QUICKSILVER RESOURCES INC - 10-K Annual Report

Indicate by check mark whether the registrant is an accelerated filer (as defined in rule 12b-2 of the Act). Yes x No ¨

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 registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Documents incorporated by reference: Proxy statement of the registrant relating to the annual meeting of stockholders to be held on May 20, 2003 which is incorporated into Part III of this Form 10-K.

As of June 28, 2002, the aggregate market value of the voting stock held by non-affiliates of Quicksilver Resources Inc. was approximately $248,323,217 based on the New York Stock Exchange composite trading closing price of $25.85 on June 28, 2002, and using the definition of beneficial ownership contained in Rule 16a-1(a) (2) promulgated pursuant to the Securities Exchange Act of 1934.

As of March 3, 2003, 21,114,728 shares of common stock of Quicksilver Resources Inc. were outstanding.

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.

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. Mercury Exploration Company, 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. We became a public company in 1999 through a merger with MSR Exploration Ltd. The Darden family, including Mercury and another entity controlled by the Dardens, still retains a significant ownership position in us, with approximately 46.7% beneficial ownership as of December 31, 2002. Thomas Darden, Glenn Darden and Anne Darden Self serve on our Board of Directors along with five 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, the Rocky Mountains and, more recently, the Canadian province of Alberta. At December 31, 2002, we had estimated proved reserves of 801 Bcfe. Approximately 86% of our reserves were natural gas, 81% were classified as proved developed and we operated approximately 70% of our reserves. Approximately 82% of our estimated proved reserves are located in Michigan and are characterized by long reserve lives and predictable well production profiles, with additional reserve and production enhancement opportunities. We recently began to focus on the exploration and development of coal bed methane reserves in Alberta, Canada. We believe that much of our future growth will be through exploration and development of our interests in these Canadian coal bed methane projects.

We intend to maintain an active capital spending program that will be focused primarily on the continued development and exploitation of our properties in Michigan and Indiana, as well as development and exploratory spending in support of our coal bed methane operations in Canada. For 2003, we have established a company-wide capital budget of $116 million, which includes approximately $34 million for possible leasehold acquisitions and new projects. Approximately $22 million will be allocated for compression and gathering systems. In geographic terms, we anticipate that 65% of the total capital budget will be allocated to our United States properties and 35% will be allocated to our Canadian operations.

The following table presents information regarding our primary areas of operation as of December 31, 2002:

Several important transactions are expected to provide, or have provided, the basis for our growth. On December 2, 2002, we purchased from Enogex Exploration Corporation its interests in natural gas properties located in Michigan, most of which we have operated and continue to operate. We acquired approximately 64.2 Bcfe of estimated proved reserves for approximately $32.0 million ($29.1 million after estimated closing adjustments). The purchased interests added approximately 8.4 MMcfd of natural gas production to our current production. We financed the acquisition with available cash and existing credit facilities.

Our wholly owned subsidiary, MGV Energy Inc., is our base of operations in Canada. Shortly after we completed our acquisition of MGV in 2000, we entered into a joint venture with EnCana Corporation to explore for coal bed methane (“CBM”) reserves on an area of over three million acres of land. Through year-end 2002, 175 CBM wells were successfully drilled by the joint venture in Southern Alberta.

In January 2003, we entered into an asset rationalization agreement with EnCana to divide the assets and rights held by the joint venture and to pursue independent operations. As a result of the agreement, we hold an interest or an option to drill and earn in approximately 667,000 acres of Alberta land where we are conducting a variety of CBM projects. Our first CBM development project, in the Gayford area of the West Palliser block, is producing approximately 3.0 MMcfd into sales lines from 23 net wells. Negligible water volumes have been seen in the Gayford area, precluding the need for water handling facilities. We also have the ability to connect into existing infrastructure and the Canadian pipeline system to assure the control and priority of natural gas sales. As of December 31, 2002, we have 36.6 Bcf of proved reserves from our CBM projects in addition to 17 Bcf of proved reserves from our other Canadian natural gas interests.

Our business strategy is designed to successfully 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 and compression to minimize producing pressures. 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 twelve 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 coal bed methane and Indiana New Albany 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 low-risk development drilling. From 2000 to 2002, our all-sources finding cost was $0.52 per Mcfe computed by dividing capital expenditures, less 2002 unevaluated expenditures, by net reserve additions for the periods 2000 to 2002. 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. In late 2001 and early 2002 we undertook a full review of our Michigan properties which contributed to a reduction in production expenses from $1.31 per Mcfe in 2001 to $1.08 per Mcfe for 2002.

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 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, such as the Enogex acquisition, producing additional economies of scale.

Management of Commodity Price Risk. We are focused on growing our oil and gas operations while minimizing the effect of commodity price swings on net income and cash flow from operations. To help ensure a level of predictability in the prices received for our natural gas and crude oil production and, therefore, the resulting cash flow, we have entered into natural gas sales contracts with price floors and natural gas and crude oil financial hedges that cover approximately 73% and 87% of our daily natural gas and crude oil production, respectively, or 73% of our total daily production for the fourth quarter of 2002. The commodity risk management strategy helps to ensure a predictable base level of cash flow, which allows us to execute our drilling and exploitation programs, meet debt service requirements and pursue acquisition opportunities despite price fluctuations.

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 may allocate approximately 10% of future capital expenditures to target high potential projects with defined financial risk. In particular, we anticipate pursuing leasehold acquisitions and joint venture opportunities that will provide us with additional unconventional gas projects, including fractured shales, coal beds and tight sands, to which our technical and operational expertise is well suited.

The natural gas produced from our domestic properties is marketed for us by Cinnabar Energy Services & Trading, LLC, our wholly-owned subsidiary, under Quicksilver’s existing long-term sales contracts and short-term wholesale spot market sales. Crude oil production is sold at local prices to the principal purchasers of crude oil in the respective areas of operations. Cinnabar also buys natural gas from and provides marketing services for third party producers. Of the total natural gas volumes marketed by Cinnabar, less than one-third is attributable to third party producers and less than 11% is attributable to gas produced from leases that we do not operate. Cinnabar does not engage in any form of price speculation. It seeks gas sales contracts only for volumes of natural gas it actually controls at the time.

Natural gas and crude oil is sold to creditworthy counterparties, such as utilities, major oil and gas companies or their affiliates, industrial customers, large trading companies or energy marketing companies, refineries and other users of petroleum products. Cinnabar is not confined to or dependent upon one purchaser or a small group of purchasers. Accordingly, the loss of a single purchaser in areas in which Cinnabar sells natural gas would not materially affect our product values. During 2002, our four largest purchasers accounted for approximately 13.8%, 12.9%, 10.3% and 10.2%, respectively, of our total consolidated natural gas and crude oil sales.

We encounter substantial competition in acquiring oil and gas leases and properties, marketing natural gas and crude oil, securing personnel and conducting our drilling and field operations. Many competitors have financial and other resources, which substantially exceed ours. The 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 have been financed primarily through debt 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 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 federal, state 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 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 operations and financial position, as well as the industry in general. 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. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as on the industry in general. Compliance with environmental requirements generally could have a materially adverse effect upon our capital expenditures, earnings or competitive position. 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”), as amended, 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 abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of 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 3, 2003, we had 243 full time employees and 4 part time employees, including officers.

The following information is provided with respect to our executive officers and other officers who make significant contributions to our business.

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.

D. WAYNE BLAIR is a Certified Public Accountant with over 20 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, he was the Controller for Mercury.

ROBERT N. WAGNER was named Vice President-Reserves Group December 2002. He had served as our Vice President-Engineering since July 1999. From January 1999 to July 1999, he was the Company’s 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, Mr. Wagner 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.

JOHN C. CIRONE was named as our Vice President and General Counsel July 1, 2002. He graduated from St. Louis University School of Law in 1974 and was employed by Union Pacific Resources Company 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.

JOHN B. GREMILLION, JR. has served as our Vice President of Investor Relations since November 2001. From June 2000 to November 2001, Mr. Gremillion held the position of Director of Investor Relations. He is a Certified Public Accountant with over 30 years experience in public and industry accounting. He was with Arthur Andersen LLP and Dresser Industries, Inc. for 12 years before joining Union Pacific Resources in 1981. At Union Pacific, he served in various tax positions and retired from Union Pacific Corporation in August 1998 as Vice President of Taxes. Mr. Gremillion graduated from Louisiana State University with a BBA in Accounting in 1968.

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. 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.

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, liquidity and results of operations. In evaluating us, you should consider carefully, among other things, the factors and the specific risks set forth below, and in documents we incorporate by reference. This annual report contains forward-looking statements that involve risks and uncertainties.

Because we have a limited operating history, 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.

Although our predecessors operated for years in the oil and gas industry prior to our formation, we began operations in 1998, and have a limited operating history in our current form upon which you may base your evaluation of our performance. As a result of our recent formation and our brief operating history, the operating results from the properties contributed by Mercury Exploration Company and others to us when we were formed may not indicate what our future results will be. 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 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 Management’s 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 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, 2002, approximately 19% 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 referred to in this annual report is the current market value of our estimated natural gas and crude oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by natural gas and crude oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of natural gas and crude oil properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with us or the oil and gas industry in general will affect the accuracy of the 10% discount factor.

Approximately 53% of our 2002 production was from the Antrim Shale formation in Michigan. An additional 34% was also located in Michigan. Because of this geographic concentration, 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 level was significantly reduced or limited below the amounts for which we have entered into contractual deliveries, we would be required to purchase natural gas at market prices to fulfill our obligation under the sales 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.

Through our wholly owned Canadian subsidiary, MGV Energy Inc., we have undertaken exploration activities and have begun independent development and operation of properties we now own as a result of an asset rationalization agreement with EnCana in January 2003. We estimate our proved coal bed methane reserves to be 36.6 Bcf. We also have entered into joint ventures with several companies to explore for and develop additional coal bed methane reserves on lands in southern Alberta. We share exploratory and evaluation costs with our joint venture partners and expect to accelerate our scheduled activities, expand into other areas and increase our capital expenditures. Capital expenditures relating to our Canadian operations are budgeted to be approximately $40 million in 2003, constituting approximately 35% of our total 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.

Our CBM projects are still in their early stages and further pilot work and evaluation will be necessary to enable us to determine the appropriate pace of development and timing of capital expenditures. While initial test results indicate that net recoverable reserves on CBM lands could be substantial, we can offer you no assurance that development will occur as scheduled or that actual results will be in accordance with estimates.

Other risks of our operations in Canada include, among other things, increases in taxes and governmental royalties, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations. Laws and policies of the United States affecting foreign trade and taxation may also adversely affect our Canadian operations.

We have experienced and expect to continue to experience substantial capital expenditure and working capital needs, particularly as a result of our property acquisition and drilling 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, 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, pipelines and trucking or terminal facilities.

Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions all 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. 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. In addition, pollution and environmental risks generally are not fully insurable.

We may be unable to make additional acquisitions of producing properties or successfully integrate them into our operations.

Our growth in recent years has been due in significant part 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 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, Montana, Wyoming 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 acquisitions of producing properties where we can utilize our experience as a low-cost operator and use available cash flows to continue to exploit our existing properties. We cannot assure you, however, that our planned 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.

Other companies operate properties that include approximately 30% 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:

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 oil and gas 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 oil and gas 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.

As of December 31, 2002 our long-term debt was $248.5 million including $192.0 million outstanding under our bank credit facility, $53.0 million outstanding under our subordinated notes, $2.6 million of other debt and a $0.9 million deferred gain from the settlement of an interest rate hedge. We had $57.1 million of available borrowing capacity under our bank credit facility. The borrowing base limitation on our credit facility is periodically redetermined. Scheduled redeterminations occur on May 1 and November 1 of each year. Our borrowing base is impacted by, among other factors, 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 possibly require the repayment of a portion of our current bank borrowings.

Our level of debt affects our operations in several important ways, including the following:

In addition, we may significantly alter our capitalization in order to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of debt. A higher level of debt increases the risk that we may default on our debt obligations. Our ability to meet debt obligations and to reduce our level of debt depends on our future performance. General economic conditions and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control.

If we are unable to repay our debt as required out of cash on hand, we could attempt to refinance the debt or repay the debt with the proceeds of an equity offering. We cannot assure you that we will be able to generate sufficient cash flow to pay the principal or interest on our debt or that future borrowing or equity financing will be available to pay or refinance the debt. The terms of our debt may also prohibit us from taking these actions. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions and our market value and operations performance at the time of the offering or other financing. We cannot assure you that any offering or refinancing can be successfully completed. 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.

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 2002 for the sale of approximately 37% 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.

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 month’s 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.

Oil and gas operations are subject to various 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 oil and gas 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 oil and gas 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.

Internal Revenue Code Section 29 income tax credits expired at the end of 2002. Unless new legislation extends the credits, our income will be lower in 2003. During 2002, 2001 and 2000, we recorded revenue of $5.1 million, $10.9 million and $8.3 million, respectively, from Section 29 credits.

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 Exploration Company and Quicksilver Energy, L.C., companies primarily owned by the members of the Darden family, beneficially own on the date of this annual report approximately 46.7% 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 21,092,945 shares of our common stock outstanding on the date of this annual report, including 227,421 shares issuable upon exchange of exchangeable shares issued by MGV Energy Inc., one of our subsidiaries. Approximately 10,807,000 of these shares are freely tradable without substantial restriction or the requirement of future registration under the Securities Act of 1933. In addition, as of December 31, 2002 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 restated certificate of incorporation, our bylaws and our stockholder rights plan contain provisions that could discourage an acquisition or change of control without our board of directors’ approval.

Our restated certificate of incorporation and our 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 SEC’s web site at http://www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. You may obtain information on the operation of the SEC’s 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.

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. It also provides opportunities for long-term contracts at favorable terms with end users who value such supply arrangements.

