Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

For the Fiscal Year Ended December 31, 2002

Commission File No. 1-13726

Chesapeake Energy Corporation

(Exact Name of Registrant as Specified in Its Charter)

(405) 848-8000

Registrant’s telephone number, including area code

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

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

None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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 ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). YES x NO ¨

The aggregate market value of our common stock held by non-affiliates on June 30, 2002 was $1,054,315,346. At February 24, 2003, there were 190,782,300 shares of common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of our definitive proxy statement for the 2003

annual meeting of shareholders are incorporated by reference in Part III

Index to Financial Statements

AMENDMENT NO. 1

EXPLANATORY NOTE

As described in Note 16 to the Consolidated Financial Statements, Chesapeake Energy Corporation has revised its previously reported Consolidated Statements of Operations and has made the corresponding revisions to the Notes to Consolidated Financial Statements for the years ended December 31, 2002 and 2001. The revisions had no effect on previously reported net income or net income per share.

Corresponding changes resulting from these revisions of classifications in the financial statements were also made to Item 1. “Business”, Item 6. “Selected Financial Data”, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8. “Financial Statements and Supplementary Data”.

In light of the refiling of this report for the purpose of revising the financial statements, we have also revised other disclosures from the original filing in response to comments of the staff of the Securities and Exchange Commission.

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PART I

ITEM 1. Business

General

We are one of the ten largest independent natural gas producers in the United States in terms of natural gas produced. Chesapeake began operations in 1989 and completed its initial public offering in 1993. Our common stock trades on the New York Stock Exchange under the symbol CHK. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at that location is (405) 848-8000. We make available free of charge on our website at www.chkenergy.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

At the end of 2002, we owned interests in approximately 10,700 producing oil and gas wells. Our primary operating area is the Mid-Continent region of the United States, which includes Oklahoma, western Arkansas, southwestern Kansas and the Texas Panhandle. Other operating areas include the Deep Giddings field in Texas, a portion of the Permian Basin region of southeastern New Mexico and a portion of the Williston Basin located in eastern Montana and western North Dakota. The following table highlights our growth since 1997:

Recent Developments

On January 31, 2003, we completed the acquisition of Mid-Continent gas assets from a wholly-owned subsidiary of Tulsa-based ONEOK, Inc. for $300 million. Based on internal reservoir engineering estimates, we believe the acquisition adds approximately 200 bcfe of proved reserves. The acquisition was funded with proceeds generated from the company’s December 2002 issuance of 23 million common shares at $7.50 per share and $150 million of 7.75% senior notes.

In September 2002, we announced our intention to dispose of our assets in the Permian Basin, either by a cash sale or an exchange of Mid-Continent properties. We have decided not to divest the Permian Basin assets as a result of recent favorable drilling results and higher oil and gas prices.

On February 24, 2003, we announced that we had entered into an agreement to acquire El Paso Corporation’s Anadarko Basin assets in western Oklahoma and the Texas Panhandle for $500 million, which, by our internal estimates, will add approximately 328 bcfe to our estimated proved reserves and approximately 67 mmcfe to our daily production. We expect to close the El Paso acquisition in March 2003. However, there is no assurance that this acquisition will be completed or that our estimates of the reserves being acquired will prove correct.

On February 24, 2003, we announced that we had entered into an agreement to acquire Vintage Petroleum, Inc.’s assets in the Bray field in southern Oklahoma for $30 million, which, by our internal estimates, will add approximately 22 bcfe to our estimated proved reserves and approximately 3.5 mmcfe to our daily production. We expect to close the Vintage acquisition in March 2003. However, there is no assurance that this acquisition will be completed or that our estimates of the reserves being acquired will prove correct.

On February 25, 2003, we announced a proposed private placement of $300 million in aggregate principal amount of senior notes, a proposed public offering of 20,000,000 shares of common stock pursuant to our existing shelf registration statement and a proposed private placement of $200 million of convertible preferred stock. There is no assurance these proposed offerings will be completed or, if they are completed, that they will be completed for the amount contemplated.

