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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

OR

¨    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             .

Commission file number: 001-14837

QUICKSILVER RESOURCES INC.

(Exact name of registrant as specified in its charter)

777 West Rosedale, Suite 300,

Fort Worth, Texas 76104

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (817) 665-5000

Securities registered pursuant to Section 12 (b) of the Act:

Securities registered pursuant to Section 12 (g) of the Act:    None

Indicate by check mark whether the registrant 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.

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INDEX TO ANNUAL REPORT ON FORM 10-K

For the Year Ended December 31, 2002

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.

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PART I

ITEM 1.    Business

We are an independent oil and gas company engaged in the exploration, acquisition, development, production and sale of natural gas, crude oil and natural gas liquids (“NGLs”) primarily from unconventional reservoirs such as fractured shales, coal beds and tight sands. 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.

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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.

Business Strategy

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.

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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.

Marketing

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.

Competition

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.

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Governmental Regulation

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.

Environmental Matters

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.

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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.

Employees

As of March 3, 2003, we had 243 full time employees and 4 part time employees, including officers.

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Executive 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.

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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.

Risk Factors

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.

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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

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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.

Our key assets are concentrated in a small geographic area.

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.

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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 may have difficulty financing our planned growth.

We have experienced and expect to continue to experience substantial capital expenditure and working capital needs, particularly as a result of our property 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.

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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.

We cannot control the activities on properties we do not operate.

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

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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:

The loss of key personnel could adversely affect our ability to operate.

Our operations are dependent on a relatively small group of key management and technical personnel. We cannot assure you that these individuals will remain with us for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us.

Competition in our industry is intense, and we are smaller and have a more limited operating history than most of our competitors.

We compete with major and independent oil and gas companies for property acquisitions. We also compete for the equipment and labor required to operate and develop these properties. Many of our competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be able to absorb the burden of any changes in federal, state, provincial and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and productive 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.

Leverage materially affects our operations.

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:

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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.

Hedging our production may result in losses.

To reduce our exposure to fluctuations in the prices of natural gas and crude oil, we have entered into long-term natural gas and crude oil hedging arrangements. These hedging arrangements expose us to risk of financial loss in some circumstances, including the following:

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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.

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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

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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.

Internet Website

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.

ITEM 2.    Properties

We own significant natural gas and crude oil production interests in the following geographic areas:

Michigan

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.

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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.

Indiana

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.

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Canada

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.

Rocky Mountain Region

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.

Oil and Gas Reserves

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.

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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.

Volumes, Sales Prices and Oil and Gas Production Expense

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.

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Development, Exploration and Acquisition Capital Expenditures

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):

Productive Oil and Gas Wells

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

Oil and Gas Acreage

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.

Drilling Activity

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

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ITEM 3.    Legal Proceedings

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.

ITEM 4.    Submission of Matters to a Vote of Security Holders

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

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PART II.

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

Comparative Market Data

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.

Equity Compensation Plan Information

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

ITEM 6.    Selected Financial Data

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

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

Selected Financial Data

(in thousands, except for per share data)

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

Forward-Looking Information

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:

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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.

CRITICAL ACCOUNTING POLICIES

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.

Oil and Gas Properties

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.

Revenue Recognition

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.

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Hedging

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.

Income Taxes

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.

Off-Balance Sheet Arrangements

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.

RESULTS OF OPERATIONS

Summary Financial Data

Year Ended December 31, 2002 Compared with December 31, 2001

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.

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Operating Revenues

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.

Gas, Oil and Related Product Sales

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.

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Other Revenues

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

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

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 and Depreciation

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.

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General and Administrative Expenses

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

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 and Other Income/ Expense

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.

Income Taxes

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.

Summary Financial Data

Year Ended December 31, 2001 Compared with December 31, 2000

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.

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Operating Revenues

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.

Gas, Oil and Related Product Sales

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.

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Other Revenues

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

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

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

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 and Depreciation

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.

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General and Administrative Expenses

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 and Other Income/ Expense

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.

Income Taxes

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.

LIQUIDITY AND CAPITAL RESOURCES

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

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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.

Capital expenditures