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. While subsurface fracturing can increase reserves and production attributable to any particular well, the over 7,400 wells drilled in the trend and the approximately 763 wells we, including Mercury prior to our formation, have drilled suggest typical per well reserves of 600 MMcf to 800 MMcf and 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 production level of 150 Mcf to 200 Mcf per day in six to 12 months, remaining at these levels for one to two years, then declining at 8% to 10% per year thereafter. The total cost to drill and complete an Antrim well is approximately $175,000, including all acreage, production facilities and flow lines, and 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, 2002, we owned working interests in 2,828 Antrim wells and operated 49% of those wells. Since 1996, we, including Mercury prior to our formation, have drilled 398 Antrim wells and successfully completed 393 for a success rate of 99%. We have 116 net identified Antrim drilling locations currently classified as proved undeveloped locations. In 2002, we drilled 54 (net) Antrim wells, of which 53 were successfully completed. For 2003, we have budgeted for the drilling of 56 (net) Antrim wells at a cost of approximately $12.4 million.

Our Prairie du Chien (“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. The average depths of these wells range from 7,000 feet to 12,000 feet.

Our PdC production is well established, and four development wells have been drilled in recent years to increase production from existing fields. 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. We fracture stimulated 5 PdC wells in 2002 with an average net incremental rate increase of 1.3 Mcfd per well.

Our Richfield/Detroit River wells are located in Kalkaska and Crawford counties in the Garfield and Beaver Creek fields. The Garfield Richfield has seven wells producing under primary solution gas drive. 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 98 producing wells and 59 water injection wells. The Richfield zone consists of seven dolomite reservoirs spread over a 200-foot interval.

The Detroit River Zone III (“DRZ3”) at Beaver Creek has been the focus of one of our development programs in 2002. Lying 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 began a Detroit River development program in the third quarter of 2002. As of December 31, 2002 18 wells were producing. We are completing a processing plant and connecting pipeline facilities and commenced the sale of oil in late 2002. Natural gas sales and NGL processing are expected to commence in April 2003.

Our Niagaran wells produce from numerous Silurian-age Niagaran (dolomite/limestone) 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, 2002, we had 65 gross (29.8 net) Niagaran wells producing approximately 4.4 MMcfed.

Through two acquisitions in 2000, we acquired a 100% working interest in 33 New Albany Shale producing wells. With these acquisitions, we also purchased the eight-mile 12-inch GTG gas pipeline that runs from southern Indiana to northern Kentucky. The New Albany Shale is similar to the Michigan Antrim, as it has to be dewatered in order to produce desorbed methane gas. Typical reserves per well are estimated to be approximately 320 MMcf.

Since acquisition of these wells, we have drilled an additional 30 wells. Average daily production in 2002 from all of our New Albany Shale wells was 2.0 MMcfd. In 2003, we will commence construction on a pipeline extension that will connect to the Texas Gas Pipeline. In 2003, we anticipate drilling approximately 85 wells in the New Albany Shale and expect to complete the pipeline extension along with a new compression facility.

We began to focus on the potential of Canadian coal bed methane (“CBM”) through MGV, our Canadian subsidiary in 2000. In late 2000, we entered into a joint venture with EnCana to explore for and develop CBM reserves initially in the West Palliser block in 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 to divide the assets and rights held by the joint venture and to pursue independent operations. As a result of the agreement, we have proved CBM reserves of 36.6 Bcf as of December 31, 2002 and immediate drilling rights on approximately 360,000 net acres in all our present Canadian CBM projects. Over one-half of the 360,000 net acres include additional natural gas rights from surface to just below the deepest coal seam target. Furthermore, MGV has been assigned all rights under three CBM joint ventures. We will continue to be partners with EnCana in three additional CBM joint ventures. We operate 94% of the CBM properties that we have an interest in.

Our Gayford and Beiseker development areas include 33 net wells drilled through 2002. Commercial production began in the Gayford area from 23 of the 33 wells in January 2003 with average flow rates of 140 Mcfd per well with negligible water. Approximately three MMcfd is being delivered into sales lines from these wells. Our plans for all Canadian CBM projects include the drilling of 76 exploratory/pilot wells and 102 development wells, including 75 net development wells in the Gayford and Beiseker areas in 2003. The average cost for these development wells, including facilities, is approximately $175,000 per well. Our CBM capital budget for 2003 will be approximately $40 million and includes these wells and additional land and facilities acquisitions.

MGV also owns interests in other natural gas properties located in southern Alberta. At the end of 2002, MGV held interests in 441 wells operated by others and 93 wells that are 100% owned and operated by MGV. All of these properties are located in southern Alberta.

Our Canadian proved reserves at December 31, 2002 were estimated to be 53.6 Bcf, including 36.6 Bcf of CBM reserves. Our average daily production in Canada for 2002 was 2.6 MMcfd.

Our Rocky Mountain properties are located in Montana and Wyoming, and production, which is primarily crude oil, is from well-established producing formations at depths ranging from 1,000 feet to 17,000 feet. These properties typically have multiple producing zones, some of which include the Phosphoria at 750 feet to 1,000 feet, the Tensleep at 1,000 feet to 3,000 feet and the Muddy/Mowry at 8,400 feet to 9,000 feet. Our Rocky Mountain properties possess significant development drilling, secondary recovery and other exploitation opportunities. As of December 31, 2002, our Rocky Mountain proved reserves were 10.9 MMbbls of crude oil and 3.1 Bcfe of natural gas and NGLs for total equivalent reserves of 68.5 Bcfe. In 2002, our daily production averaged 8.2 MMcfed.

The following reserve quantity and future net cash flow information concerns our proved reserves that are primarily located in the United States. Holditch-Reservoir Technologies Consulting Services, independent petroleum engineers and a subsidiary of Schlumberger, and Netherland, Sewell & Associates, Inc. prepared our reserve estimates. The determination of oil and gas reserves is based on estimates that are highly complex and interpretive. The estimates are subject to continuing change, as additional information becomes available. Under the guidelines set forth by the SEC, the calculation of reserves is performed using year-end prices held constant, unless a contract provides otherwise, and is based on a 10% discount rate. Future production and development costs are based on year-end costs and include production taxes. This standardized measure of discounted future net cash flows is not necessarily representative of the market value of our properties.

The reserve data set forth in this document represents only estimates. 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, the estimated future net revenues from such proved reserves and the standardized measure of discounted future net cash flows attributable to them at December 31, 2002, 2001 and 2000. At year-end 2002, 2001 and 2000, Canadian reserves were 53.6 Bcf, 16.5 Bcf and 16.2 Bcf of natural gas, respectively, with discounted future net cash flows of $54.5 million, $9.1 million and $50.9 million, respectively.

The following table sets forth certain information regarding the production and sales volumes and average sales prices and production costs associated with our producing properties for the periods indicated.

The following table sets forth certain information regarding the approximate costs incurred by us in our development and exploration activities and purchase of natural gas and crude oil in place (in thousands):

The following table summarizes productive oil and gas wells attributable to our direct interests as of December 31, 2002.

The following table sets forth the developed and undeveloped leasehold acreage held directly by us. Developed acres are defined as acreage spaced or able to be assigned to productive wells. 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. We hold undeveloped acreage in Michigan, Montana, Indiana and Wyoming as well as the Canadian province of Alberta.

The following table sets forth the number of wells drilled and attributable to our direct interests.

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. Due to administrative oversight an answer was not timely filed and a default was entered against us in December 2001. On October 24, 2002, the trial court granted Terra’s motion to set aside the default. The court heard arguments on class certification on November 8, 2002; on December 6, 2002 the court issued a memorandum opinion granting class certification in part and denying it in part. The court stated that those portions of the royalty owner’s complaint against us alleging that we deducted excessive post production costs from royalty payments should not be certified as class action. The court certified the remainder of the complaint for class action status. On December 20, 2002 we filed a motion for clarification and reconsideration of the court’s order. That motion was denied on March 9, 2003. Based on information currently available to us, we believe that the final resolution of this matter will not have a material effect on our operations, equity or cash flows.

There were no matters submitted to a stockholder vote during the fourth quarter of 2002.

ITEM 5. Market for Registrant’s Common Equity and Related Stockholder Matters

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 March 3, 2003, there were approximately 524 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 primary credit facility restricts payments of dividends on our common stock.

The following table sets forth information related to our equity compensation plan as of December 31, 2002.

The following tables set forth, as of the dates and for the periods indicated, selected financial information for us. Our financial information is taken from our audited consolidated financial statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial

Condition and Results of Operations” and our consolidated financial statements and notes thereto contained in this document. The following information is not necessarily indicative of our future results.

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Certain statements contained in this annual report and other materials we file with the Securities and Exchange Commission, as well as information included in oral statements or other written statements made or to be made by us, other than statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements may relate to a variety of matters not currently ascertainable, such as future capital expenditures, drilling activity, acquisitions and dispositions, development or exploratory activities, cost savings efforts, production activities and volumes, hydrocarbon reserves, hydrocarbon prices, hedging activities and the results thereof, financing plans, liquidity, regulatory matters, competition and our ability to realize efficiencies related to certain transactions or organizational changes. Forward-looking statements generally are accompanied by words such as “anticipate,” “believe,” “budgeted,” “expect,” “intend,” “plan,” “project,” “potential,” or similar statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include:

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this section. The following discussion and analysis should be read in conjunction with “Selected Financial Data” and the consolidated financial statements and notes thereto, appearing elsewhere in this annual report.

Our financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. The reported financial results and disclosures were determined using significant accounting policies, practices and estimates described below. We believe the reported financial results are reliable and that the ultimate actual results will not differ significantly from those reported.

We employ the full cost method of accounting for our oil and gas production assets. 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. 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; (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.

The ceiling test is affected by a decrease in net cash flow from reserves due to higher operating or finding 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, 2002, the capitalized cost, inclusive of future development costs, for U.S. and Canadian reserves was $0.66 per Mcfe and $0.62 per Mcfe, respectively. If the cost center ceiling falls below the capitalized cost for the cost center, we would be required to report an impairment of the cost center’s oil and gas assets at the reporting date.

Revenues are recognized when title to the product transfers to purchasers. We follow the “sales method” of accounting for revenue for natural gas and crude oil production, so that we recognize sales revenue on all production sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. Ultimate revenues from the sales of natural gas and crude oil production is not known with certainty until up to three months after production and title transfer occur. Current revenues are accrued based on our expectation of actual deliveries and actual prices received.

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. Every derivative instrument is recorded on our balance sheet as either an asset or liability 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. The ineffective portion of hedges is recognized currently in earnings.

Accounting and disclosure rules relating to derivative instruments accounted for as cash flow hedges require us to increase our reported stockholders’ equity when future natural gas prices are forecasted to decrease relative to the strike price in our hedges, and to decrease our reported stockholders’ equity when future natural gas and crude oil prices increase relative to the strike price in our hedges. The change in reported stockholders’ equity relates only to our hedged production. Future declines in natural gas and crude oil prices are not beneficial to us since less than 100% of our production is hedged and even though hedge accounting rules require us to increase our book value.

Included in our net deferred tax liability are $12.3 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.

Internal Revenue Code Section 29 income tax credits expired at the end of 2002. During 2002, 2001 and 2000, we recorded revenue of $5.1 million, $10.9 million and $8.3 million, respectively, from Section 29 credits.

We have no off-balance sheet arrangements, special purpose entities, financing partnerships or guarantees. The companies that we have an equity investment in do not have any significant debts.

Net income of $13.8 million ($0.68 per diluted share) was recorded for 2002, a decrease of 28% over 2001 net income of $19.3 million ($1.00 per diluted share). The decrease was largely the result of an 8% drop in 2002 realized prices. The sales price decreases were only partially offset by a 20% decrease in production expense for 2002.

Total revenues for 2002 were $122.0 million, a $20.0 million decrease from the $142.0 million reported in 2001. Realized sales prices decreased 8%. This decrease, along with a decrease in crude oil volumes, decreased production revenue $13.0 million from the 2001 period. Other revenue was $6.9 million lower primarily due to a decrease in deferred revenue recognition from the sale of Section 29 tax credits and the one-time receipt of revenue associated with a bankruptcy settlement in 2001.

Our sales volumes, revenues and average prices for the years ended December 31, 2002 and 2001 are as follows:

Natural gas sales decreased $8.9 million from 2001 to $90.3 million for 2002. The $0.28 per Mcf decrease in average natural gas prices accounted for the entire revenue decrease. Sales volumes for 2002 were slightly higher than 2001 sales volumes. In 2001, sales volumes of 540,000 Mcf were attributable to prior year production payouts identified during 2001. These 2001 payout volumes were offset by approximately 696,000 Mcf of additional 2002 net sales volumes. Significant production increases in Michigan included 646,000 Mcf from Sturgeon Valley Ranch where 15 wells were drilled in late 2001 and at Garfield Field where PdC wells were fracture stimulated between February and June of 2002, resulting in production increases of 306,000 Mcf. Drilling in Indiana resulted in additional production of 132,000 Mcf. Production in 2002 also included 252,000 Mcf from the interests purchased from Enogex Exploration Corporation in December 2002. These increases were partially offset by natural production declines on existing production. In 2002, we drilled 104 net productive wells excluding Canadian wells. We successfully worked over or recompleted a total of 20 net wells during 2002.

Oil sales were $19.7 million for 2002 compared to $22.3 million in 2001. Sales volumes for 2002 decreased 154,000 barrels from 2001 total crude oil production, decreasing oil sales $3.4 million. Higher realized oil prices offset the sales volume decline by $760,000 over the prior year. We sold oil properties located in Wyoming and Texas in June and July of 2002. These property sales resulted in a decrease of approximately 21,000 barrels as compared to 2001.

NGL sales for 2002 decreased $1.6 million to $2.3 million. The decrease was primarily the result of lower NGL prices for 2002.

Other revenue in 2002 consisted of revenue associated with Section 29 tax credits and with marketing, transportation and processing of natural gas. Revenue derived from Section 29 tax credit monetizations decreased $5.8 million from 2001. Deferred revenue recognition associated with the 2000 tax credit monetization ceased during 2002. Natural gas marketing, transportation and processing revenue for 2002 was $3.0 million as compared to $3.6 million in 2001. The decrease was due primarily to lower gas marketing margins and less marketed volumes in 2002. Other revenue in 2002 also decreased due to the one-time receipt of $580,000 of revenue recognized in 2001 as a result of a bankruptcy settlement.