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Business Strategy

From our inception in 1989, our business goal has been to create value for our investors by building one of the largest onshore natural gas resource bases in the United States. Since 1998, our business strategy to achieve this goal has been to integrate our aggressive and technologically advanced Mid-Continent drilling program with a Mid-Continent focused producing property consolidation program. We believe this balanced business strategy enables us to achieve greater economies of scale, increase our undrilled acreage inventory and attract and retain talented and motivated land, geoscientific and engineering personnel. We are executing our strategy by:

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Based on our view that natural gas has become the fuel of choice to meet growing power demand and increasing environmental concerns in the United States, we believe our Mid-Continent focused natural gas development strategy should provide substantial growth opportunities in the years ahead. Although U.S. gas production has declined in each of the past six quarters, we have increased our production in each of those quarters. Our goal is to increase our overall production by 10% to 15% per year, with approximately one-third of this growth projected to be generated through the drillbit and the remainder from acquisitions.

Company Strengths

We believe the following six characteristics distinguish our past performance and future growth potential from other natural gas producers:

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Drilling Activity

The following table sets forth the wells we drilled during the periods indicated. In the table, “gross” refers to the total wells in which we had a working interest and “net” refers to gross wells multiplied by our working interest.

At December 31, 2002, we had 53 (22.4 net) wells in process. We have a fleet of six rigs which are dedicated to drilling wells operated by Chesapeake. Our drilling business is conducted through our wholly owned subsidiary, Nomac Drilling Corporation.

Well Data

At December 31, 2002, we had interests in approximately 10,700 (4,250 net) producing wells, including properties in which we held an overriding royalty interest, of which 350 (200 net) were classified as primarily oil producing wells and 10,350 (4,050 net) were classified as primarily gas producing wells. Chesapeake operates approximately 4,600 of the total 10,700 producing wells. We operate approximately 77% of our proved reserves by volume.

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Production, Sales, Prices and Expenses

The following table sets forth information regarding the production volumes, oil and gas sales, average sales prices received and expenses for the periods indicated:

In October 2001, we sold our Canadian subsidiary for approximately $143.0 million.

Proved Reserves

The following table sets forth our estimated proved reserves and the present value of the proved reserves (based on our weighted average wellhead prices at December 31, 2002 of $30.18 per barrel of oil and $4.28 per mcf of gas). These prices were based on the cash spot prices for oil and natural gas at December 31, 2002.

As of December 31, 2002, the present value of our proved developed reserves as a percentage of total proved reserves was 77%, and the volume of our proved developed reserves as a percentage of total proved reserves was 74%. Natural gas reserves accounted for 90% of total proved reserves at December 31, 2002.

Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. A change in price of $0.10 per mcf for natural gas and $1.00 per barrel for oil would result in a change in our December 31, 2002 present value of proved reserves of approximately $99 million and $19 million, respectively.

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Development, Exploration, Acquisition and Divestiture Activities

The following table sets forth historical cost information regarding our development, exploration, acquisition and divestiture activities during the periods indicated:

Acreage

The following table sets forth as of December 31, 2002 the gross and net acres of both developed and undeveloped oil and gas leases which we hold. “Gross” acres are the total number of acres in which we own a working interest. “Net” acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our options to acquire additional leasehold which have not been exercised.

Marketing

Chesapeake’s oil production is sold under market sensitive or spot price contracts. Our natural gas production is sold to purchasers under percentage-of-proceeds or percentage-of-index contracts and by direct marketing to end users or aggregators. By the terms of the percentage-of-proceeds contracts, we receive a percentage of the resale price received by the purchaser for sales of residue gas and natural gas liquids recovered after gathering and processing our gas. These purchasers sell the residue gas and natural gas liquids based primarily on spot market prices. The revenue we receive from the sale of natural gas liquids is included in natural gas sales. Under percentage-of-index contracts, the price per mmbtu we receive for our gas at the wellhead is tied to indexes published in Inside FERC or Gas Daily. During 2002, sales to Continental Natural Gas and Duke Energy Field Services of $90.2 million and $71.4 million, respectively, accounted for 22% of our total revenues. Management believes that the loss of one of these customers would not have a material adverse effect on our results of operations or our financial position. Other than the purchasers noted above, no other customer accounted for more than 10% of total revenues in 2002.

Chesapeake Energy Marketing, Inc., a wholly-owned subsidiary, provides marketing services, including commodity price structuring, contract administration and nomination services for Chesapeake and its partners. CEMI is a reportable segment under SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information. See note 8 of notes to consolidated financial statements in Item 8.

