50 and resulted in a $1.0 million increase in sales that was partially offset by a decrease in sales volumes.
Other revenue, consisting primarily of revenue from the marketing, transportation and processing of natural gas, was $2.6 million for 2004 and about $0.6 million higher than other revenue for 2003. Other revenue in 2003 was reduced by $0.5 million as a result of the repurchase of Section 29 tax credit properties.
Other revenue of $1.9 million in 2003 consisted of revenue from the marketing, transportation and processing of natural gas. In 2002, other revenue also included revenue of $5.1 million from the sale of Section 29 tax credits. The tax credits expired in 2002. In 2003, a $0.5 million reduction in other revenue was the result of the repurchase of the tax credit properties. Natural gas marketing, transportation and processing revenue for 2003 was $2.5 million as compared to $4.6 million in 2002. Marketing revenue in 2003 decreased $1.8 million from 2002 primarily as a result of pipeline delivery imbalances that occurred during 2003. Repayments of those imbalances required the purchase of natural gas when natural gas prices had increased from the time in which the imbalances occurred resulting in marketing margin losses.
Our operating expenses for 2004 were $120.2 million and $26.4 million higher than operating expenses for 2003. Increases were primarily the result of higher sales volumes and producing well counts in Canada and Indiana, higher depletion rates and added depreciation on facilities and pipelines placed into service since mid-2003, and an increase in U.S. compressor overhauls performed in 2004 as compared to 2003. General and administrative costs also increased by $4.8 million in 2004.
Operating expenses were $93.8 million in 2003 compared to $81.5 million for 2002. The increase was primarily the result of additional sales volumes.
Oil and Gas Production Costs
Costs for the production of oil and gas were $65.2 million and $13.0 million higher in 2004 as compared to 2003. Higher oil and gas prices, as well as higher Canadian sales volumes for 2004, increased production tax expense $1.5 million. U.S. production expense increased $6.0 million in 2004, excluding production tax increases of $0.6 million. Initial operating expenses associated with new Indiana and Kentucky wells and production increased production expense approximately $2.2 million. The increase included approximately $0.9 million for salt-water disposal and equipment rentals. These expenses were the result of inadequate salt-water disposal capacity and delays in completing electricity connections at each well. During 2004, 35 new wells and 22 non-producing wells acquired in 2003 began production, in addition to 47 wells that began production in the fourth quarter of 2003. Operating costs began to decrease as initial production containing high concentrations of water was followed by natural gas production increases. Production overhead in Indiana increased approximately $0.8 million as a result of personnel added to operate and maintain these properties. Michigan and Indiana operating expenses increased approximately $1.5 million and $0.2 million, respectively, as a result of the routine periodic overhaul of several compressors. Similar overhaul expenses were not incurred during 2003. These items increased U.S. production expenses by $0.14 per Mcfe for 2004 compared to 2003. Remaining production expense increases were attributable to modest price increases across a broad range of expense categories.
Canadian production expenses in 2004, excluding a production tax increase of $0.9 million, increased $5.5 million for 2004. A net increase in Canadian production of approximately 5,780,000 Mcf and higher well counts were the primary factors for the increase. Total Canadian production expense, including production taxes, continued to reflect improving economies of scale as expense decreased on a Mcfe-basis to $1.19 per Mcfe.
Oil and gas production expense for 2003 was $52.2 million, compared to 2002 expense of $42.2 million. Production taxes were $3.0 million higher as a result of higher sales volumes and higher average natural gas and crude oil prices in 2003. Production expenses for U.S. properties in 2003 increased $5.0 million, excluding production tax increases of $2.7 million. Notable production expense increases included $3.1 million of additional expense associated with natural gas volumes produced from the acquired Enogex interests and $0.8 million resulting from settlement costs for post-production cost allowances in Michigan and environmental issues in Indiana and Michigan. Inventory losses, primarily in Indiana, increased expense $0.3 million in 2003. Additional operating expenses of approximately $0.8 million were primarily due to the start-up of producing wells in Indiana during the fourth quarter.
Canadian production expenses in 2003, excluding production taxes of $0.3 million, increased $1.9 million. Canadian production increased approximately 2,000,000 Mcf, primarily as a result of the start-up of production from our CBM projects in January 2003. Although absolute Canadian production expense increased, expense per Mcfe, including production taxes, decreased $0.49 to $1.35 per Mcfe for 2003 as a result of 2003 CBM production.