Operating expenses were $81.5 million in 2002 compared to $89.7 million for 2001. The decrease was the result of lower sales volumes, including the absence of 2001 payout volumes, and cost reduction measures we instituted early in 2002 resulting in a decrease in lease operating expense and production overhead of $4.0 million. Additional expense recoveries of $3.5 million were the result of review of various operating agreements under which we operate both oil and gas properties and other partnerships. The review resulted in an increase of expenses recovered from the oil and gas properties and partnerships. In 2001, we recovered a $1.1 million provision for doubtful accounts associated with the receipt of a bankruptcy settlement.

Oil and gas production costs for 2002 were $42.2 million compared to 2001 expense of $52.7 million. Production costs, excluding production taxes and expense recoveries, were $4.0 million lower in 2002. Lower 2002 production volumes decreased production costs $1.3 million. In early 2002, we instituted cost reduction measures that resulted in a $2.7 million decrease in production expenses. Production taxes were $2.3 million lower as a result of lower sales volumes and lower average natural gas and crude oil prices in 2002.

Additional expense recoveries of $4.3 million were recorded in 2002. A review of the operating agreements under which we operate both oil and gas properties and partnerships resulted in an additional recovery of $3.5 million of expenses. Beginning in the fourth quarter of 2002, we brought the compressor maintenance function in-house on our operated compression facilities. Additional 2002 expense recoveries associated with compressor maintenance were $790,000.

Depletion increased $790,000 to $27.0 million in 2002. A higher depletion rate increased 2002 depletion $1.5 million, but this was partially offset by a $690,000 decrease due to lower production volumes. Depreciation increased $725,000 to $3.2 million in 2002 primarily as a result of gas compression assets added in 2002.

General and administrative expenses were $7.6 million for 2002 and comparable to 2001 general and administrative expenses. Legal expenses increased $450,000 primarily as a result of legal fees incurred for defense of a royalty lawsuit filed against us in late 2001. The increase was offset by decreases in stock exchange fees, board of directors’ fees, professional engineering fees and several other expense categories. Stock exchange fees for 2001 included $136,000 for our initial listing on the New York Stock Exchange. No expense for directors’ fees was recognized for 2002, as the directors were compensated with stock options accounted for under APB Opinion No. 25 and FASB Interpretation No. 44.

Income from equity affiliates decreased $925,000 from the prior year due primarily to losses of $796,000 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 of $19.8 million in 2002 decreased $3.9 million from 2001. The decrease reflects a significant decrease in our effective interest rates partially offset by an increase in our average debt outstanding in 2002.

The income tax provision of $7.5 million was established using an effective U.S. federal tax rate of 35%. The 2002 current benefit of $262,000 consists of a refund of federal alternative minimum tax of $178,000 and a state income tax benefit of $139,000 partially offset by Canadian Large Corporation tax expense of $55,000. Income tax expenses decreased from the prior year as a result of lower 2002 pretax income as compared to 2001.

Net income of $19.3 million ($1.00 per diluted share) was recorded for 2001, an increase of 10% over 2000 net income of $17.6 million ($0.95 per diluted share). The increase was largely the result of a full year’s operating results from the properties acquired from CMS Energy Corporation in March of 2000 as compared to the three quarters of results reflected for 2000.

Total revenues for 2001 were $142.0 million, an increase of 20% from the $118.4 million reported in 2000. Additional volumes, resulting primarily from properties acquired from CMS, increased hydrocarbon sales revenue by $19.5 million over the 2000 period while an overall decrease in prices reduced revenue by $2.9 million.

Our sales volumes, revenues and average prices for the years ended December 31, 2001 and 2000 are as follows:

Gas sales of $99.2 million for 2001 were 22% higher than the $81.0 million for 2000 as gas volumes increased 23% to 32,689,000 Mcf in 2001. Additional gas sales volumes of 6,000,000 Mcf contributed $18.3 million of additional revenue over 2000. Higher gas volumes were primarily the result of approximately 3,994,000 Mcf in the first quarter from properties acquired from CMS and approximately 371,000 Mcf from Indiana properties acquired from Mercury Exploration Company and Dominion Reserves-Indiana, Inc. in the fourth quarter of 2000. Approximately 163,000 Mcf were added from the Bindloss area acquired in early 2001 by MGV. An additional 540,000 Mcf were attributable to prior year production payouts identified during 2001. Capital expenditures for drilling, recompletions and workovers in 2001 resulted in a 2,400,000 Mcf increase in sales volumes. These increases were offset by natural production declines on existing production. In 2001, we drilled 127 net productive wells excluding Canadian exploratory wells. Additionally, we successfully worked over or recompleted 86 net wells during 2001. Average prices were virtually unchanged from 2000.

Oil sales declined to $22.3 million for 2001 compared to $23.7 million in 2000. Average oil sales prices in 2001 were $21.03 per barrel compared to $22.87 per barrel in 2000. Lower prices decreased revenue $1.9 million over the prior year. Additional oil production contributed $504,000 of revenue as compared to 2000. Crude oil production increased 24,000 barrels from 2000 as a result of 58,000 barrels in the first quarter from CMS properties and 116,000 barrels from 2001 capital expenditures partially offset by production declines on existing production.

NGL sales for 2001 were essentially unchanged from 2000. Revenue of $3.9 million resulted from NGL production of 195,000 barrels as compared to $4.1 million in revenue from 160,000 barrels in 2000. Capital expenditures increased 2001 sales volumes by 47,000 barrels that were partially offset by production declines on existing production.

Other revenue in both 2001 and 2000 primarily consisted of revenue associated with Section 29 tax credits and revenue associated with marketing, transportation and processing of natural gas. Deferred revenue of $9.4 million was recognized in 2001 from the 2000 Section 29 tax credit monetization compared to $6.8 million in 2000. Revenue from prior Section 29 tax credit monetizations was $1.5 million in 2001, an increase of $68,000 over 2000. Natural gas marketing, transportation and processing revenue for 2001 was $5.1 million as compared to $1.0 million in 2000 due primarily to increased third party marketing activity in 2001 and inclusion of a full year’s results in 2001 for the operations acquired from Mercury effective July 1, 2000. During the year, $1.7 million was received from a customer in bankruptcy of which $580,000 was recorded in other revenue and $1.1 million was recorded as reversal of bad debt expense.

Operating expenses of $89.7 million in 2001 were 28% higher than the $69.8 million incurred in 2000. The increase was the result of additional volumes from acquisition properties, prior period payout expenses and a full year’s expenses associated with the marketing, transportation and processing operations acquired from Mercury in 2000. Also included is a recovery of a $1.1 million provision for doubtful accounts associated in with the 1999 bankruptcy of one of our natural gas purchasers.

Oil and gas production costs for 2001 were $52.7 million and 40% higher than the $37.6 million incurred in 2000. Increased sales volumes from 2000 acquisitions, prior year payouts and other production increases resulted in approximately $7.0 million of additional production expense. Higher levels of compressor maintenance and well workovers, increased well counts and additional field and production office personnel accounted for the remaining $7.8 million increase. Production taxes increased $1.2 million to $7.9 million in 2001 as a result of increased sales volumes partially offset by lower average sales prices for 2001.

Other operating costs of $1.7 million are associated with the marketing, transportation and processing operations acquired from Mercury. The increase of $1.1 million over 2000 reflects a full year’s activity for 2001.

Depletion increased to $26.2 million in 2001 from $23.0 million in 2000. Depletion increased $4.2 million as a result of increased sales volumes, partially offset by a $975,000 decrease due to a lower depletion rate that resulted from increased reserve volumes as compared to the prior year. Depreciation increased $910,000 to $2.5 million in 2001 primarily as a result of the gas processing and transportation assets acquired in the Mercury acquisition as well as gas compression facilities added in 2001.

General and administrative costs incurred during 2001 were $7.7 million and $412,000 higher than 2000. The increase was primarily the result of additional contract labor expense of $469,000 and additional stock exchange fees of approximately $124,000 relating to the our initial listing on the New York Stock Exchange, offset by reductions in various other categories.

Interest expense of $23.8 million in 2001 increased $1.6 million from 2000. The increase reflects an additional quarter of interest for debt incurred for the acquisition of the CMS properties partially offset by lower effective interest rates in 2001.

Other income increased $294,000 primarily as a result of additional interest income earned on invested operating cash balances.

The income tax provision of $10.8 million was established using an effective U.S. federal tax rate of 35%. The 2001 current portion of $463,000 consists of federal alternative minimum tax of $178,000 and Canadian and state income tax expense of $285,000. Income tax expense increased $687,000 as a result of additional pretax income in 2001 partially offset by a decrease in the 2001 effective tax rate.

Our primary sources of cash during 2002 were: cash provided by operations; the issuance of common stock in a public offering; the exercise of warrants and employee stock options; and proceeds from utilization of our credit facility. Primary cash outflows for the year were capital expenditures and the repayment of debt.

Internal Revenue Code Section 29 income tax credits expired at the end of 2002, and, unless new legislation extends the credits, this source of income will no longer be available to us. During 2002, 2001 and 2000, we recorded revenue of $5.1 million, $10.9 million and $8.3 million, respectively, from Section 29 credits. Of these amounts, $1.5 million, $1.5 million and $1.4 million represent cash revenue for 2002, 2001 and 2000, respectively.

Cash from operations of $44.0 million was $13.9 million less than 2001. Lower sales prices and volumes reduced operating cash by $13.0 million while lower production costs and interest expense offset the revenue reduction by $14.4 million. Unfavorable changes in working capital and the 2001 receipt of $1.7 million from the settlement of the bankruptcy of a former natural gas producer further reduced cash from operations in 2002 as compared to 2001.

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 77% and 41% of our 2002 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. Either of these events could have a material adverse effect on our cash flows.

Cash used in investing activities was $83.7 million for 2002, an increase of $16.4 million from 2001. Capital expenditures in 2002 were $21.6 million higher due primarily to the purchase of Michigan natural gas interests from Enogex in December for approximately $32.0 million ($29.1 million after estimated closing adjustments). Cash from equity affiliates and the sale of properties in Wyoming and Texas partially offset capital expenditures.

During 2002 we received $40.6 million from the issuance of common stock upon the exercise of warrants in the first quarter of 2002, completion of a November 2002 public offering and exercise of employee stock option exercises throughout the year. The $2.0 million of net proceeds from notes payable under our credit facility was offset by the payments made to reduce term debt and the costs associated with renewing our credit facility in May 2002.

Our credit facility is a three-year revolving facility that matures on May 15, 2005 and permits us to obtain revolving credit loans and to issue letters of credit for our account from time to time in an aggregate amount not to exceed the lessor of the borrowing base or $250 million. The current borrowing base is $250 million and is subject to semi-annual redetermination and certain other redeterminations based upon several factors. Scheduled redeterminations occur on May 1 and November 1 of each year. Our borrowing base is impacted by, among other factors, 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 possibly require the repayment of a portion of our current bank borrowings.

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)+1.875% or bank prime. Our interest rate was 3.665% from October 3, 2002 through January 2, 2003 on $177 million. 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. We currently are in compliance with all such restrictions. At December 31, 2002, we had $57.1 million available under the credit facility.

We also have $53 million of 14.75% Second Mortgage Notes outstanding at December 31, 2002. These subordinated notes were issued in March and April of 2000. Prepayments made on or after March 28, 2003 require a premium payment ranging from 3% to 6%. Quarterly interest payments to the note holders may be paid in kind with respect to all or any portion of interest in excess of 10% by issuing additional notes. The subordinated notes contain restrictive covenants, which, among other things, require maintenance of working capital, collateral coverage ratio and an earnings ratio before interest, taxes, depreciation and amortization and costs associated with seismic and geological services in connection and attributable to oil and gas exploration. We are currently in compliance with such restrictions. At December 31, 2002, a deferred gain of $0.9 million remains from the settlement of an interest rate hedge on July 15, 2002 associated with the subordinated notes. We received $1.0 million, which is being amortized through the original termination date of the hedge, March 30, 2009.

On March 12, 2003, the holders of the subordinated notes were notified that we intend to exercise our prepayment option for all of the subordinated notes outstanding. In addition to the principal and accrued interest, we will pay a premium of $3.2 million on June 27, 2003. We plan to finance the repayment with issuance of $50 million of term debt to be repaid over three and one half years at an interest rate of approximately 7.5%. The remaining $6.2 million of principal and premium is expected to be financed through the credit facility.

We believe that our capital resources are adequate to meet the requirements of our business. We anticipate our 2003 capital expenditure budget of approximately $116 million, including $34 million for possible leasehold acquisitions and new projects, will be funded by cash flow from operations, credit facility utilization and possible issuance of common stock under a shelf registration statement filing made in 2002. If capital resources are inadequate or unavailable, we may curtail our acquisition, development and exploration drilling and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.

Long-Term Debt—We had $192 million outstanding as of December 31, 2002 under our credit facility. The remaining long-term debt consists of subordinated notes of $53 million and various other notes of $3.6 million. See “Liquidity and Capital Resources” for further information regarding our planned refinancing of the subordinated notes in June 2003.

Operating Leases—We lease office buildings and other property under operating leases. $5.3 million of our operating lease obligations are with an affiliate of Mercury Exploration Company, which is owned by the Darden family.

Section 29 Property Settlement—We conveyed to a bank Section 29 tax credits from working interests in various Michigan properties in 1997 and 2000. As a result of the expiration of Internal Revenue Code Section 29 at December 31, 2002, we notified the bank of our intent to repurchase the properties in September 2002. We have estimated that the cost to reacquire the interests will not exceed $5.7 million.

Gas Purchase Obligation—Cinnabar Energy Services and Trading LLC, our wholly owned subsidiary, has a contract to purchase 8,000 MMbtu/month of natural gas at $4.05/MMbtu from November 2002 through October 2003. This obligation has been hedged.