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Hedging Activities

We utilize hedging strategies to hedge the price of a portion of our future oil and natural gas production and from time to time to manage interest rate exposure. See Item 7A—Quantitative and Qualitative Disclosures About Market Risk.

Risk Factors

You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities.

Oil and gas prices are volatile. A decline in prices could adversely affect our financial results, cash flows, access to capital and ability to grow.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and gas properties depend primarily upon the prices we receive for the oil and gas we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks is subject to periodic redeterminations based on prices specified by our bank group at the time of redetermination. In addition, we may have ceiling test write-downs in the future if prices fall significantly.

Historically, the markets for oil and gas have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil and gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and other factors that are beyond our control, including:

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and gas price movements with any certainty. Declines in oil and gas prices would not only reduce revenue, but could reduce the amount of oil and gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. Further, oil and gas prices do not necessarily move in tandem. Because approximately 90% of our proved reserves are currently natural gas reserves, we are more affected by movements in natural gas prices.

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Our level of indebtedness and preferred stock may adversely affect operations and limit our growth, and we may have difficulty making debt service and preferred stock dividend payments on our indebtedness and preferred stock as such payments become due.

As of December 31, 2002, we had long-term indebtedness of $1.7 billion, none of which was bank indebtedness. As of February 21, 2003, we had long-term indebtedness of $1.76 billion, $104 million of which was bank indebtedness. As of March 31, 2003, we had $1.98 billion in long-term indebtedness, none of which was bank indebtedness, plus preferred stock outstanding having an aggregate liquidation preference of $349.9 million. Our long-term indebtedness represented 65% of our total book capitalization at December 31, 2002. We expect to be highly leveraged in the foreseeable future.

Our level of indebtedness and preferred stock affects our operations in several ways, including the following:

We may incur additional debt, including significant secured indebtedness, in order to make future acquisitions or to develop our properties. A higher level of indebtedness increases the risk that we may default on our existing debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. 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, the value of our assets and our performance at the time we need capital.

In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Our industry is extremely competitive.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial and other resources than we do.

We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation, exploration and production. We face intense competition from both major and other independent oil and natural gas companies in each of the following areas:

Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop and exploit our oil and natural gas properties and to acquire

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additional properties in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

Our commodity price risk management activities may reduce the realized prices received for our oil and gas sales.

In order to manage our exposure to price volatility in marketing our oil and gas, we enter into oil and gas price risk management arrangements for a portion of our expected production. Commodity price risk management transactions may limit the prices we actually realize; and we may experience reductions in oil and gas revenues from our commodity price risk management activities in the future. The estimated fair value of our oil and gas derivative instruments outstanding as of February 20, 2003 is a liability of approximately $64 million. In addition, our commodity price risk management transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

Some of our commodity price and interest rate risk management arrangements require us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations exceed certain levels. As of December 31, 2002, we were required to post a total of $24.5 million of collateral with two of our counterparties through letters of credit issued under our bank credit facility. As of February 21, 2003, we were required to post a total of $57.0 million of collateral. Future collateral requirements are uncertain and will depend on arrangements with our counterparties, highly volatile natural gas and oil prices and fluctuations in interest rates.

The actual quantities and present value of our proved reserves may prove to be lower than we have estimated.

This report contains estimates of our proved reserves and the estimated future net revenues from our proved reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.

At December 31, 2002, approximately 26% of our estimated proved reserves by volume were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. These reserve estimates include the assumption that we will make significant capital expenditures to develop the reserves, including $248 million in 2003. You should be aware that the estimated costs may not be accurate, development may not occur as scheduled and results may not be as estimated.

You should not assume that the present values referred to in this document represent the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The December 31, 2002 present value is based on weighted average oil and gas prices of $30.18 per barrel of oil and $4.28 per mcf of natural gas. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.

Any changes in consumption by oil and gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows.

The timing of both the production and the costs for the development and production of oil and gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the accuracy of the 10% discount factor.

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We may not have funds sufficient to make the significant capital expenditures required to replace our reserves.

