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Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the Fiscal Year Ended December 31, 2004

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  x

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, 2004 was $3,229,393,436. At March 2, 2005, there were 314,122,017 shares of common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the 2005 Annual Meeting of Shareholders are incorporated by reference in Part III.

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PART I

ITEM 1.    Business

General

We are one of the four largest independent producers of natural gas in the U.S. and own interests in approximately 20,000 producing oil and gas wells. Our proved oil and natural gas reserves as of December 31, 2004 were approximately 4.9 tcfe. At December 31, 2004, approximately 89% of our proved reserves (by volume) were natural gas, and approximately 70% of our proved oil and natural gas reserves were located in our primary operating area-the Mid-Continent region of the United States, which includes Oklahoma, western Arkansas, southwestern Kansas and the Texas Panhandle. In addition, we are building significant secondary operating areas in the South Texas and Texas Gulf Coast region, the Permian Basin of western Texas and eastern New Mexico and in the Ark-La-Tex area of central and eastern Texas and northern Louisiana.

From January 1, 1998 through December 31, 2004, we have been one of the most active consolidators of onshore U.S. natural gas assets, having purchased approximately 3.8 tcfe of proved reserves at a total cost of approximately $4.5 billion (excluding $851 million of unproved properties as well as $558 million of deferred taxes in connection with certain corporate acquisitions).

During 2004, we remained active in the acquisitions market. Acquisition expenditures totaled $2.0 billion in 2004 (excluding $464 million of deferred taxes in connection with certain corporate acquisitions). Through our completed 2004 acquisitions, we acquired an internally estimated 1,137 bcfe of proved oil and natural gas reserves at a cost of $1.36 per mcfe (excluding $0.41 per mcfe of deferred taxes in connection with certain corporate acquisitions).

During 2004, we drilled 561 (425 net) operated wells and participated in another 890 (121 net) wells operated by other companies. The company’s success rate was 96% for both operated and non-operated wells. Through our exploration and development operations, we added approximately 962 bcfe of proved oil and gas reserves. As of December 31, 2004, our proved developed producing reserves were 66% of our total proved reserves. In 2004, we invested $299.8 million in leasehold (exclusive of leases acquired through acquisitions) and 3-D seismic data.

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. References to “us”, “we” and “our” in this report refer to Chesapeake Energy Corporation together with its subsidiaries.

Recent Developments

On January 28, 2005, we amended and restated our revolving bank credit facility, increasing the borrowing base to $1.25 billion and extending the maturity to January 2010.

On February 1, 2005, we acquired Mid-Continent and Ark-La-Tex natural gas and oil assets through the purchase of the stock of BRG Petroleum Corporation and the acquisition of various other partnership interests for cash consideration of approximately $325 million, of which $16.3 million was paid in 2004.

Business Strategy

Since the company’s inception in 1989, our goal has been to create value for our investors by building one of the largest onshore natural gas resource bases in the United States. For the past seven years, our strategy to

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accomplish this goal has been to build the dominant operating position in the Mid-Continent region, the third largest gas supply region in the U.S. In building this industry-leading position in the Mid-Continent, we have integrated an aggressive and technologically advanced drilling program with an active property consolidation program focused on small to medium-sized corporate and property acquisitions of up to $600 million. We are now building significant secondary operating areas in the South Texas and Texas Gulf Coast region, Permian Basin and Ark-La-Tex area. We believe significant elements of our successful Mid-Continent strategy can be transferred to these areas.

Key elements of this business strategy are further explained below:

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Based on our view that natural gas will be in a tight supply/high demand relationship in the U.S. during at least the next five years because of flat to declining supply and growing demand for this clean-burning, domestically-produced fuel, we believe our focused natural gas acquisition, exploitation and exploration strategy should provide substantial value-creating growth opportunities in the years ahead. Our goal is to increase our overall production by 10% to 20% per year, with growth at an annual rate of 10% generated organically through the drillbit and the remaining growth generated through future acquisitions. We have reached or exceeded this overall production goal in 10 of our 12 years as a public company.

Company Strengths

We believe the following six characteristics distinguish our past performance and differentiate our future growth potential from other independent 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.

The following table shows the wells we drilled by area:

At December 31, 2004, we had 114 (50 net) wells in process. We own 10 rigs which are dedicated to drilling wells operated by Chesapeake and 12 additional rigs are under construction or on order. Our drilling business is conducted through our wholly owned subsidiary, Nomac Drilling Corporation.

Well Data

At December 31, 2004, we had interests in approximately 19,800 (8,058 net) producing wells, including properties in which we held an overriding royalty interest, of which 2,900 (1,222 net) were classified as primarily oil producing wells and 16,900 (6,836 net) were classified as primarily gas producing wells. Chesapeake operates approximately 8,800 of its 19,800 producing wells. During 2004, we drilled 561 (425 net) wells and participated in another 890 (121 net) wells operated by other companies. We operate approximately 81% of our current daily production volumes.

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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:

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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, 2004 of $39.91 per barrel of oil and $5.65 per mcf of gas). These weighted average wellhead prices were based on the cash spot prices for oil and natural gas at December 31, 2004.

As of December 31, 2004, the present value of our proved developed reserves as a percentage of total proved reserves was 70%, and the volume of our proved developed reserves as a percentage of total proved reserves was 66%. Natural gas reserves accounted for 89% of the volume of total proved reserves at December 31, 2004.