Canadian Drilling Commitments—We have minimum drilling commitments under operating agreements with joint venture partners.

Standby Letters Of Credit—Our letters of credit have been issued due to federal and state regulatory requirements. The majority of these letters are against the credit facility. All letters have an annual renewal option.

The Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” which is effective for fiscal years beginning after June 15, 2002. This statement, effective in 2003, establishes accounting and reporting standards for the legal obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction or development and the normal operation of long-lived assets. It requires that the fair value of the liability for asset retirement obligations shall be recognized in the period in which it is incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost shall be capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost shall be allocated to expense using a systematic method over the asset’s useful life. Changes in the liability for the asset retirement obligation shall be recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows.

All asset retirement obligations and costs were identified and their fair values estimated as of the date the long-lived assets were placed into service. The asset retirement obligations’ fair values were then estimated as of January 1, 2003, the date of adoption of the statement. Our adoption of this accounting standard as of January 1, 2003 resulted in the recognition of $10.8 million of asset retirement costs and $13.1 million of asset retirement obligations. The cumulative-effect adjustment of $2.2 million includes $1.1 million for additional depletion and depreciation of the asset retirement costs, $2.3 million for accretion of the fair value of the asset retirement obligations and $1.2 million for deferred tax benefits. In 2003, we estimate the additional expense for depletion, depreciation and accretion to be $1.1 million before income taxes.

SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections” was issued in April 2002. The Statement rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt” and an amendment of that Statement, SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements.” As a result of the rescission of SFAS No 4, debt extinguishment will no longer be classified as extraordinary under APB No. 30, “Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.” We have adopted this statement.

The FASB also issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 supersedes EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FASB Statement No. 123.” The statement provides alternative methods of transition for voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. We will comply with the disclosure requirements in our interim financial statements for the year ending December 31, 2003.

The FASB issued FASB Interpretation No. (“FIN”) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” in November 2002. The FIN elaborates on the disclosures required by a guarantor in its financial statements under certain guarantees it has issued. It also clarifies, that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. FIN 46, “Consolidation of Variable Interest Entities” was issued in January 2003. FIN 46 addresses consolidation by business enterprises of variable interest entities. We have reviewed both Interpretations. Neither FIN has any effect on our financial statements.

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 swaps, futures and forward contracts; however, we have also limited future gains from favorable movements.

We enter into various contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas and crude oil production. These contracts have included physical sales contracts and derivatives including price ceilings and floors, no-cost collars and fixed price swaps. As of December 31, 2002, 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 28,100 Mcfd of our natural gas production was sold under these contracts during 2002. The remaining 6,900 Mcfd sold under these contracts were third-party volumes controlled by us. Approximately 38,100 Mcfd of our natural gas production is hedged using fixed price swap agreements at a weighted average price of $2.70 per Mcf. These agreements expire from April 2004 to April 2005. Additionally, we have hedged 500 Bbld of our crude oil production using a fixed price swap agreement and 1,500 Bbld of crude oil using crude oil collars. These agreements expire in September 2003 and December 2003, respectively. As a result of these various contracts, we benefit from significant predictability of our natural gas and crude oil revenues.

The following table summarizes our open financial derivative positions as of December 31, 2002 related to natural gas and crude oil production.

Utilization of our hedging programs may result in realization of natural gas and crude oil prices varying from market 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 program had not been in effect by $7.4 million in 2002, $22.1 million in 2001, and $22.5 million in 2000.

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 2004. Additional natural gas volumes of 16,500 Mcfd are committed at market price through September 2008. During 2002, approximately 5,400 Mcfd of our natural gas production was sold under these contracts. An additional 15,600 Mcfd sold under these contracts were third-party volumes controlled by us.

Based on the natural gas financial fixed price hedge positions, for each $1.00 per Mcf increase in the price of natural gas, our annualized revenue would increase by approximately $22.4 million of which $13.9 million would be reduced due to the existing hedges.

Cinnabar Energy Services & Trading, LLC, our wholly owned marketing company, also enters into various financial contracts to hedge its exposure to commodity price risk associated with future contractual natural gas sales and purchases of third party volumes. These contracts include either fixed and floating price sales or purchases from third parties. As a result of these firm sale and purchase commitments and associated financial price swaps, the hedge derivatives have qualified as fair value hedges. Marketing revenues were lower by $2.2 million in 2002 and $3.0 million in 2001 as a result of hedging activities. Hedge ineffectiveness resulted in

$26,000 of net losses and $48,000 of net gains recorded to other revenue for 2002 and 2001, respectively. The following table summarizes Cinnabar’s open financial derivative positions and hedged firm commitments as of December 31, 2002 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, 2002 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 the Company’s derivatives and commitments does not necessarily represent the value a third party would pay to assume our contract positions.

We manage our exposure associated with interest rates by entering into interest rate swaps. In October 2002, we closed our fixed-rate interest swaps related to $75 million of our variable-rate debt and entered into a new fixed-rate swap. The new fixed-rate swap converts the debt’s floating LIBOR base to a 3.74% fixed-rate through March 31, 2005. The realized loss of $1.9 million on the closed swaps is being reclassified out of other comprehensive income through March 31, 2003, the original maturity of the closed swaps.

In July 2002, we closed our variable-rate interest swap covering the $53 million of our fixed-rate subordinated notes. The swap converted the debt’s 14.75% fixed-rate debt to a floating three-month LIBOR base. We received a cash settlement of $1.0 million. The settlement was deferred and is being recognized as a reduction of interest expense through March 30, 2009, the original life of the swap.

Interest expense for the years ended December 31, 2002 and 2001 was $2.6 million and $1.3 million higher, respectively, as a result of the interest rate swaps. If interest rates on our unhedged variable debt of $117 million increase or decrease by one percentage point, our annual pretax income will decrease or increase by $1.2 million.

Credit risk is the risk of loss as a result of non-performance by counterparties of their contractual obligations. We sell a portion our natural gas production directly under long-term natural gas contracts and the remainder of our natural gas and crude oil is sold through Cinnabar. All such natural gas and crude oil is sold to creditworthy counterparties, such as utilities, major oil and gas companies or their affiliates, industrial customers, large trading companies or 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 are required according to Company policy. 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. In fact, credit ratings of the parent companies of the two counterparties to our long-term gas contracts were recently downgraded by Standard & Poors and Moody’s. Please see Item 1. Risk Factors.

Performance risk results when a financial counterparty fails to fulfill its contractual obligations such as commodity pricing or volume commitments. Typically, such risk obligations are defined within the trading agreements. We manage performance risk through management of credit risk. Each customer and/or counterparty is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter.

Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. While cross-currency transactions are immaterial, the result in a ten percent change in the Canadian-U.S. exchange rate would increase or decrease equity by approximately $3.0 million at December 31, 2002.

The integrity and consistency of the consolidated financial statements of Quicksilver Resources Inc. (the “Company”), which were prepared in accordance with accounting principles generally accepted in the United States of America, are the responsibility of management and properly include some amounts that are based upon estimates and judgments.

The Company maintains a system of internal accounting controls to provide reasonable assurance, at appropriate cost, that the Company’s assets are protected and transactions are properly recorded. Additionally, the integrity of the financial accounting system is based on careful selection and training of qualified personnel, organizational arrangements which provide for appropriate division of responsibilities and communication of established written policies and procedures.

Deloitte & Touche LLP, independent auditors, has audited the consolidated financial statements of the Company. Their report expresses their opinion as to the fair presentation, in all material respects, of the financial statements and is based upon their independent audit conducted in accordance with generally accepted auditing standards.

The Audit Committee, composed solely of outside directors, meets periodically with the independent auditors and representatives of management to discuss auditing and financial reporting matters. In addition, the independent auditors meet periodically with the Audit Committee without management representatives present and have free access to the Audit Committee at any time. The Audit Committee is responsible for recommending to the Board of Directors the engagement of the independent auditors, which is subject to stockholder approval, and the general oversight review of management’s discharge of its responsibilities with respect to the matters referred to above. We believe the Company’s internal controls as of and for the year ended December 31, 2002 provide reasonable assurance that the consolidated financial statements are reliable.

We have audited the accompanying consolidated balance sheets of Quicksilver Resources Inc. (the “Company”) as of December 31, 2002 and December 31, 2001, 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, 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

Quicksilver Resources Inc. (“Quicksilver”) is an independent oil and gas company incorporated in the state of Delaware and headquartered in Fort Worth, Texas. Quicksilver engages in the acquisition, development, exploration, production and sale of natural gas, crude oil and natural gas liquids as well as the marketing, processing and transmission of natural gas. Substantial portions of Quicksilver’s reserves are located in Michigan, Indiana and Alberta, Canada. Quicksilver has U.S. offices in Gaylord, Michigan, Cut Bank, Montana and a Canadian subsidiary, MGV Energy Inc. (“MGV”) located in Calgary, Alberta.

Quicksilver’s results of operations are largely dependent on the difference between the prices received for its natural gas and crude oil products and the cost to find, develop, produce and market such resources. Natural gas and crude oil prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond Quicksilver’s control. These factors include worldwide political instability, quantity of natural gas in storage, foreign supply of crude oil and natural gas, the price of foreign imports, the level of consumer demand and the price of available alternative fuels. Quicksilver manages a portion of the operating risk relating to natural gas and crude oil price volatility through hedging and fixed price contracts. (see notes 3 and 4)

The Consolidated Financial Statements include the accounts of Quicksilver and its subsidiaries (collectively, the “Company”). The Company accounts for its ownership in unincorporated partnerships and companies under the equity method of accounting as it has significant influence over those entities, but because of terms of the ownership agreements Quicksilver does not meet the criteria for control which would require consolidation of the entities. The Company also consolidates its pro-rata share of oil and gas joint ventures. All significant inter-company transactions are eliminated.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from the Company’s estimates. Significant estimates underlying these financial statements include the estimated quantities of proved natural gas and crude oil reserves used to compute depletion of natural gas and crude oil properties and the related present value of estimated future net cash flows therefrom (see note 19), estimates of current revenues based upon expectations for actual deliveries and prices received and the estimated fair value of financial derivative instruments.

Cash equivalents consist of time deposits and liquid debt investments with original maturities of three months or less.

The Company’s customers are natural gas and crude oil purchasers. Each customer and/or counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. The Company does not require collateral, however, appropriate credit ratings are required and parental guarantees are obtained. Receivables are generally due in 30-60 days. When collections of specific amounts due are no longer reasonably assured, an allowance for doubtful accounts is established. During 2002, four purchasers accounted for approximately 13.8%, 12.9%, 10.3% and 10.2%, respectively, of the Company’s total consolidated natural gas and crude oil sales.

The Company enters into financial derivative instruments to hedge price risk for its natural gas and crude oil sales and interest rate risk. Hedging is accounted for in accordance with Statements of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedge Activities” and SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities, which amended SFAS No. 133 (see note 3). The Company does not enter into financial derivatives for trading or speculative purposes.

All derivatives are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and losses that qualify as hedges are recognized in revenues or interest expense in the period in which the hedged transaction is recognized. Fair value is determined by reference to published future market prices or interest rates. Ineffective portions of hedges are recognized currently in earnings.

The Company’s long-term contracts for delivery of 25,000 Mcfd and 10,000 Mcfd at a floor of $2.49 and $2.47, respectively, through March 2009 are not considered derivatives but rather normal sales contracts under SFAS No. 133. Approximately 6,900 Mcfd of these volumes are third-party volumes controlled by the Company.

Inventories consist of well equipment, spare parts and supplies carried on a first-in, first-out basis at the lower of cost or market.

The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, geological and geophysical expenses, dry holes, leasehold equipment and overhead charges directly related to acquisition, exploration and development activities, are capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized.

The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves as determined by independent petroleum engineers. Excluded from amounts subject to depletion are costs associated with unevaluated properties. Natural gas and crude oil are converted to equivalent units based upon the relative energy content, which is six thousand cubic feet of natural gas to one barrel of crude oil.

Net capitalized costs are limited to the lower of unamortized cost net of 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, (ii) the cost of properties not being amortized, (iii) the lower of cost or market value of unproved properties included in the cost being amortized; less (iv) income tax effects related to differences between the book and tax basis of the natural gas and crude oil properties. Such limitations are imposed separately for the U.S. and Canadian cost center.

All other properties and equipment are stated at original cost and depreciated using the straight-line method based on estimated useful lives from five to forty years.

Revenues are recognized when title to the products transfer to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue, so that the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2002 and 2001, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred. Environmental remediation costs, which improve the condition of a property, are capitalized.

Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities at rates that will be in effect in years the temporary differences are expected to reverse. 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.

The Company’s financial instruments include cash, time deposits, accounts receivable, notes payable, accounts payable, long-term debt and financial derivatives. The fair value of long-term debt is estimated at the present value of future cash flows discounted at rates consistent with comparable maturities for credit risk. The carrying amounts reflected in the balance sheet for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value due to the short maturity of such instruments.

The Company’s Canadian subsidiary, MGV, uses the Canadian dollar as its function currency. All balance sheet accounts of Canadian operations are translated into U.S. dollars at the year-end rate of exchange and statement of income items are translated at the weighted average exchange rates for the year. The resulting translation adjustments are made directly to a separate component of other comprehensive income within stockholders’ equity. Gains and losses from foreign currency transactions are included in the consolidated statement of income.

Certain reclassifications have been made for comparative purposes for presentations adopted in 2002.

Basic net income or loss per common share is computed by dividing the net income or loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income or loss per common share is calculated in the same manner, but also considers the impact to net income and common shares for the potential dilution from stock options, stock warrants and any other outstanding convertible securities.

The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income per common share.

Warrants representing 550,000 shares of common stock were excluded from the 2002 and 2001 diluted net income per share computation for the period prior to their exercise as the exercise price exceeded the average market price of the Company’s common stock. For the year ended December 31, 2000, 24,856 shares of common stock under options and warrants representing 1,100,000 shares were excluded from the diluted net income per share computations as the exercise price exceeded the average market price of the Company’s common stock.