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, our bank credit facility and debt and equity issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas, and our success in developing and producing new reserves. If revenue were to decrease as a result of lower oil and gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves. If our cash flows from operations are not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt, debt or equity or other methods of financing to meet these requirements.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves will decline over time. In addition, approximately 26% of our total estimated proved reserves by volume at December 31, 2002 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We may not be able to successfully find and produce reserves economically in the future. In addition, we may not be able to acquire proved reserves at acceptable costs.

Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.

Our recent growth is due in part to acquisitions of exploration and production companies and producing properties. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are uncertain and beyond our control. These factors include recoverable reserves, exploration potential, future oil and gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties, which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise.

We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, competition for producing oil and gas properties is intense and many of our competitors have financial and other resources that are substantially greater than those available to us. Therefore, we may not be able to acquire oil and gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. For example, we might decide to pursue acquisitions or properties located in geographic regions other than the Mid-Continent region. To the extent that such acquired properties are substantially different from our existing properties, our ability to efficiently realize the economic benefits of such transactions may be limited.

Future price declines may result in a writedown of our asset carrying values.

We utilize the full cost method of accounting for costs related to our oil and gas properties. Under this method, all such costs (for both productive and nonproductive properties) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. However, these capitalized costs are subject to a ceiling test which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the prices for oil and gas at that date. A significant decline in oil and gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future write-down of capitalized costs and a non-cash charge against future earnings.

Oil and gas drilling and producing operations are hazardous and expose us to environmental liabilities.

Oil and gas operations are subject to many risks, including well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental

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hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these risks occur, we could sustain substantial losses as a result of:

Our liability for environmental hazards includes those created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. We maintain insurance against some, but not all, of the risks described above. Our insurance may not be adequate to cover casualty losses or liabilities. Also, in the future we may not be able to continue to obtain insurance at premium levels that justify its purchase.

Exploration and development drilling may not result in commercially productive reserves.

We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

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

We depend, and will continue to depend in the foreseeable future, on the services of our officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties, marketing oil and gas production, and developing and executing financing and hedging strategies. Our ability to retain our officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. We do not maintain key person life insurance on any of our personnel.

Lower oil and gas prices could negatively impact our ability to borrow.

Our current bank credit facility limits our borrowings to a borrowing base of $250 million as of December 31, 2002. The borrowing base is determined periodically at the discretion of a majority of the banks and is based in part on oil and gas prices. Additionally, some of our indentures contain covenants limiting our ability to incur indebtedness in addition to that incurred under our bank credit facility. These indentures limit our ability to incur additional indebtedness unless we meet one of two alternative tests. The first alternative is based on a percentage of our adjusted consolidated net tangible assets, which is determined using discounted future net revenues from proved oil and gas reserves as of the end of each year. As of December 31,

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2002, we cannot incur additional indebtedness under this first alternative of the debt incurrence test. The second alternative is based on the ratio of our adjusted consolidated EBITDA to our adjusted consolidated interest expense over a trailing twelve-month period. As of December 31, 2002, we are permitted to incur significant additional indebtedness under this second alternative of the debt incurrence test. Lower oil and gas prices in the future could reduce our adjusted consolidated EBITDA, as well as our adjusted consolidated net tangible assets, and thus could reduce our ability to incur additional indebtedness.

Our oil and gas marketing activities may expose us to claims from royalty owners.

In addition to marketing our own oil and gas production, our marketing activities include marketing oil and gas production for working interest owners and royalty owners in the wells that we operate. These activities include the operation of gathering systems and the sale of oil and natural gas under various arrangements. Royalty owners have commenced litigation against a number of companies in the oil and gas production business claiming that amounts paid for production attributable to the royalty owners’ interest violated the terms of the applicable leases and state law, that deductions from the proceeds of oil and gas production were unauthorized under the applicable leases and that amounts received by upstream sellers should be used to compute the amounts paid to the royalty owners. Chesapeake presently is a defendant in four such cases commenced as class action suits. As new cases are decided and the law in this area continues to develop, our liability relating to the marketing of oil and gas may increase.

Regulation

General. The oil and gas industry is subject to regulation at the federal, state and local level, and some of the laws, rules and regulations that govern our operations carry substantial penalties for noncompliance. This regulatory burden increases our cost of doing business and, consequently, affects our profitability.