Depletion, Depreciation and Accretion
Depletion expense for 2004 was $34.5 million, as compared to 2003 depletion expense of $27.4 million. Additional sales volumes of approximately 4,070,000 Mcfe and a $0.10 per Mcfe increase in the consolidated depletion rate added $7.2 million of depletion expense from 2003 to 2004. The $0.10 per Mcfe higher consolidated depletion rate was the result of additional increases in future development costs as compared to increases in proved reserves when comparing engineering estimates of proved reserves for December 31, 2004 and 2003. The $1.2 million increase in 2004 depreciation was primarily the result of the addition of compression and transportation assets and overhead assets.
Depletion expense increased $0.4 million to $27.4 million in 2003. Increased depletion expense was the result of higher sales volumes partially offset by a slight decrease in our consolidated depletion rate. Additional depreciation of $0.7 million was primarily the result of additions to processing and transportation assets including the Cardinal Pipeline, which began operations in September 2003. Accretion expense of $0.7 million in 2003 was the result of the adoption of SFAS No. 143 as of January 1, 2003.
General and Administrative Expenses
General and administrative expenses were $12.9 million for 2004. Of the $4.8 million increase from 2003, additional expenses of $2.3 million were primarily the result of an increase in management and administrative personnel from August 2003 through March 2004. Contract labor, legal and accounting fees increased
approximately $1.0 million for 2004 due largely to new Sarbanes-Oxley and corporate governance requirements. Engineering and other professional fees increased approximately $0.4 million from 2003 due primarily to additional fees for preparation of required outside engineering reserve reports. Various other expenses including outside directors fees, charitable donations, insurance, investor relations and stock exchange fees increased a total of $0.6 million from 2003 expense amounts.
General and administrative expenses were $8.1 million for 2003 and $0.6 million higher than 2002 general and administrative expenses. The increase is primarily the result of $0.7 million in additional bonuses earned in 2003 and $0.3 million due to the addition of management personnel in the last half of the year. Professional fees were $0.2 million higher than in 2002 and were related to the use of additional engineering and accounting services. These increases were partially offset by the $0.3 million reduction in expense for contract labor in 2003.
Income from Equity Affiliates
Income from equity affiliates for 2003 increased $1.1 million from the prior year when we recorded losses of $0.8 million associated with Voyager Compression Services LLC. During 2002, Voyager recorded operating losses in addition to an impairment of its assets and lease termination costs in conjunction with ending its operations.
Interest expense for 2004 was $15.7 million and $4.5 million less than 2003 interest expense. Interest expense in 2003 included a charge of $3.8 million as a result of the early redemption of $53.0 million in principal amount of our subordinated notes payable, which included a $3.2 million prepayment penalty and the write-off of $1.5 million of remaining deferred financing costs, partially offset by a deferred hedging gain of $0.9 million. Ongoing interest expense decreased approximately $0.7 million due to a decrease in LIBOR interest rates and the 2003 issuance of our second mortgage notes, which accrue interest at a substantially lower rate than the subordinated notes payable that were retired in mid-2003, partially offset by an increase in our average debt outstanding during 2004 as compared to 2003.
Interest expense was $20.2 million in 2003. Interest expense for 2003 included a charge of $3.8 million as a result of the early redemption of $53.0 million in principal amount of our subordinated notes payable through the issuance of $70.0 million in principal amount of second mortgage notes. The $3.8 million charge consisted of a prepayment premium of $3.2 million and the write-off of $1.5 million of remaining deferred financing costs, partially offset by an associated deferred hedging gain of $0.9 million. Ongoing interest expense decreased $2.8 million as a result of a significant decrease in our effective interest rates that was partially offset by an increase in our average debt outstanding in 2003. The interest rates paid on our debt were lower in 2003 because of lower LIBOR rates and the refinancing of our subordinated notes payable through the issuance of our second mortgage notes.
Our income tax provision for 2004 was $14.2 million. Our U.S. income tax provision was established using the statutory U.S. federal tax rate of 35.0%. In addition to the deferred tax provision of approximately $8.8 million, a current U.S. tax provision of $0.8 million was accrued for U.S. federal income tax due on a dividend distribution of approximately $86.5 million made to us by MGV in 2004 and consisted of estimated earnings and profits of $15.5 million. We have planned for reinvestment of the dividend in the U.S. under a qualified domestic
reinvestment plan as defined under recently enacted Internal Revenue Code Section 965(a)(1), which allows 85% of the dividend to be excluded from U.S. taxable income for the year. The Canadian income tax provision consisted of a deferred tax provision of approximately $5.9 million accrued at a Canadian combined federal and provincial statutory rate of 33.6% and a current tax provision of $0.3 million. The deferred tax provision was reduced by a scientific, research and experimental development tax credit of $1.7 million. This credit was granted by Revenue Canada to MGV in 2004 for expenditures incurred in 2001.