The Company has reviewed the requirements under Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 131, “Disclosure about Segments of an Enterprise and Related Information.” The Company has one reportable operating segment and its operations outside of the U.S. are not yet material.

The FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which is effective for fiscal years beginning after June 15, 2002. This statement, effective in 2003, establishes accounting and reporting standards for the legal obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction or development and the normal operation of long-lived assets. It requires that the fair value of the liability for asset retirement obligations shall be recognized in the period in which it is incurred.

Upon initial recognition of the asset retirement liability, an asset retirement cost shall be capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost shall be allocated to expense using a systematic method over the asset’s useful life. Changes in the liability for the asset retirement obligation shall be recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows.

All asset retirement obligations and costs were identified and their fair values estimated as of the date the long-lived assets were placed into service. The asset retirement obligations’ fair values were then estimated as of January 1, 2003, the date of adoption of the statement. Adoption by the Company of this accounting standard as of January 1, 2003 resulted in the recognition of $10.8 million of asset retirement costs and $13.1 million of asset retirement obligations. The cumulative-effect adjustment of $2.2 million includes $1.1 million for additional depletion and depreciation of the asset retirement costs, $2.3 million for accretion of the fair value of the asset retirement obligations and $1.2 million for deferred tax benefits. In 2003, the Company estimates the additional expense for depletion, depreciation and accretion to be $1.1 million before income taxes.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation— Transition and Disclosure—an amendment of FASB Statement No. 123.” The statement provides alternative methods of transition for voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company will comply with the disclosure requirements in its interim financial statements for the year ending December 31, 2003.

The FASB issued FASB Interpretation No. (“FIN”) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” in November 2002. The FIN elaborates on the disclosures required by a guarantor in its financial statements under certain guarantees it has issued. It also clarifies, that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. FIN 46, “Consolidation of Variable Interest Entities” was issued in January 2003. FIN 46 addresses consolidation by business enterprises of variable interest entities. The Company has reviewed both Interpretations. Neither FIN has any effect on the Company’s financial statements.

The Company hedges a portion of its equity production of natural gas and crude oil using various financial derivatives. All derivatives are evaluated using the hedge criteria established under SFAS Nos. 133 and 138. If hedge criteria are met, the change in a derivative’s fair value (for a cash flow hedge) is deferred in stockholders’ equity as a component of accumulated other comprehensive income. These deferred gains and losses are recognized into income in the period in which the hedged transaction is recognized in revenues to the extent the hedge is effective. The ineffective portions of hedges are recognized currently in earnings.

During 2002 and 2001, Cinnabar Energy Services and Trading LLC (“Cinnabar”), the Company’s wholly owned marketing subsidiary, entered into both fixed and floating price firm natural gas sale and purchase commitments and associated financial price swaps which extend through October 2003. The derivative transactions qualify as fair value hedges. Hedge ineffectiveness resulted in $26,000 of net losses and $48,000 of net gains recorded to other revenue in 2002 and 2001, respectively.

During 2002, the Company closed three interest rate swap agreements. The first, covering its $53,000,000 of Second Mortgage Notes (“Subordinated Notes”), was closed on July 15, 2002 and the Company received a cash settlement of $1,000,000. The agreement converted the debt’s 14.75% fixed rate to a floating three-month LIBOR base rate. The interest rate swap had qualified as a fair value hedge. The Company deferred the $1,000,000 settlement, which is being recognized through the original maturity date for the swap, March 30, 2009. In October, the Company closed its two fixed-rate interest rate swaps related to $75,000,000 of the Company’s variable-rate debt and entered into a new fixed-rate interest swap that converted the interest rate to a fixed-rate of 3.74% through March 31, 2005. The fair value of the open swap was a loss of $2,910,000 as of December 31, 2002. During the fourth quarter of 2002, $945,000 of the realized loss of $1,854,000 on the closed swaps was recognized as interest expense. The remainder will be reclassified out of other comprehensive income through March 31, 2003, the original maturity of such swaps.

The change in carrying value of the Company’s derivatives, firm sale and purchase commitments and interest rate swaps in the Company’s balance sheet since December 31, 2001 resulted from an increase in market prices for natural gas, crude oil and a decrease in interest rates. The change in fair value of all cash flow hedges was reflected in accumulated other comprehensive income, net of deferred tax effects. Natural gas and crude oil derivative assets and liabilities reflected as current in the December 31, 2002 balance sheet represent the estimated fair value of contract settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas and crude oil as of the balance sheet date. Because present accounting rules do not provide for the accrual of the future cash flow transactions the natural gas and crude oil swaps were designed to hedge, an apparent working capital deficit is created which does not, in management’s opinion, accurately depict the Company’s true working capital position or its liquidity. These settlement amounts are not due and payable until the monthly period that the related underlying hedged gas or oil sales transaction occurs. Settlement of the underlying hedged transactions occurs in the following 20 to 85 days.

The estimated fair values of all derivatives and the associated fixed price firm sale and purchase commitments of the Company as of December 31, 2002 and 2001 are provided below. The associated carrying values of these swaps are equal to the estimated fair values for each period presented.

The fair value of all natural gas and crude derivatives and firm sale and purchase commitments as of December 31, 2002 and 2001 was estimated based on market prices of natural gas and crude oil for the periods covered by the derivatives. The net differential between the prices in each derivative 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. The fair value of interest rate swaps was based upon counter party estimates of the fair value of such swaps. As a result, the fair value of the Company’s derivatives and commitments does not necessarily represent the value a third party would pay to assume the Company’s contract positions. Of the $52,749,000 of derivative liabilities, $26,362,000 has been classified as current based on the maturity of the derivative instruments resulting in $16,710,000 of after-tax losses to be reclassified from other comprehensive income in 2003.

The Company has established policies and procedures for managing risk within its organization, including internal controls. The level of risk assumed by the Company is based on its objectives and capacity to manage risk.

Quicksilver’s primary risk exposure is related to natural gas and crude oil commodity prices. The Company has mitigated the downside risk of adverse price movements through the use of swaps, futures and forward contracts, however, it has also limited future gains from favorable movements.

The Company enters into contracts to hedge its exposure to commodity price risk associated with anticipated future natural gas and crude oil production. These contracts have included physical sales contracts

and derivatives including price ceilings and floors, no-cost collars and fixed price swaps. As of December 31, 2002, Quicksilver sells approximately 25,000 Mcfd and 10,000 Mcfd of natural gas under long-term contracts with a floor of $2.49 per Mcf and $2.47 per Mcf, respectively, through March 2009. Approximately 28,100 Mcfd of the Company’s natural gas production was sold under these contracts during 2002. The remaining 6,900 Mcfd sold under these contracts were third-party volumes controlled by the Company. Approximately 38,100 Mcfd of the Company’s natural gas production is hedged using fixed price swap agreements at prices averaging $2.70 per Mcf. These agreements expire from April 2004 to April 2005. Additionally, the Company has hedged 500 Bbld of its crude oil production using a fixed price swap agreement at a price of $26.30 per Bbl and 1,500 Bbld of crude oil using crude oil collars with a floor of $21.00 per Bbl and a ceiling of $28.80 per Bbl. As a result of these various contracts, the Company benefits from significant predictability of its natural gas and crude oil revenues. The following table summarizes the Company’s open financial derivative positions as of December 31, 2002 related to natural gas and crude oil production.

Utilization of the Company’s hedging program may result in natural gas and crude oil realized prices varying from market prices that the Company receives from the sale of natural gas and crude oil. As a result of the hedging programs, revenues from production in 2002, 2001 and 2000 were $7,415,000, $22,052,000 and $22,474,000, respectively, lower than if the hedging program had not been in effect.

Commodity price fluctuations affect the remaining natural gas and crude oil volumes as well as the Company’s NGL volumes. Up to 4,500 Mcfd of natural gas is committed at market price through May 2004. Additional natural gas volumes of 16,500 Mcfd are committed at market price through September 2008. During 2002, approximately 5,400 Mcfd of Quicksilver’s natural gas production was sold under these contracts. An additional 15,600 Mcfd sold under these contracts were third-party volumes controlled by the Company.

Cinnabar also enters into various financial contracts to hedge its exposure to commodity price risk associated with future contractual natural gas sales and purchases with derivative instruments. Marketing revenues for Cinnabar were $2,221,000 and $2,957,000 lower as a result of its hedging activities in 2002 and

2001, respectively. The following table summarizes Cinnabar’s open financial derivative positions and hedged firm commitments as of December 31, 2002 related to natural gas marketing.

The fair values of fixed price and floating price natural gas and crude oil derivatives and associated firm commitments as of December 31, 2002 were estimated based on market prices of natural gas and crude oil for the periods covered by the contracts. The net differential between the prices in each contract 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 natural gas and crude oil financial swap and firm commitment fair value does not necessarily represent the value a third party would pay to assume the Company’s contract positions.

The Company manages its exposure associated with interest rates by entering into interest rate swaps. In October 2002, the Company closed its fixed-rate interest swaps related to $75,000,000 of its variable-rate debt and entered into a new fixed-rate swap. The new fixed-rate swap converts the debt’s floating LIBOR base to a 3.74% fixed-rate through March 31, 2005. The realized loss of $1,854,000 on the closed swaps is being reclassified out of other comprehensive income through March 31, 2003, the original maturity of the closed swaps.

In July 2002, the Company closed its variable-rate interest swap covering the $53,000,000 of fixed-rate Subordinated Notes. The swap converted the debt’s 14.75% fixed-rate debt to a floating three-month LIBOR base. The Company received a cash settlement of $1,000,000. The settlement was deferred and is being recognized as a reduction of interest expense through March 30, 2009 the original life of the swap.

Credit risk is the risk of loss as a result of non-performance by counterparties of their contractual obligations. The Company sells a portion its natural gas production directly under long-term natural gas contracts and the remainder of its natural gas and crude oil is sold through Cinnabar. All such natural gas and crude oil is

sold to creditworthy counterparties, such as utilities, major oil and gas companies or their affiliates, industrial customers, large trading companies or energy marketing companies, refineries and other users of petroleum products. The Company also enters into hedge derivatives with financial counterparties. The Company monitors exposure to counterparties by reviewing credit ratings, financial statements and credit service reports. Exposure levels are limited and parental guarantees are required according to Company policy. In this manner the Company reduces credit risk.

While the Company follows its credit policies at the time it enters into sales contracts, the credit worthiness of counterparties could change over time. In fact, credit ratings of the parent companies of the two counterparties to the Company’s long-term gas contracts were recently downgraded by Standard & Poors and Moody’s. Please see Item 1. Risk Factors.

Performance risk results when a financial counterparty fails to fulfill its contractual obligations such as commodity pricing or volume commitments. Typically, such risk obligations are defined within the trading agreements. The Company manages performance risk through management of credit risk. Each customer and/or counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter.

The Company’s Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, the Company is exposed to foreign currency exchange rate risk.

On December 2, 2002, the Company purchased from Enogex Exploration Company its interest in natural gas properties located in Michigan, most of which it has operated and continues to operate. The Company acquired approximately 64.2 Bcf of estimated proven reserves for $31,950,000 ($29,059,000 after estimated closing adjustments). The purchased interests added approximately 8.4 MMcfd of natural gas production to the Company’s current production. The Company financed the acquisition with available cash and existing credit facilities. The affect of this acquisition on the consolidated financial statements is not significant.

On March 31, 2000, the Company acquired from CMS Oil and Gas Company, a subsidiary of CMS Energy Corporation, oil and gas properties located primarily in Michigan (“CMS Properties” or “CMS Acquisition”). The purchase price, which was finalized in November 2000, was $164 million. The CMS Acquisition was financed through restructuring of Quicksilver’s senior bank facility, the sale of $53 million in subordinated notes, and the monetization, through a major financial institution, of a portion of the accompanying Internal Revenue Code Section 29 income tax credits related to the CMS Properties (see notes 9 and 10). The CMS Acquisition was accounted for under the purchase accounting method, and consisted of both CMS oil and gas properties and 100% of the common stock of Terra Energy Ltd.

The following table represents the allocation, in thousands, of the assets acquired and liabilities assumed, based upon their fair value on the date of the CMS Acquisition. In accordance with SFAS No. 109, “Accounting

for Income Taxes”, a deferred tax liability was recognized for the differences between the allocated values and the tax bases of the acquired assets and liabilities.

The following summary unaudited pro forma financial information (in thousands, except per share amounts) gives the effect of the acquisition on the Company’s 2000 historical income statement as though the acquisition had occurred at January 1, 2000. Adjustments were made to reflect a combined depletion rate, incremental general and administrative expense and interest expense on acquisition debt. The effects of the other acquisitions in the year 2000 on the consolidated financial statements are not significant and have been excluded from the pro forma presentation.

Effective July 1, 2000, Quicksilver purchased substantially all of the oil and gas-related assets of, and 65% of a gas compression company from, Mercury Exploration Company (“Mercury”), a related party (see note 19), for $18 million. An independent appraiser determined the fairness, from a financial point of view, of the $18 million purchase price, and the non-related party members of the Board of Directors approved the purchase. The acquisition was financed through assumption of existing debt of $6.1 million, application of an account receivable of $7.3 million, issuance of a note of $3.2 million and accounts payable of $1.4 million. The transaction was accounted for as an acquisition of companies under common control. As a result, all assets and liabilities acquired were recorded at Mercury’s historical book value. The excess of purchase price over book value was accounted for as a reduction of paid in capital.

The assets purchased included all of the capital stock of Mercury Michigan, Inc. (“MMI”), 65% of the capital stock of Voyager Compression Services, LLC (“Voyager”) and gas and oil properties located in Indiana and Kentucky. MMI is a gas processing company, which gathers and processes approximately 75 million cubic feet of natural gas per day, and which owns fifty percent each of Beaver Creek Pipeline, LLC (“Beaver Creek”) and Cinnabar Energy Services & Trading, LLC (“Cinnabar”). Quicksilver now owns 100% of Beaver Creek and Cinnabar.