Exploration and Production. Our operations are subject to various types of regulation at the U.S. federal, state and local levels. Such regulation includes requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation are:

Our operations are also subject to various conservation regulations. These include the regulation of the size of drilling and spacing units (regarding the density of wells which may be drilled in a particular area) and the unitization or pooling of oil and gas properties. In this regard, some states, such as Oklahoma, allow the forced pooling or integration of tracts to facilitate exploration, while other states, such as Texas, rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and, therefore, more difficult to fully develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amount of oil and gas we can produce and to limit the number of wells or the locations at which we can drill.

We do not anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position.

Environmental Regulation. Various federal, state and local laws and regulations concerning the discharge of contaminants into the environment, the generation, storage, transportation and disposal of contaminants, and the protection of public health, natural resources, wildlife and the environment affect our exploration, development and production operations. We must take into account the cost of complying with environmental regulations in planning, designing, drilling, operating and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production

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waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. In addition, our operations require us to obtain permits for, among other things,

Under state and federal laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us or prior owners or operators in accordance with current laws or otherwise, to suspend or cease operations in contaminated areas, or to perform remedial plugging operations to prevent future contamination. The Environmental Protection Agency and various state agencies have limited the disposal options for hazardous and nonhazardous wastes. The owner and operator of a site, and persons that treated, disposed of or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. The Environmental Protection Agency, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements.

Federal and state occupational safety and health laws require us to organize information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.

We have made and will continue to make expenditures to comply with environmental regulations and requirements. These are necessary business costs in the oil and gas industry. Although we are not fully insured against all environmental risks, we maintain insurance coverage which we believe is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental laws and regulations, as well as claims for damages to property or persons resulting from company operations, could result in substantial costs and liabilities, including civil and criminal penalties, to Chesapeake. We believe we are in substantial compliance with existing environmental regulations, and that, absent the occurrence of an extraordinary event the effect of which cannot be predicted, any noncompliance will not have a material adverse effect on our operations or earnings.

Income Taxes

At December 31, 2002, Chesapeake had federal income tax net operating loss (NOL) carryforwards of approximately $653 million. Additionally, we had approximately $300 million of alternative minimum tax (AMT) NOL carryforwards available as a deduction against future AMT income and approximately $8 million of percentage depletion carryforwards. The NOL carryforwards expire from 2010 through 2022. The value of these carryforwards depends on the ability of Chesapeake to generate taxable income. In addition, for AMT purposes, only 90% of AMT income in any given year may be offset by AMT NOLs.

The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake.

In the event of an ownership change (as defined for income tax purposes), Section 382 of the Code imposes an annual limitation on the amount of a corporation’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of the company multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains (as defined in the Code) inherent in the assets sold. Chesapeake had an ownership change in March 1998 which triggered a limitation. Certain NOLs acquired through various acquisitions are also subject to limitations. Of the

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Index to Financial Statements

$653 million NOLs and $300 million AMT NOLs, $346 million and $83 million, respectively, are limited under Section 382. Therefore, $307 million of the NOLs and $217 million of the AMT NOLs are not subject to the limitation. The utilization of $346 million of the NOLs and the utilization of $83 million of the AMT NOLs subject to the Section 382 limitation are limited to approximately $41 million and $15 million, respectively, each taxable year. Although no assurances can be made, we do not believe that an additional ownership change has occurred as of December 31, 2002. Equity transactions after the date hereof by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs.

In the event of another ownership change, the amount of Chesapeake’s NOLs available for use each year will depend upon future events that cannot currently be predicted and upon interpretation of complex rules under Treasury regulations. If less than the full amount of the annual limitation is utilized in any given year, the unused portion may be carried forward and may be used in addition to successive years’ annual limitation.

We expect to utilize our NOL carryforwards and other tax deductions and credits to offset taxable income in the future. However, there is no assurance that the Internal Revenue Service will not challenge these carryforwards or their utilization.

In 2002, the Internal Revenue Service completed an audit of Chesapeake for the years ended December 31, 1999 and 2000. There were no significant adjustments resulting from this audit.

Title to Properties

Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and gas industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and gas industry. Nevertheless, we are involved in title disputes from time to time which result in litigation. See Item 3—Legal Proceedings for a description of pending cases challenging certain of our oil and gas leasehold interests in the West Panhandle Field of Texas.