Our income tax provision of $10.0 million for 2003 was established using an effective U.S. federal tax rate of 35%. The provision also includes $1.7 million for Canadian federal and provincial income tax expense. Canadian income tax expense includes consideration of tax rate reductions that were enacted during 2003. Income tax expenses increased from the prior year as a result of higher 2003 pretax income as compared to 2002.
LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION
Our statements of cash flows are summarized as follows:
Cash flows from operating activities increased $40.2 million, or 68%, for 2004 compared to 2003. The principal factor in the increase was a $12.2 million increase in operating income for 2004, together with increases in accounts receivable and payable, accrued liabilities and depletion, depreciation and amortization. In addition, 2003 income included a $3.2 million prepayment premium incurred when the $53 million of subordinated notes were redeemed. Operating cash flows were also higher because of MGVs use of cash calls on other working interest owners prior to incurring capital expenditures on various CBM exploration and development projects. A reduction in QRIs third party marketing activities further increased operating cash flows about $2.0 million.
Cash flows from operating activities were $15.1 million, or 34%, higher for 2003 compared to 2002. A 19% increase in operating income for 2003 as compared to 2002 was the principal factor. The $7.8 million increase in operating income was largely due to a 21% increase in realized average prices and a 3% increase in sales volumes. Operating income for 2002 included $5.1 million of deferred revenue that was offset by additional oil, gas and NGL revenue for 2003, which effectively increased operating cash flows by $5.1 million for 2003.
Our principal operating sources of cash include sales of natural gas, crude oil and NGLs and revenues from natural gas transportation and processing. We sold approximately 74% and 85% of our 2004 and 2003 natural gas and crude oil production, respectively, under long-term contracts with price floors and financial hedges. As a result, we benefit from significant predictability of our natural gas and crude oil revenues. However, when natural gas and crude oil market prices exceed our financial hedge swap prices, we are required 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 payment from our customers until 25 to 60 days after the month of production. Additionally, in the event of a significant production curtailment, we are required contractually to fulfill our commitments under our long-term sales contracts by purchasing natural gas volumes at market prices.
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, 2004. We currently estimate that our spending for property, plant and equipment in 2005 will be as much as $261 million. Total capital expenditures by operating segment for 2004, 2003 and 2002 are as follows:
Our 2004 capital expenditures for exploration and development activities were focused in four areas. Expenditures for Canadian exploration and development 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 exploration and development 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 transportation 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.
Capital expenditures in 2003 of $148.5 million included $69.0 million for development and exploration of our Canadian CBM projects and acreage. We spent $31.8 million for further development of our Indiana/Kentucky properties and additional acreage positions. Our pipeline in the area, Cardinal Pipeline, accounted for $4.0 million of our capital expenditures. Michigan capital expenditures of $24.6 million focused on continued development and exploitation of the Antrim Shale. A significant acreage position in north Texas was acquired for approximately $12.6 million in 2003.
We acquired Michigan natural gas interests from Enogex Exploration Corporation in December 2002 for approximately $32.0 million. Canadian capital expenditures were $15.0 million associated with CBM exploration costs and acreage acquisition. The remaining $42.0 million was spent on exploration and development costs incurred primarily in Michigan and Indiana.
During 2004, we extended and increased our senior secured credit facility. Currently, our credit facility is a revolving facility that matures on July 28, 2009 and permits us to obtain revolving credit loans and letters of credit from time to time in an aggregate amount not to exceed the lesser of the borrowing base or $600 million. The current borrowing base is $300 million and is subject to annual redetermination and certain other redeterminations based upon several factors. Scheduled redeterminations occur on May 1 of each year. Our borrowing base is impacted primarily by the fair value of our oil and gas reserves. Changes in the fair value of our oil and gas reserves are affected by prices for natural gas and crude oil, operating expenses and the results of our drilling activity. A significant decline in the fair value of our reserves could reduce our borrowing base. A borrowing base reduction could limit our ability to carry out our capital expenditure programs and, in some circumstances, require the repayment of a portion of our outstanding borrowings under the facility.