On December 22, 2000, Quicksilver acquired the remaining minority interest in its Canadian subsidiary, MGV Energy Inc., headquartered in Calgary, Alberta. Quicksilver’s initial 89.5% interest in MGV was acquired on August 26, 1999. In exchange for their 10.5% interest, the minority shareholders of MGV received the equivalent of 283,669 shares of Quicksilver common stock in the form of MGV exchangeable shares valued at $2,309,000, which was allocated to the assets acquired and liabilities assumed based upon their fair value.

On March 10, 1999, one of the Company’s natural gas purchasers filed for protection under Chapter 11 of the Federal Bankruptcy Code. Management determined that a portion of the approximate $2,450,000 account receivable associated with the purchaser was uncollectable; accordingly, an allowance for doubtful accounts of $1,350,000 was established in the first quarter of 1999. The Company recovered $1,379,000 during 2000 and an additional $1,651,000 during 2001. As a result, $1,071,000 and $279,000 were recorded in 2001 and 2000, respectively, as recoveries of the provision for doubtful accounts. The remaining $580,000 was recorded to other revenue in 2001.

Under full cost accounting, the Company may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties excluded from natural gas and crude oil properties being amortized at December 31, 2002 and 2001 and the year in which they were incurred as follows:

Costs are transferred into the amortization base on an ongoing basis, as the projects are evaluated and proved reserves established or impairment determined. Pending determination of proved reserves attributable to the above costs, the Company cannot assess the future impact on the amortization rate. As of December 31, 2002, approximately $13,025,000 of the total unevaluated property balance of $16,913,000 related to the Company’s Canadian coal bed methane projects. These costs will be transferred into the amortization base as the undeveloped areas are evaluated. The Company anticipates that the majority of this activity should be completed over the next two to three years.

Capitalized overhead costs that directly relate to exploration and development activities were $847,000 and $481,000 for the years ended December 31, 2002 and 2001, respectively.

Depletion per Mcfe was $0.69, $0.65 and $0.68 for the years ended December 31, 2002, 2001 and 2000, respectively.

Costs related to the acquisition of debt are deferred and amortized on a straight-line basis over the term of the debt.

The Company has a three-year revolving credit facility (“Credit Facility”) that matures on May 13, 2005 and permits the Company to obtain revolving credit loans and to issue letters of credit for the account of the Company from time to time in an aggregate amount not to exceed the lesser of the borrowing base or $250 million. The borrowing base is $250 million and is subject to semi-annual determination and certain other redeterminations based upon several factors. Scheduled redeterminations occur on May 1 and November 1 of each year. At the Company’s 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, the Company can designate the interest rate on amounts outstanding at either the LIBOR + 1.875% or bank prime. At December 31, 2002, the Company’s interest rate was 3.665% through January 2, 2003 on $177 million. The collateral for the Credit Facility consists of substantially all of the existing assets of the Company and any future reserves acquired. The loan agreements prohibit the declaration or payment of dividends by the Company and contain other restrictive covenants, which, among other things, require the maintenance of a minimum current ratio. The Company currently is in compliance with all such restrictions. At December 31, 2002, the Company had $57,085,496 available under the Credit Facility.

The Company also has $53 million of 14.75% Second Mortgage Notes (“Subordinated Notes”) outstanding at December 31, 2002. These notes were issued in March and April of 2000. Prepayments made on or after March 28, 2003 require a premium payment ranging from 3% to 6%. Quarterly interest payments to the note holders may be paid in kind with respect to all or any portion of interest in excess of 10% by issuing additional

notes. The Subordinated Notes contain restrictive covenants, which, among other things, require maintenance of working capital, collateral coverage ratio and an earnings ratio before interest, taxes, depreciation and amortization and costs associated with seismic and geological services in connection and attributable to oil and gas exploration. The Company is currently in compliance with such restrictions. The Subordinated Notes are due on March 30, 2009, with quarterly principal payments starting on the earlier of: (a) payment in full of the Company’s Credit Facility indebtedness or (b) June 28, 2006. A deferred gain of $942,000 remains from the settlement of an interest rate hedge related to the Subordinated Notes. In July 2002, the Company received $1,000,000, which is being amortized through the original termination date of the hedge, March 30, 2009.

On March 12, 2003, the holders of the Subordinated Notes were notified that the Company intended to exercise its prepayment option for all of the Subordinated Notes outstanding. In addition to the principal and accrued interest, the Company will pay a premium of $3,180,000 on June 27, 2003. The Company plans to finance the repayment with issuance of $50 million of term debt to be repaid over three and one half years at an interest rate of approximately 7.5%. The remaining $6,180,000 of principal and premium is expected to be financed through the Credit Facility. At the time of the refinancing, the premium of $3,180,000 and the remaining deferred finance costs of approximately $1,485,000 will be expensed. The remainder of the deferred hedging gain of approximately $875,000 will be recognized as well.

As a part of the Mercury acquisition, the Company incurred debt through a note payable to Mercury Exploration Company. This note has an interest rate of 9% with quarterly principal payments of $160,000 plus interest through December 2005. The balance of this note was $1,920,000 as of December 31, 2002.

Until expiration of the tax credit at December 31, 2002, certain properties of the Company earned Internal Revenue Code Section 29 income tax credits. Code Section 29 allowed a credit against regular federal income tax liability for certain eligible gas production.

On March 31, 2000, the Company conveyed, to a bank, Section 29 tax credits for 99.5% of the interests acquired from CMS and the Terra interests in Devonian production from certain wells located in Michigan. Cash proceeds received from the sale were $25 million and were recorded as unearned revenue. Revenue was recognized as reserves were produced. The purchase and sale agreement and ancillary agreements with the bank included a production payment in favor of Quicksilver burdening future production on the properties. Revenue of $3,678,000, $9,396,000 and $6,842,000 was recognized in 2002, 2001 and 2000, respectively, in other revenue.

During 1997, other tax credits were conveyed through the sale of certain working interests to a bank. Revenue of $1,451,000, $1,499,000 and $1,431,000 was recognized in 2002, 2001 and 2000, respectively, in other revenue.

The Company expects to repurchase the remaining interests in the properties. The Company has estimated that the cost to reacquire the interests will not exceed $5,743,000.

The Company leases office buildings and other property under operating leases. Future minimum lease payments, in thousands, for operating leases with initial non-cancelable lease terms in excess of one year as of December 31, 2002, were as follows:

Rent expense for operating leases with terms exceeding one month was $1,434,000 in 2002, $1,706,000 in 2001, and $1,088,000 in 2000.

As of December 31, 2002, the Company had approximately $979,000 in letters of credit outstanding related to various state and federal bonding requirements.

Quicksilver has an incentive plan in place for three executives of MGV. The plan calls for a bonus to be payable as of December 31, 2005 (determination date) based principally on the value of proved reserves found and certain other measures. As of December 31, 2002 these performance measures had not been met and accordingly no accrual has been made. The Company will continue to evaluate the performance of the executives against the criteria set forth in the bonus plan and make accruals for such bonus payments when it determines that it is probable that the bonus payments will be made.

In August 2001, a group of royalty owners (Athel E. Williams et al.) brought suit against Quicksilver and three of its subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd, one of Quicksilver’s subsidiaries acquired in 2000, 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. Due to administrative oversight an answer was not timely filed and a default was entered against us in December 2001. On October 24, 2002, the trial court granted Terra’s motion to set aside the default. The court heard arguments on class certification on November 8, 2002; on December 6, 2002 the court issued a memorandum opinion granting class certification in part and denying it in part. The court stated that those portions of the royalty owner’s complaint against us alleging that we deducted excessive post production costs from royalty payments should not be certified as class action. The court certified the remainder of the complaint for class action status. On December 20, 2002 we filed a motion for clarification and reconsideration of the court’s order. That motion was denied on March 9, 2003. Based on information currently available to the Company, Quicksilver believes that the final resolution of this matter will not have a material effect on its operations, equity or cash flows.

The Company is subject to various possible contingencies, which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2002, 2001 and 2000 are as follows:

The provisions for income taxes for the years ended December 31, 2002, 2001 and 2000 are as follows:

A reconciliation of the statutory federal income tax rate and the effective tax rate for the years ended December 31, 2002, 2001 and 2000 are as follows:

Included in deferred tax assets are net operating losses of approximately $35,273,000 that are available for carryover beginning in the year 2003 to reduce future U.S. taxable income. The net operating losses will begin to expire in 2004. These net operating losses have not been reduced by a valuation allowance, because management believes that future taxable income will more likely than not be sufficient to utilize substantially all of its tax carry forwards prior to their expirations. However, under Internal Revenue Code Section 382, a change of ownership was deemed to have occurred for MSR in 1998. Due to the limitations imposed by Section 382, a portion of MSR’s net operating losses could not be utilized and are not included in deferred tax assets.

Quicksilver has a 401(k) retirement plan available to all employees with three months of service and who are at least 21 years of age. The Company may make discretionary contributions to the plan. Company contributions were $172,000, $180,000 and $451,000 for the years ended December 31, 2002, 2001 and 2000, respectively.

The Company initiated a self-funded health benefit plan effective July 1, 2001. The plan has been reinsured on an individual claim and total group claim basis. Quicksilver is responsible for payment of the first $40,000 for each individual claim. The claim liability for the total group was $1,097,000 for the plan year ended June 30, 2002 and is anticipated to be approximately $1,397,000 for the plan year ending June 30, 2003. Aggregate level reinsurance is in place for payment of claims up to $1,000,000 over and above the estimated maximum claim liability of $1,758,000 for the plan year ending June 30, 2003. Administrative expenses for the plan year ended June 30, 2002 were $352,000 and are anticipated to be $362,000 for the plan year ending June 30, 2003.

The Company is authorized to issue 40 million shares of common stock with a par value per share of one cent ($0.01) and 10 million shares of preferred stock with a par value per share of one cent ($0.01). At December 31, 2002, the Company had 21,092,945 shares of common stock outstanding (including 227,421 shares issuable in respect to the MGV exchangeable shares) and one share of special voting preferred stock outstanding.

In connection with the December 2000 MGV minority interest acquisition, all issued and outstanding shares of MGV capital stock, other than those held by Quicksilver, totaled 283,669 and were converted into MGV exchangeable shares. Each MGV exchangeable share is a non-voting share of MGV’s capital stock exchangeable for one share of Quicksilver common stock. Exchange can occur as a result of (i) liquidation of MGV; (ii) exercise of a redemption right by an MGV shareholder requiring MGV to purchase exchangeable shares; or (iii) exercise of an exchange put right by an MGV shareholder requiring Quicksilver to exchange the exchangeable shares for Quicksilver common stock. Any MGV exchangeable shares still outstanding on December 31, 2005 will be treated as having been the subject of an exercise of an exchange put right on that date. Upon exchange, the holder of exchangeable shares is entitled to receive one share of Quicksilver common stock and the full amount of all cash dividends declared on a share of Quicksilver common stock from the date of issuance of the exchangeable share to the date of exchange. In order to provide voting rights to holders of MGV exchangeable shares equivalent to the voting rights of the Quicksilver common shares, Quicksilver created, on December 15, 2000, a series of its preferred stock designated as Special Voting Stock. Quicksilver issued a single share of Special Voting Stock to an appointee. During 2002 and 2001, 10,000 and 3,500 exchangeable shares, of MGV were presented to Quicksilver for purchase for $189,100 and $59,200, respectively. A total of 42,748 MGV exchangeable shares were converted to Quicksilver common stock during 2002.

The Company’s restated certificate of incorporation authorizes its board of directors to issue preferred stock without stockholder approval. If the Company’s board of directors elects to issue preferred stock, it could be

more difficult for a third party to acquire control of the Company, even if that change of control might be beneficial to stockholders. The Company’s restated certificate also provides for a classified board of directors. This staggered election approach makes more difficult and discourages a proxy contest or the assumption of control by a substantial stockholder and thus increases the likelihood that incumbent directors will retain their positions. In March 2003, by amendment of its bylaws, the Company established an advance notice requirement for director nominations by stockholders and actions to be taken at annual meetings at the request of stockholders. It also established a stockholder rights plan. These bylaw amendments and the stockholder rights plan could impede a merger, consolidation, takeover or other business combination involving the Company or discourage a potential acquirer from making a tender offer or otherwise attempting to take control of the Company. In certain circumstances, the fact that corporate devices are in place that will inhibit or discourage takeover attempts could reduce the market value of the Company’s common stock.

On March 11, 2003, the Company’s board of directors declared a dividend distribution of one preferred share purchase right for each outstanding share of common stock of the Company outstanding on March 26, 2003. Each right will entitle stockholders to buy one one-thousandth of a share of the Company’s Series A Junior Participating Preferred Stock at an exercise price of $100.00.

The rights will be exercisable only if a person or group acquires 15 percent or more of the common stock of Quicksilver or announces a tender offer the consummation of which would result in ownership by a person or group of 15 percent or more of the common stock of the Company. Such 15 percent threshold will not apply to certain members of the Darden family who collectively owned, directly or indirectly, approximately 46.7% of the Company’s common stock at December 31, 2002.

If Quicksilver is acquired in a merger or other business combination transaction after a person has acquired 15 percent or more of the outstanding common stock of the Company, each right will entitle its holder to purchase, at the right’s then-current exercise price, a number of the acquiring company’s common shares having a market value of twice such price. In addition, if a person or group acquires 15 percent or more of the outstanding common stock of the Company, each right will entitle its holder (other than such person or members of such group) to purchase, at the right’s then-current exercise price, a number of common shares of the Company having a market value of twice such price.

Prior to the acquisition by a person or group of beneficial ownership of 15 percent or more of the common stock of Quicksilver, the rights are redeemable for one cent per right at the option of the board of directors of the Company.