Operating Hazards and Insurance

The oil and gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. If any of these should occur, Chesapeake could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

Chesapeake maintains a $50 million oil and gas lease operator policy that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. There can be no assurance that this insurance will be adequate to cover any losses or exposure to liability. We also carry comprehensive general liability policies and a $75 million umbrella policy. We carry workers’ compensation insurance in all states in which we operate and a $1 million employment practice liability policy. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks.

Employees

Chesapeake had 866 employees as of December 31, 2002, which includes 123 employed by our drilling rig subsidiary, Nomac Drilling Corporation. No employees are represented by organized labor unions. We believe our employee relations are good.

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Index to Financial Statements

Glossary

The terms defined in this section are used throughout this Form 10-K.

Bcf. Billion cubic feet.

Bcfe. Billion cubic feet of gas equivalent.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Commercial Well; Commercially Productive Well. An oil and gas well which produces oil and gas in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry Hole; Dry Well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploratory Well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

Full Cost Pool. The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal Wells. Wells which are drilled at angles greater than 70 degrees from vertical.

Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.

Mbtu. One thousand btus.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet of gas equivalent.

Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.

Mmbtu. One million btus.

Mmcf. One million cubic feet.

Mmcfe. One million cubic feet of gas equivalent.

Net Acres or Net Wells. The sum of the fractional working interest owned in gross acres or gross wells.

NYMEX. New York Mercantile Exchange.

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Index to Financial Statements

Present Value or PV-10. When used with respect to oil and gas reserves, present value or PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

Productive Well. A well that is producing oil or gas or that is capable of production.

Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production responses that increased recovery will be achieved.

Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved Undeveloped Location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves may not include estimates attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Royalty Interest. An interest in an oil and gas property entitling the owner to a share of oil or gas production free of costs of production.

Standardized Measure of Discounted Future Net Cash Flows. The discounted future net cash flows relating to proved reserves based on year-end prices, costs and statutory tax rates (adjusted for permanent differences) and a 10-percent annual discount rate.

Tcf. One trillion cubic feet.

Tcfe. One trillion cubic feet of gas equivalent.

Undeveloped Acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Written Put Option. An option, exercisable by the buyer, to require the seller (writer) to sell a specified amount of a commodity at an agreed upon price and time. The buyer pays the seller (writer) a premium for entering into the transaction.

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Index to Financial Statements

ITEM 2. Properties

Chesapeake focuses its natural gas exploration, development and acquisition efforts in one primary operating area and in three secondary operating areas: (i) the Mid-Continent (consisting of Oklahoma, western Arkansas, southwestern Kansas and the Texas Panhandle), representing 86% of our proved reserves, (ii) the Gulf Coast region consisting primarily of the Deep Giddings Field in Texas and the Austin Chalk and Tuscaloosa Trends in Louisiana, representing 6% of our proved reserves, (iii) the Permian Basin region of southeastern New Mexico, representing 5% of our proved reserves and (iv) the Williston Basin of eastern Montana and western North Dakota, representing 3% of our proved reserves. In October 2001, we sold our Canadian subsidiary which included all of our Canadian properties and leasehold.

During the year ended December 31, 2002, we participated in 708 gross (279.2 net) wells, 269 of which we operated. A summary of our development, exploration, acquisition and divestiture activities by operating area is as follows:

Chesapeake’s proved reserves increased 24% during 2002 to an estimated 2,205 bcfe at December 31, 2002, compared to 1,780 bcfe of estimated proved reserves at December 31, 2001 (See note 11 of notes to consolidated financial statements in Item 8).

Chesapeake’s strategy for 2003 is to continue developing our natural gas assets through exploratory and developmental drilling and by selectively acquiring strategic properties in the Mid-Continent area. We have budgeted approximately $475 to $525 million for drilling, acreage acquisition, seismic and related capitalized internal costs, all of which is expected to be funded out of operating cash flow based on our current assumptions. Our budget is frequently adjusted based on changes in oil and gas prices, drilling results, drilling costs and other factors.

Primary Operating Area

Mid-Continent. Chesapeake’s Mid-Continent proved reserves of 1,903 bcfe represented 86% of our total proved reserves as of December 31, 2002, and this area produced 147.3 bcfe, or 81%, of our 2002 production. During 2002, we invested approximately $322.4 million to drill 673 (263.1 net) wells in the Mid-Continent. We anticipate spending approximately 90% to 95% of our total budget for exploration and development activities in the Mid-Continent region during 2003. We anticipate the Mid-Continent will contribute approximately 194 bcfe, or 84%, of expected total production during 2003. Substantially all of our budgeted production is expected to come from proved reserves estimated as of December 31, 2002.