At our option, loans may be prepaid, and revolving credit commitments may be reduced, in whole or in part at any time in minimum amounts. As of year-end, we can designate the interest rate on amounts outstanding at either the London Interbank Offered Rate (LIBOR) +1.375% or specified bank rates. The collateral for the credit facility consists of substantially all of our existing assets and any future reserves acquired. The loan agreements prohibit the declaration or payment of dividends by us and contain other restrictive covenants, which, among other things, require the maintenance of a minimum current ratio (calculated in accordance with provisions of the loan agreements) of at least 1.0. At December 31, 2004, we were in compliance with all such restrictions and we had $119.1 million available under the credit facility.
On November 1, 2004, we sold $150 million of 1.875% convertible subordinated debentures due in 2024 for gross proceeds of approximately $147.8 million. Holders of the debentures may require us to repurchase all or a portion of their debentures on November 1, 2011, 2014 or 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into Quicksilver common stock at a rate of 21.8139 shares for each $1,000 debenture, subject to adjustment. This results in an initial conversion price of approximately $45.84 per share and represents a premium of 42.5 percent over the closing sale price of $32.17 per share on October 26, 2004. Generally, except upon the occurrence of specified events, holders of the debentures are not entitled to exercise their conversion rights until the Companys stock price is $55.01 (120 % of the conversion price per share). Upon conversion, we have the option to deliver in lieu of Quicksilver common stock, cash or a combination of cash and Quicksilver common stock.
On December 31, 2004, we had outstanding $70 million of Second Mortgage Notes due 2006, of which $40 million bore interest at a fixed rate of 7.5% and $30 million bore interest at a variable rate based upon three-month LIBOR plus 5.48%. The Second Mortgage Notes contain restrictive covenants that, among other things, require maintenance of a minimum current ratio of at least 1.0, a ratio of net present value of proved reserves to
total debt of at least 1.8 to 1.0; and a ratio of earnings before interest, taxes, depreciation and amortization and non-cash income and expense to interest expense of at least 1.25 (calculated in each case in accordance with provisions of the Second Mortgage Notes). At December 31, 2004, we were in compliance with such restrictions.
As of December 31, 2004, 2003 and 2002, 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 2005 capital expenditure budget of approximately $261 million will be funded by cash flow from operations, credit facility utilization and the possible issuance of debt or equity securities.
The following impacted our balance sheet as of December 31, 2004, as compared to our balance sheet as of December 31, 2003:
Contractual Obligations and Commercial Commitments
Information regarding our contractual obligations (within the scope of Item 303(a)(5) of Regulations S-K) as of December 31, 2004 is set forth in the following table. At December 31, 2004, we did not have any capital lease obligations or material purchase obligations that were binding on us and that specified all significant terms. Other long-term liabilities constituting contractual obligations reflected on our balance sheet at December 31, 2004 consisted of derivative obligations and asset retirement obligations.
We have the following commercial commitments as of December 31, 2004.
Standby Letters Of CreditOur letters of credit have been issued to fulfill contractual or regulatory requirements. The majority of these letters of credit were issued under our senior credit facility. All letters have an annual renewal option.
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, will, 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.
Recently Issued Accounting Standards
In December 2004, the Financial Accounting Standards Boards (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123(R), Share-Based Payment, which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods and services. SFAS No. 123(R) focuses primarily on accounting for transactions with employees, and carries forward without change prior guidance for shared-based payments for transactions with non-employees.
SFAS No. 123(R) eliminates the intrinsic value measurement objective in Accounting Principle Board (APB) Opinion 25 and generally requires measurement of the cost of employee services received in exchange for an award of equity instruments be based on the fair value of the award on the date of the grant. The standard requires grant date fair value to be estimated using either an option-pricing model that is consistent with the terms of the award or a market observed price, if such a price exists. Such cost must be recognized over the period during which an employee is required to provide service in exchange for the award (which is usually the vesting period). The standard also requires estimation of the number of instruments that will ultimately be issued rather than accounting for forfeitures as they occur.
We are required to apply SFAS No. 123(R) to all awards granted, modified or settled in our first reporting period under U.S. GAAP after June 15, 2005. The standard requires use of either the modified prospective method or the modified retrospective method. Under the modified prospective method, compensation cost is recognized for all awards granted after adoption of the standard and for the unvested portion of previous grant awards that are outstanding on that date. The modified retrospective method is used to recognize compensation cost for prior periods whereby previously issued financial statements are restated to recognize the amounts we previously calculated and reported on a pro forma basis. Under both methods, the standard permits the use of either a straight-line or an accelerated method to amortize the cost as an expense for awards that vest over time. The standard permits and encourages early adoption.