On October 4, 1999, the Board of Directors adopted the Company’s 1999 Stock Option and Stock Retention Plan (the “1999 Plan”), which was approved at the annual stockholders’ meeting held in June 2000. There are 1.3 million shares of common stock reserved under the 1999 Plan, which provides for the grant of incentive stock options, non-qualified stock options, stock appreciation rights and retention stock awards.

Under terms of the 1999 Plan, options may be granted to officers and employees at an exercise price that is not less than 100% of the fair market value on the date of grant, and which are exercisable in whole or part by the optionee after at least one year of continuous service from the date of grant. Incentive stock options and non-qualified options may not be exercised more than ten years from date of grant. A summary of stock option

transactions under the 1999 Plan, including options for 24,856 shares of the Company’s common stock resulting from a conversion of outstanding MSR Exploration Ltd. options in March of 1999, is as follows:

Pro forma information regarding net income and earnings per share is required by SFAS No. 123, and has been determined as if the Company had accounted for its employee stock options under the fair value method of that statement. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions:

The following table reflects pro forma net income and earnings per share under the fair value approach of SFAS No. 123 (in thousands, except per share amounts):

These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period, and additional options may be granted in future years.

The following table summarizes information about stock options outstanding at December 31, 2002.

As of December 31, 2002, the Darden family has 46.7% beneficial ownership in Quicksilver including shares owned directly, and shares owned by Mercury Exploration Company and Quicksilver Energy L.C., companies that are owned by the Dardens. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.

During 2002 and 2001, Quicksilver paid $849,000 and $902,000, respectively, for principal and interest on the note payable to Mercury associated with the 2000 acquisition of assets from Mercury. The balance of the note is $1,920,000 at December 31, 2002. Quicksilver and its associated entities paid $743,000 and $731,000 for rent in 2002 and 2001, respectively, on buildings which are owned by a Mercury affiliate. Rental rates were determined based on comparable rates charged by third parties.

Effective July 1, 2000, Quicksilver purchased the natural gas producing, gathering, transmission and marketing assets of, and 65% of Voyager Compression Services, LLC (“Voyager”), a gas compression company, from Mercury for $18 million. An independent appraiser determined the fairness, from a financial point of view, of the $18 million purchase price and the non-related party members of the Board of Directors approved the purchase. Mercury continues to own 33% of Voyager, and Jeff Cook, an officer of the Company, owns 2%.

Quicksilver accounts for its 65% holdings in Voyager under the equity method since control over Voyager is shared equally with Mercury. During 2002 and 2001, Quicksilver purchased compressors and equipment for $3,725,000 and $5,386,000 respectively, and maintenance and related services for $1,846,000 and $2,791,000, respectively, from Voyager at terms as favorable as those granted to third parties.

During 2002, Voyager recognized an impairment loss of $926,000 related to its inventory, fixed assets and operating leases for facilities. Subsequently, Voyager sold, to a third party, its Michigan inventory and fixed assets and recognized a gain on the sale of $245,000. Quicksilver recognized its proportionate share of these items during the year.

Voyager sold its compressor service fixed assets and the majority of its Texas inventory to Quicksilver for $1,570,000 (its historical cost that approximated fair value), in February 2003. In addition, Quicksilver agreed to pay Voyager $2,219,000 for the fair value of its compressor service contracts. The transaction was reviewed and approved by the non-related party members of the Board of Directors. Mercury’s portion of the gain on the sale of the service contracts will be treated as an equity distribution by Quicksilver as Mercury and the Darden family are considered as having a controlling interest in Quicksilver. Quicksilver’s gain on the sale of the contracts will be eliminated.

Voyager has also agreed to sell to a Mercury affiliate certain leasehold improvements on operating leases with the Mercury affiliate at historical cost, which approximates fair value, of approximately $844,000. The leases will be cancelled and Voyager estimates the lease cancellation costs to be $437,000.

The following table reflects quantities of proved oil and gas reserves, based upon reports prepared by Holditch-Reservoir Technologies Consulting Services, independent petroleum engineers and a subsidiary of Schlumberger, and Netherland, Sewell & Associates, Inc. The reserve reports were prepared in accordance with guidelines established by the Securities and Exchange Commission and, accordingly, were based on existing economic and operating conditions. Natural gas and crude oil prices in effect as of the date of the reserve reports were used without any escalation except in those instances where the sale of production was covered by contract, in which case the applicable contract prices, including fixed and determinable escalations, were used for the duration of the contract, and thereafter the year-end price was used (See “Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves” below for a

discussion of the effect of the different prices on reserve quantities and values.) Operating costs, production and ad valorem taxes and future development costs were based on current costs with no escalation.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of the Company’s natural gas and crude oil reserves or the costs that would be incurred to obtain equivalent reserves. Reserves are primarily located in the United States. As of December 31, 2002, 2001 and 2000, Canadian reserves were natural gas of 53.6 Bcf, 16.5 Bcf and 16.2 Bcf, respectively.

The following table sets forth certain information regarding the production and sales volumes and average sales prices and production costs associated with Quicksilver’s producing properties for the periods indicated.

Costs incurred in oil and gas property acquisition, exploration and development activities are as follows:

The following table summarizes productive oil and gas wells attributable to our direct interests as of December 31, 2002.

The following table sets forth the developed and undeveloped leasehold acreage held directly by Quicksilver. Developed acres are defined as acreage spaced or able to be assigned to productive wells. 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 Quicksilver has a working interest. Net acres are the sum of Quicksilver’s fractional interests owned in the gross acres. Quicksilver holds undeveloped acreage ine Michigan, Montana, Indiana and Wyoming as well as the Canadian province of Alberta.

The following table sets forth the number of wells drilling and attributable to Quicksilver direct interests.

I. Standard Measures of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves

The standardized measure of discounted cash flows relating to oil and gas reserves are set forth below:

An analysis of changes in the standardized measure of discounted future net cash flow follows:

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of the Company’s natural gas and crude oil properties. An estimate of such value should consider, among other factors, anticipated future prices of natural gas and crude oil, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

Under the Standardized Measure, future cash inflows were estimated by applying year-end prices, adjusted for contracts with price floors but excluding hedges, to the estimated future production of the year-end reserves. These prices were adjusted by field for appropriate regional differentials. The average product prices resulting from such adjustments were $4.45, $2.66, and $8.12 per Mcfe for 2002, 2001 and 2000, respectively. These prices have varied widely and have a significant impact on both the quantities and value of the proved reserves as reduced prices cause wells to reach the end of their economic life much sooner and also make certain proved undeveloped locations uneconomical, both of which reduce reserves.

Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved natural gas and crude oil properties. Tax credits and net operating loss carry forwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

The information set forth under Item 1—Election of Directors, in our proxy statement for our annual meeting of stockholders to be held May 20, 2003, is incorporated herein by reference. See Item 1. “Business— Executive Officers” for information concerning executive officers.

The information set forth under “Executive Compensation” of the proxy statement for our May 20, 2003 meeting of stockholders is incorporated herein by reference.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information set forth under “Security Ownership of Certain Beneficial Holders and Management and Related Stockholder Matters” in the proxy statement for our May 20, 2003 meeting of stockholders is incorporated herein by reference.

The information set forth under “Transactions with Management and Certain Stockholders” in the proxy statement for our May 20, 2003 meeting of stockholders is incorporated herein by reference.

During the 90-day period prior to the filing date of this report, management, including our president and chief executive officer and senior vice president and chief financial officer, evaluated effectiveness of the design and operation of our disclosure controls and procedures. Based upon, and as of the date of, that evaluation, the president and chief executive officer and senior vice president and chief financial officer concluded that the disclosure controls and procedures were effective, in all material respects, to ensure that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required.

There have been no significant changes in our internal controls or in other factors, which could significantly affect internal controls subsequent to the date we carried out our evaluation. There were no significant deficiencies or material weaknesses identified in the evaluation and, therefore, no corrective actions were taken.

The following financial statements of ours and the report of our Independent Auditors thereon are included on pages 41 through 74 of this Form 10-K.

Consolidated Statements of Income for the years ended December 31, 2002, 2001 and 2000

Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the years ended December 31, 2002, 2001 and 2000

Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000

Notes to Consolidated Financial Statements for the Years Ended December 31, 2002, 2001 and 2000

[All schedules are omitted because the required information is inapplicable or the information is presented in the financial statements or the notes thereto.]

We filed a Current Report on Form 8-K on November 19, 2002 to report as an Other Event item that we entered into an Underwriting Agreement with McDonald Investments Inc. with respect to the sale by us and the purchase by McDonald Investments of 1,000,000 shares of our common stock, and with respect to the grant by us to McDonald Investments of an option to purchase all or any part of 150,000 shares of common stock solely to cover over-allotments. The shares of our common stock purchased by McDonald Investments were issued pursuant to a shelf registration statement we previously filed with the Securities and Exchange Commission and which was declared effective.

We filed a Current Report on Form 8-K on December 10, 2002 to report as an Other Event item the completion of an acquisition of Enogex Exploration Corporation’s interests in natural gas properties located in Michigan.

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

QUICKSILVER RESOURCES INC. (the “Registrant”)

by:		/s/ GLENN DARDEN
		Glenn Darden President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on behalf of the registrant and in the capacities and on the dates indicated have signed this report below.

I, Glenn Darden, President and Chief Executive Officer of Quicksilver Resources Inc., certify that:

By:

/s/ GLENN DARDEN

Glenn Darden

President and Chief Executive Officer

I, Bill Lamkin, Executive Vice President and Chief Financial Officer of Quicksilver Resources Inc., certify that:

By:

/s/ BILL LAMKIN

Bill Lamkin

Executive Vice President and

Chief Financial Officer

Producing Formation	Proved Reserves (Bcfe)	% Gas		% Proved Developed		2002 Production (MMcfed)
Antrim Shale	549.9	100	%	87	%	56.9
Non-Antrim	104.2	59	%	81	%	36.8

All Formations	654.1	93	%	86	%	93.7

	Year ended December 31,
	2002		2001		2000
Proved reserves:
Natural gas (MMcf)		691,585		551,522		570,814
Crude oil (MBbl)		16,002		13,344		14,856
NGL (MBbl)		2,216		1,538		1,535
Total (MMcfe)		800,893		640,814		669,160
Representative crude oil and natural gas prices: (1)
Natural gas—NYMEX Henry Hub	$	4.74	$	2.57	$	9.78
Crude oil—NYMEX		31.20		19.84		26.90
Present values (in thousands): (2)
Standardized measure of discounted future net cash flows, before income tax	$	867,748	$	358,950	$	1,592,761
Standardized measure of discounted future net cash flows, after income tax	$	614,851	$	268,942	$	1,069,292
Proved developed reserves:
Natural gas (MMcf)		573,639		464,964		444,865
Crude oil (MBbl)		10,722		8,543		9,391
NGL (MBbl)		1,524		1,023		813
Total (MMcfe)		647,115		522,360		506,089

	Year Ended December 31,
Production:	2002		2001		2000
Natural gas (MMcf)		32,845		32,689		26,655
Crude oil (MBbl)		905		1,059		1,035
NGL (MBbl)		156		195		161
Total (MMcfe)		39,209		40,212		33,831
Weighted average sales price (including impact of hedges):
Natural gas (per Mcf)	$	2.75	$	3.03	$	3.04
Crude oil (per Bbl)		21.74		21.03		22.87
NGL (per Bbl)		14.97		19.97		25.25
Production cost (per Mcfe) (1)		1.08		1.31		1.11

	Year Ended December 31,
	2002		2001		2000
Acquisition of properties	$	38,171	$	5,749	$	167,855
Development costs		35,116		50,202		20,078
Exploration costs		14,584		10,103		360

Total	$	87,871	$	66,054	$	188,293

	GROSS	NET
Natural Gas	4,532	1,463.5
Oil	568	531.9

Total	5,100	1,995.4

PART I
ITEM 1.	Business	3
ITEM 2.	Properties	18
ITEM 3.	Legal Proceedings	23
ITEM 4.	Submission of Matters to a Vote of Security Holders	23

PART II
ITEM 5.	Market for Registrant’s Common Equity and Related Stockholder Matters	24
ITEM 6.	Selected Financial Data	24
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk	37
ITEM 8.	Financial Statements and Supplementary Data	41
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	74

PART III
ITEM 10.	Directors and Executive Officers of the Registrant	75
ITEM 11.	Executive Compensation	75
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	75
ITEM 13.	Certain Relationships and Related Transactions	75
ITEM 14.	Controls and Procedures	75

PART IV
ITEM 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	76
	SIGNATURES	78
	CERTIFICATIONS	79

Areas of Operations	Proved Reserves (Bcfe)	% Natural Gas		% Proved Developed		2002 Production (MMcfed)
Michigan	654.1	93	%	86	%	93.7
Indiana	22.0	100	%	66	%	2.0
Canada (1)	53.6	100	%	42	%	2.6
Other	71.2	6	%	66	%	9.1

Total	800.9	86	%	81	%	107.4

Name	Age	Position(s) Held With Quicksilver
		Executive Officers
Thomas F. Darden	49	Chairman of the Board
Glenn Darden	47	President, Chief Executive Officer and Director
Bill Lamkin	57	Executive Vice President, Chief Financial Officer and Secretary
Jeff Cook	46	Senior Vice President—Operations
D. Wayne Blair	46	Vice President and Controller
		Other Officers
Robert N. Wagner	39	Vice President—Reserve Group
John C. Cirone	52	Vice President and General Counsel
John B. Gremillion, Jr.	56	Vice President—Investor Relations
Anne Darden Self	45	Vice President—Human Resources and Director
MarLu Hiller	40	Treasurer

	Years Ended December 31,
	2002		2001		2000
	GROSS	NET	GROSS	NET	GROSS	NET
DEVELOPMENT WELLS:
Productive	123.0	98.2	198.0	122.6	55.0	35.5
Dry	1.0	1.0	1.0	—	—	—

Total	124.0	99.2	199.0	122.6	55.0	35.5

EXPLORATORY WELLS:
Productive	68.0	49.1	89.0	36.1	8.0	2.8
Dry	3.0	3.0	5.0	4.5	—	—