Secondary Operating Areas

Gulf Coast. Chesapeake’s Gulf Coast proved reserves (consisting primarily of the Deep Giddings Field in Texas and the Austin Chalk and Tuscaloosa Trends in Louisiana) represented 142 bcfe, or 6%, of our total proved reserves as of December 31, 2002. During 2002, the Gulf Coast assets produced 23.3 bcfe, or 13%, of our total production. During 2002, we invested approximately $20.9 million to drill 13 (6.3 net) wells in the Gulf Coast. We anticipate the Gulf Coast will contribute approximately 26 bcfe, or 11%, of expected total production during 2003. Substantially all of our budgeted production is expected to come from proved reserves estimated as of December 31, 2002. We anticipate spending approximately 5% of our total budget for exploration and development activities in the Gulf Coast region during 2003.

Permian Basin. Chesapeake’s Permian Basin proved reserves (consisting primarily of the Lovington area in New Mexico) represented 113 bcfe, or 5%, of our total proved reserves as of December 31, 2002. During 2002, the Permian assets produced 7.6 bcfe, or 4%, of our total production. We anticipate the Permian Basin will contribute approximately 8 bcfe, or 3%, of expected total production during 2003. Substantially all of our budgeted production is expected to come from proved reserves estimated as of December 31, 2002. During 2002, we invested approximately $10.3 million to drill 19 (8.8 net) wells in the Permian Basin. For 2003, we anticipate spending approximately 2% of our total budget for exploration and development activities in the Permian Basin.

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Index to Financial Statements

In September 2002, we announced our intention to dispose of our assets in the Permian Basin, either by a cash sale or an exchange for Mid-Continent properties. We have decided not to divest the Permian Basin assets as a result of recent favorable drilling results and higher oil and gas prices.

Williston Basin. Chesapeake’s Williston Basin proved reserves represented 38 bcfe, or 2%, of our total proved reserves as of December 31, 2002. During 2002, the Williston assets produced 3.2 bcfe, or 2%, of our total production. We anticipate the Williston Basin will contribute approximately 4 bcfe, or 2%, of expected total production during 2003. Substantially all of our budgeted production is expected to come from proved reserves estimated as of December 31, 2002. During 2002, we invested approximately $4.4 million to drill 3 (1.0 net) wells in the Williston Basin. For 2003, we have not budgeted any exploration and development activities in the Williston Basin.

Oil and Gas Reserves

The tables below set forth information as of December 31, 2002 with respect to our estimated proved reserves, the associated estimated future net revenue and the present value at such date. Ryder Scott Company L.P. evaluated 20%, Lee Keeling and Associates evaluated 23%, Netherland, Sewell & Associates, Inc. evaluated 20% and Williamson Petroleum Consultants, Inc. evaluated 10% of our combined discounted future net revenues from our estimated proved reserves at December 31, 2002. The remaining 27% was evaluated internally by our engineers. All estimates were prepared based upon a review of production histories and other geologic, economic, ownership and engineering data we developed. The present value of estimated future net revenue shown is not intended to represent the current market value of the estimated oil and gas reserves we own.

The future net revenue attributable to our estimated proved undeveloped reserves of $1.5 billion at December 31, 2002, and the $868 million present value thereof, have been calculated assuming that we will expend approximately $570 million to develop these reserves. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, product prices and the availability of capital.

No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission.

Chesapeake’s ownership interest used in calculating proved reserves and the associated estimated future net revenue were determined after giving effect to the assumed maximum participation by other parties to our farmout and participation agreements. The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for oil and gas production sold subsequent to December 31, 2002. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices.

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Index to Financial Statements

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond Chesapeake’s control. The reserve data represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the actual quantities of oil and gas that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and cost, that may not prove correct. The foregoing uncertainties are particularly true as to proved undeveloped reserves, which are inherently less certain than proved developed reserves and which comprise a significant portion of our proved reserves. In addition, the estimated future net revenue from proved reserves and the associated present value does not include any estimates of corporate overhead, debt service costs, future income tax expense, or depreciation, depletion and amortization expense.