Management has commenced analysis of the impact of SFAS No. 123(R), but has not yet decided: (1) whether to elect early adoption, (2) if early adoption is elected, at what date to adopt the standard, (3) whether to use the modified prospective method or elect to use the modified retrospective method, and (4) whether to use straight-line amortization or an accelerated method. Additionally we cannot predict with reasonable certainty the number of options that will be unvested and outstanding on December 31, 2005. Accordingly, management cannot currently quantify with precision the effect this standard would have on the Companys financial position or results of operations in the future, except that a greater expense will probably be recognized for any awards that we may grant in the future.
In November 2004, the FASB issued SFAS No. 151, Inventory Costs, an amendment of ARB No. 43, Chapter 4, which amends Chapter 4 of ARB No. 43 that deals with inventory pricing. The statement clarifies the accounting for abnormal amounts of idle facility expenses, freight, handling costs and spoilage. Under paragraph 5 of ARB No. 43, such items might be considered to be so abnormal, under certain circumstances, as to require treatment as current period charges. SFAS No. 151 eliminates the criterion of so abnormal and requires that those items be recognized as current period charges. The statement also requires allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. This statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005, although earlier application is permitted for fiscal years beginning after the issuance date of the statement. Retroactive application is not permitted. Management is analyzing the requirements of SFAS No. 151 and believes that its adoption will not have any significant impact on the financial position, results of operations or cash flows of the Company.
The FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB No. 29 in December 2004. The statement amends Opinion 29 by eliminating the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. SFAS No. 153 provides that a nonmonetary exchange has commercial substance if future cash flows of the entity are expected to change significantly as a result of the exchange. The statement is
effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges occurring in fiscal periods beginning after the date of the issuance of the statement. Retroactive application is not permitted. Management is analyzing the requirements of SFAS No. 151 and believes that its adoption will not have any significant impact on the financial position, results of operations or cash flows of the Company.
FASB Staff Position (FSP) No. 109-2, Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004, was issued in December 2004. This FSP provides guidance on accounting for special reductions in taxes included in the American Jobs Creation Act of 2004. In particular, the Act allows a one-time decrease in U.S. Federal taxes on repatriated foreign earnings. FSP No. 109-2 clarifies that a companys consideration of the Act does not overrule their prior contention that the foreign earnings were permanently reinvested. Also, this FSP indicates that companies should provide tax expense when a decision is made to repatriate some or all foreign earnings, and provide disclosure about the possible range of repatriation if the analysis is not yet complete. We repatriated $86.5 million through a Canadian dividend distribution in 2004 and provided approximately $0.8 million of current income tax expense in 2004.
In September 2004, the SEC issued Staff Accounting Bulletin (SAB) No. 106. This pronouncement requires companies that use the full cost method of accounting for oil and gas producing activities to include an estimate of future asset retirement costs to be incurred as a result of future development activities on proved reserves in their calculation of depreciation, depletion and amortization. It also requires full cost companies to exclude any cash outflows associated with settling asset retirement obligations from their full cost ceiling test calculation. In addition, it requires specific disclosures regarding the impact of asset retirement obligations on oil and gas producing activities, ceiling test calculations and depreciation, depletion and amortization calculations. We will adopt the provisions of this pronouncement in the first quarter of 2005. We believe the adoption of SAB No. 106 will have no immediate effect on our consolidated financial statements.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
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.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
MANAGEMENTS STATEMENT OF RESPONSIBILITIES
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, 2004 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, 2004, 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
March 16, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Quicksilver Resources Inc.
Fort Worth, Texas
We have audited the accompanying consolidated balance sheets of Quicksilver Resources Inc. and subsidiaries (the Company) as of December 31, 2004 and 2003 and the related consolidated statements of income, comprehensive income, stockholders equity and cash flows for each of the three years in the period ended December 31, 2004. 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 statements 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 Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standard No. 143, Accounting for Asset Retirement Obligations.
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, 2004, based on the criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2005 expressed an unqualified opinion on managements assessment of the effectiveness of the Companys internal control over financial reporting.
/s/ Deloitte & Touche LLP
Fort Worth, Texas
March 16, 2005
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2004 AND 2003
In thousands, except for share data
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
In thousands, except for per share data
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
In thousands, except for share and per share data