Total	71.0	52.1	94.0	40.6	8.0	2.8

	HIGH		LOW

2002
Fourth Quarter	$	24.40	$	16.79
Third Quarter		25.95		16.89
Second Quarter		26.35		21.30
First Quarter		23.50		16.80
2001
Fourth Quarter	$	19.50	$	11.45
Third Quarter		19.10		10.32
Second Quarter		20.50		11.00
First Quarter		13.69		9.06

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	738,211	$	7.50	[307,517	]
Equity compensation plans not approved by security holders	—		N/A	—

Total	738,211	$7.50		[307,517]

	Years Ended December 31,
	2002			2001
Income tax provision (in thousands)	$	7,498		$	10,800
Effective tax rate		35.2	%		35.9	%

	Payments Due by Period
Contractual Obligations	Total		Less than 1 Year		1-3 Years		4-5 Years		After 5 Years
	(in thousands)
Long-Term Debt	$	248,502	$	951	$	193,902	$	22,944	$	30,705
Operating Leases		6,297		1,230		2,037		1,576		1,454
Section 29 Property Settlement		5,743		5,743		—		—		—
Gas Purchase Obligation		324		324		—		—		—

Total Obligations	$	260,866	$	8,248	$	195,939	$	24,520	$	32,159

	Amounts of Commitments Expiration per Period
Commercial Commitments	Total Committed		Less than 1 Year		1-3 Years		4-5 Years		After 5 Years
	(in thousands)
Canadian Drilling Commitments	$	1,354	$	1,354	$	—	$	—	$	—
Standby Letters of Credit		979		979		—		—		—

Total Commitments	$	2,333	$	2,333	$	—	$	—	$	—

Product	Type	Contract Period	Volume	Weighted Avg Price Per Mcf or Bbl		Fair Value
						(in thousands)
Gas	Fixed Price	Jan 2003-Apr 2004	7,500 Mcfd	$	2.40	$	(7,836	)
Gas	Fixed Price	Jan 2003-Dec 2004	528 Mcfd		2.07		(724	)
Gas	Fixed Price	Jan 2003-Apr 2005	10,000 Mcfd		2.79		(13,292	)
Gas	Fixed Price	Jan 2003-Apr 2005	10,000 Mcfd		2.79		(13,354	)
Gas	Fixed Price	Jan 2003-Apr 2005	10,000 Mcfd		2.79		(13,354	)
Oil	Fixed Price	Jan 2003-Sep 2003	500 Bbld		26.30		(292	)
Oil	Collar	Jan 2003-Dec 2003	1,500 Bbld		21.00—28.80		(379	)

					Net open positions	$	(49,231	)

		Page
Management’s Responsibility for Financial Statements		42
Independent Auditors’ Report		43
Consolidated Balance Sheets as of December 31, 2002 and 2001		44
Consolidated Statements of Income for the Years Ended December 31, 2002, 2001 and 2000		45
Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the Years Ended December 31, 2002, 2001 and 2000		46
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000		47
Notes to Consolidated Financial Statements for the Years Ended December 31, 2002, 2001 and 2000		48

	2002			2001
ASSETS
Current assets
Cash and cash equivalents	$	9,116		$	8,726
Accounts receivable		21,075			21,489
Current deferred income taxes		9,045			2,640
Inventories and other current assets		5,540			5,079

Total current assets		44,776			37,934
Investments in and advances to equity affiliates		10,219			14,248
Properties, plant and equipment—net (“full cost”)		470,078			412,455
Other assets		4,465			7,247

	$	529,538		$	471,884

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	951		$	945
Accounts payable		14,931			12,168
Accrued derivative obligations		26,362			9,025
Accrued liabilities		26,210			34,937

Total current liabilities		68,454			57,075
Related party debt		1,280			1,920
Long-term debt		247,213			246,505
Unearned revenue		—			4,561
Deferred derivative obligations		26,387			13,461
Other long-term liabilities		234			222
Deferred income taxes		57,065			53,753
Commitments and contingencies (Note 12)		—			—
Stockholders’ equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 1 share issued as of December 31, 2002 and 2001		—			—
Common stock, $0.01 par value, 40,000,000 shares authorized, 23,663,447 and 22,534,875 shares issued as of December 31, 2002 and 2001, respectively		237			225
Paid in capital in excess of par value		114,113			77,814
Treasury stock of 2,570,502 and 3,751,852 shares as of December 31, 2002 and 2001, respectively		(10,099	)		(14,634	)
Accumulated other comprehensive loss		(34,170	)		(14,007	)
Retained earnings		58,824			44,989

Total stockholders’ equity		128,905			94,387

	$	529,538		$	471,884

	December 31, 2002		December 31, 2001
	(in thousands)
Derivative assets:
Fixed price purchase commitments	$	29	$	1,476
Natural gas financial collars		—		255
Floating price natural gas financial swaps		269		93
Fixed price natural gas financial swaps		—		28
Fixed to floating interest rate swap		—		1,853

		298	$	3,705

Derivative liabilities:
Fixed price natural gas financial swaps	$	48,560	$	17,134
Fixed price crude oil financial swaps		292		—
Fixed price sale commitments		226		—
Crude oil financial collars		379		—
Floating price natural gas financial swaps		382		1,521
Floating to fixed interest rate swap		2,910		3,832

	$	52,749	$	22,487

Properties and equipment	$	189,080
Working capital		(570	)
Deferred taxes		(24,497	)

Total purchase price	$	164,013

	Year Ended December 31, 2000
	(in thousands, except per share data)
Revenues	$	134,618
Expenses		105,549
Net income		18,495
Earnings per share—
Basic	$	1.01
Diluted	$	1.00

	As of December 31,
	2002		2001
	(in thousands)
Accrued production receivables	$	15,351	$	14,451
Joint interest receivables		5,080		6,251
Other receivables		644		787

	$	21,075	$	21,489

	December 31, 2002 Costs Incurred During										December 31, 2001 Costs Incurred During
	2002		2001		2000		Prior		Total		2001		2000		1999		Prior		Total
	(in thousands)										(in thousands)
Acquisition costs	$	6,249	$	903	$	2,083	$	875	$	10,110	$	1,574	$	3,119	$	1,224	$	300	$	6,217
Exploration costs		6,803		—		—		—		6,803		8,022		219		—		—		8,241

Total	$	13,052	$	903	$	2,083	$	875	$	16,913	$	9,596	$	3,338	$	1,224	$	300	$	14,458

Years Ending
2003	$	951
2004		951
2005		192,951
2006		10,680
2007		12,264
2008		9,882
Thereafter		20,823

	$	248,502

	2002		2001
Risk-free interest rate	3.0	%	3.5	%
Expected life (in years)	3.5		3.5
Expected volatility	55.6	%	60.7	%
Dividend yield	—		—

	2002				2001
	As Reported		Pro Forma		As Reported		Pro Forma
Net income	$	13,835	$	13,161	$	19,310	$	18,719
Basic net income per share	$	0.70	$	0.66		1.03		1.00
Diluted net income per share	$	0.68	$	0.65		1.00		0.97

	Options Outstanding				Options Exercisable
Range of Exercisable Prices	At 12/31/02	Wtd Avg Remaining Contractual Life	Wtd Avg Exercise Price		At 12/31/02	Wtd Avg Exercise Price
$ 3-4	304,407	2.1	$	3.69	160,339	$	3.69
7-8	264,998	2.5		7.12	156,281		7.13
9-10	39,452	3.1		9.80	39,452		9.80
16-18	129,236	4.0		16.55	28,967		16.20
22-23	118	4.9		22.83	118		22.83

	738,211	2.6	$	7.50	385,157	$	6.65

	For the Years Ended December 31,
	2002		2001		2000
	(in thousands)
Section 29 tax credits	$	5,129	$	10,895	$	8,273
Marketing		3,021		3,623		598
Processing and transportation		1,533		1,520		604
Other		—		580		145

	$	9,683	$	16,618	$	9,620

	For the Years Ended December 31,
	2002		2001		2000
Natural gas (MMcf)
Beginning of year	551,552		570,814		192,963
Revisions of previous estimates	41,663		(43,351	)	14,434
Extensions and discoveries	66,979		54,855		17,923
Purchases of reserves-in-place	64,267		1,893		372,149
Production	(32,845	)	(32,689	)	(26,655	)

Total proved, end of year	691,586		551,522		570,814

Proved developed reserves	573,638		464,964		444,865

Crude oil (MBbl)
Beginning of year	13,344		14,856		15,281
Revisions of previous estimates	2,153		(455	)	(787	)
Extensions and discoveries	1,444		—		—
Purchases of reserves-in-place	25		2		1,397
Sales of reserves-in-place	(59	)	—		—
Production	(905	)	(1,059	)	(1,035	)

Total proved, end of year	16,002		13,344		14,856

Proved developed reserves	10,722		8,543		9,391

Natural gas liquids (MBbl)
Beginning of year	1,538		1,535		845
Revisions of previous estimates	214		197		555
Extensions and discoveries	619		—		—
Purchases of reserves-in-place	1		1		296
Production	(156	)	(195	)	(161	)

Total proved, end of year	2,216		1,538		1,535

Proved developed reserves	1,524		1,023		813

Proved reserves equivalent end of year (MMcfe):
Natural gas	691,586		551,522		570,814
Crude oil	96,012		80,064		89,136
Natural gas liquids	13,295		9,228		9,210

Total proved	800,893		640,814		669,160

Total proved developed	647,116		522,360		506,089

	Mar 31		Jun 30		Sep 30		Dec 31
	(In thousands, except per share data)
2002
Operating revenues	$	28,899	$	31,000	$	30,307	$	31,773
Operating income		8,177		10,283		11,045		11,188
Net income		2,172		3,690		3,640		4,333
Basic net income per share		0.11		0.19		0.18		0.21
Diluted net income per share		0.11		0.18		0.18		0.21
2001
Operating revenues	$	43,084	$	37,879	$	32,034	$	28,966
Operating income (1)		20,881		13,691		10,871		7,961
Net income		9,404		5,004		3,120		1,782
Basic net income per share		0.51		0.27		0.17		0.09
Diluted net income per share		0.50		0.26		0.16		0.09

Exhibit No.		Sequential Description

3.1		Restated Certificate of Incorporation of Quicksilver Resources Inc. (filed as Exhibit 4.1 to the Company’s Form S-4 File No. 333-66709, filed November 3, 1998 and included herein by reference).

3.2		Certificate of Designation, Preferences and Rights of Preferred Stock (filed as Exhibit 3.2 to the Company’s Form 10-K filed March 27, 2001 and included herein by reference).

3.3		Certificate of Amendment to the Restated Certificate of Incorporation of Quicksilver Resources Inc. (filed as Exhibit 3.1 to the Company’s Form 10-Q filed August 14, 2001 and included herein by reference).

*3.4		Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc.

3.5		Bylaws of Quicksilver Resources Inc. (filed as Exhibit 4.2 to the Company’s Form S-4 File No. 333-66709, filed November 3, 1998 and included herein by reference).

3.6		Amendment to Bylaws of Quicksilver Resources Inc. adopted on November 30, 1999 (filed as Exhibit 3.4 to the Company’s Form 10-K filed March 27, 2001 and included herein by reference).

3.7		Amendment to the Bylaws of Quicksilver Resources Inc., adopted June 5, 2001 (filed as Exhibit 3.2 to the Company’s Form 10-Q filed August 14, 2001 and included herein by reference.)

*3.8		Amendment to the Bylaws of Quicksilver Resources Inc., adopted March 11, 2003

4.1		Rights Agreement, dated as of March 11, 2003, between Quicksilver Resources Inc. and Mellon Investor Services LLC, as Rights Agent (filed as Exhibit 4.1 to the Company’s Form 8-A filed March 14, 2003 and included herein by reference.)

10.1		Master Gas Purchase and Sale Agreement, dated March 1, 1999 by and between Quicksilver Resources Inc. and Reliant Energy Services, Inc. (filed as Exhibit 10.10 to the Company’s Form S-1 File No. 333-89229, filed October 18, 1999 and included herein by reference).

10.2		Wells Agreement, (filed as an exhibit to the Registration Statement on Form S-4 File No. 333-29769, and included herein by reference).

+10.3		Quicksilver Resources Inc. 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.28 to the Company’s Form S-1 File No. 333-89229, filed October 18, 1999 and included herein by reference).

10.4		Fourth Amended and Restated Credit Agreement, dated as of May 13, 2002, among Quicksilver Resources Inc., as Borrower, Bank of America, N.A., as Administrative Agent, and the financial institutions listed therein (filed as Exhibit 10.6 to the Company’s Form 10-Q filed May 15, 2002 and included herein by reference).

*21.1		List of subsidiaries of Quicksilver Resources Inc.

*23.1		Consent of Deloitte & Touche LLP

*23.2		Consent of Holditch-Reservoir Technologies Consulting Services

*23.3		Consent of Nertherland, Sewell & Associates, Inc.

*99.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*99.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Signature	Title	Date

/s/ THOMAS F. DARDEN Thomas F. Darden	Chairman of the Board	March 26, 2003

/s/ GLENN DARDEN Glenn Darden	President, Chief Executive Officer and Director	March 26, 2003

/s/ BILL LAMKIN Bill Lamkin	Executive Vice President and Chief Financial Officer	March 26, 2003

/s/ D. WAYNE BLAIR D. Wayne Blair	Vice President and Controller	March 26, 2003

/s/ ANNE DARDEN SELF Anne Darden Self	Vice President—Human Resources And Director	March 26, 2003

/s/ JAMES A. HUGHES James A. Hughes	Director	March 26, 2003

/s/ D. RANDALL KENT D. Randall Kent	Director	March 26, 2003

/s/ STEVEN M. MORRIS Steven M. Morris	Director	March 26, 2003

/s/ W. YANDELL ROGERS, III W. Yandell Rogers, III	Director	March 26, 2003

/s/ MARK WARNER Mark Warner	Director	March 26, 2003