See Item 1 “Business” and note 11 of notes to consolidated financial statements included in Item 8 for a description of drilling, production and other information regarding our oil and gas properties.

Facilities

Chesapeake owns an office building complex in Oklahoma City and field offices in Lindsay, Waynoka, and Weatherford, Oklahoma; Garden City, Kansas; Borger, Dumas and College Station, Texas; and Eunice and Hobbs, New Mexico. In addition, Chesapeake leases field office space in Forgan, Kingfisher, Sayre and Wilburton, Oklahoma; Navasota, Texas; and Dickinson, North Dakota. Chesapeake owns 40 different gas gathering and processing facilities located in Oklahoma, Kansas and Louisiana.

ITEM 3. Legal Proceedings

We are currently involved in various routine disputes incidental to our business operations. We believe that the final resolution of such currently pending or threatened litigation is not likely to have a material adverse effect on our financial position or results of operations. In addition, the following matters are pending:

One of our subsidiaries has been a defendant in 16 lawsuits filed between June 1997 and December 2001 by royalty owners seeking the termination of certain of our gas leases located in the West Panhandle Field in Texas. Because of inconsistent jury verdicts in four of the cases tried to date and because the amount of damages sought is not specified in all of the pending cases, the outcome of any future trials and appeals could not be predicted. As a result, management determined that these cases should be reported as material pending legal proceedings, and we have done so beginning with our Form 10-Q for the quarter ended June 30, 1999. Management has reevaluated the risk of liability posed by these cases primarily as a result of a recent decision by the Texas Supreme Court interpreting a lease provision similar to the lease provision at issue in our litigation. In light of this decision, management has concluded that the damages, if any, that might be awarded to plaintiffs in the lease cessation cases pending against us would not have a material adverse effect on our financial position or results of operations. Because our assessment of the lease cessation cases has changed, we have reversed approximately $3 million of the reserve previously established in connection with these cases as a reduction to general and administrative expenses during 2002.

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

Not applicable.

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Index to Financial Statements

PART II

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

Price Range of Common Stock

Our common stock trades on the New York Stock Exchange under the symbol “CHK.” The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the New York Stock Exchange:

At February 24, 2003 there were 1,177 holders of record of our common stock and approximately 48,000 beneficial owners.

Dividends

On September 20, 2002, our board of directors declared a $0.03 per share dividend on our common stock which was paid in October 2002. On December 20, 2002, our board of directors declared a $0.03 per share dividend on our common stock which was paid on January 15, 2003. Prior to the October dividend, we had not paid a dividend on our common stock since 1998. While we expect to continue to pay dividends on our common stock, the payment of future cash dividends will depend upon, among other things, our financial condition, funds from operations, the level of our capital and development expenditures, our future business prospects, any contractual restrictions and any other factors considered relevant by the board of directors.

Our revolving credit agreement limits the amount of cash dividends we may pay to $25.0 million per year, excluding dividends on our 6.75% cumulative convertible preferred stock. Four of the indentures governing our outstanding senior notes contain restrictions on our ability to declare and pay cash dividends. Under these indentures, we may not pay any cash dividends on our common or preferred stock if an event of default has occurred, if we have not met one of the two debt incurrence tests described in the indentures, or if immediately after giving effect to the dividend payment, we have paid total dividends and made other restricted payments in excess of the permitted amounts. As of December 31, 2002, our coverage ratio for purposes of the debt incurrence test was 2.9 to 1, compared to 2.25 to 1 required in our indentures.

ITEM 6. Selected Financial Data

The following table sets forth selected consolidated financial data of Chesapeake for the twelve months ended December 31, 2002, 2001, 2000, 1999 and 1998. The data are derived from our audited consolidated financial statements revised to reflect the reclassification of certain items, as more fully described in Note 16 of Notes to Consolidated Financial Statements. Our acquisition of Gothic Energy Corporation in the first quarter of 2001, and the divestiture of our Canadian assets in October 2001, materially affect the comparability of the selected financial data for 2001 and 2000. The Gothic acquisition was accounted for using the purchase method. The table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements, including the notes, appearing in Items 7 and 8 of this report.

22

Index to Financial Statements