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, 2004 present value of proved reserves of approximately $215 million and $40 million, respectively.

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:

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Our development and leasehold costs included $333 million, $229 million and $120 million of expenditures in 2004, 2003 and 2002, respectively, related to properties carried as proved undeveloped locations in the prior year’s reserve reports. Included in our reserve report as of December 31, 2004 are estimated future development costs of $1.9 billion related to the development of proved undeveloped reserves ($1.0 billion in 2005, $0.5 billion in 2006, $0.2 billion in 2007 and $0.2 billion in 2008 and beyond). Chesapeake’s developmental drilling schedules are subject to revision and reprioritization throughout the year, resulting from unknowable factors such as the relative success in an individual developmental drilling prospect leading to an additional drilling opportunity, rig availability, title issues or delays, and the effect that acquisitions may have on prioritizing development drilling plans.

Acreage

The following table sets forth as of December 31, 2004 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 generally sold under market sensitive or spot price contracts. Our natural gas production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. 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 transportation and processing of 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 oil sales. Under percentage-of-index contracts, the price per mmbtu we receive for our gas is tied to indexes published in Inside FERC or Gas Daily.

During 2004, sales to Eagle Energy Partners I, L.P. (“Eagle”) of $467 million accounted for 17% of our total revenues. Chesapeake owns approximately 31% of Eagle. Management believes that the loss of this customer would not have a material adverse effect on our results of operations or our financial position. No other customer accounted for more than 10% of total revenues in 2004.

Chesapeake Energy Marketing, Inc., which is our marketing subsidiary, provides marketing services, including commodity price structuring, contract administration and nomination services for Chesapeake and its partners. This subsidiary 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.

Hedging Activities

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

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Risk Factors

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

Our revenues, operating results, profitability and future rate of growth 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 89% of our reserves at December 31, 2004 are natural gas reserves, we are more affected by movements in natural gas prices.

Our level of indebtedness may limit our financial flexibility.

As of December 31, 2004, we had long-term indebtedness of $3.1 billion, with $59 million drawn under our revolving bank credit facility. Our long-term indebtedness represented 49% of our total book capitalization at December 31, 2004. We increased the borrowing base under our revolving bank credit facility to $1.25 billion on January 28, 2005, with approximately $437 million drawn as of March 2, 2005.

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

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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 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 redetermination. A lowering of our borrowing base could require us to repay indebtedness in excess of the borrowing base, or we might need to further secure the lenders with additional collateral.

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 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.

Significant capital expenditures are 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 revolving 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 flow from operations is not sufficient to meet our obligations and fund our capital expenditure budget, we may not be able to access debt, equity or other methods of financing on an economic basis to meet these requirements.

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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 and production will decline over time. In addition, approximately 34% of our total estimated proved reserves (by volume) at December 31, 2004 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. Our reserve estimates reflect that our production rate on producing properties will decline approximately 26% from the beginning until the end of 2005. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.

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, 2004, approximately 34% 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 these reserves, including $1.0 billion in 2005. 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 report 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, 2004 present value is based on weighted average oil and gas wellhead prices of $39.91 per barrel of oil and $5.65 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 expenses from 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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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, producing properties and undeveloped leasehold. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including estimates of 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. As a result of these factors, 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. It is our current intention to continue focusing on acquiring properties with development and exploration potential located in the Mid-Continent, the South Texas and Texas Gulf Coast region, the Permian Basin region and the Ark-La-Tex area. To the extent that we acquire properties substantially different from the properties in our operating regions or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as in our prior acquisitions.

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:

Future price declines may result in a write-down 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

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aggregate basis over the estimated lives of the properties using the unit-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, adjusted for the impact of derivatives accounted for as cash flow hedges. A significant decline in oil and gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future writedown of capitalized costs and a non-cash charge against future earnings. Our aggregate present value of future net revenues plus the value of the unproved properties would equal the recorded net book value of our oil and gas properties at December 31, 2004, assuming an index price of approximately $3.90 per mcf for gas and assuming the price of oil remains constant at $43.39 per barrel for oil. If index prices were to fall below these levels, we could experience a write-down of the book value of our oil and gas assets.

Our hedging activities may reduce the realized prices received for our oil and gas sales and require us to provide collateral for hedging liabilities.

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 hedging may limit the prices we actually realize and therefore reduce oil and gas revenues in the future. The fair value of our oil and gas derivative instruments outstanding as of December 31, 2004 was an asset of approximately $38.4 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 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, 2004, we were required to post a total of $66 million of collateral with our counterparties through letters of credit issued under our bank credit facility with respect to commodity price and financial risk management transactions. As of March 2, 2005, we were required to post a total of $61 million of collateral. Future collateral requirements are uncertain and will depend on arrangements with our counterparties, highly volatile natural gas and oil prices.

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

Our amended and restated revolving bank credit facility limits our borrowings to $1.25 billion, based on our borrowing base. 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 our adjusted consolidated net tangible assets (as defined in all of our indentures), which is determined using discounted future net revenues from proved oil and gas reserves as of the end of each year. The second alternative is based on the ratio of our adjusted consolidated EBITDA (as defined in all of our indentures) to our adjusted consolidated interest expense over a trailing twelve-month period. As of December 31, 2004 we were permitted to incur significant additional indebtedness under both of these debt incurrence tests. 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.

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Oil and gas drilling and producing operations can be hazardous and may 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 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 obtain insurance at premium levels that justify its purchase.

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

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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, including processing facilities. 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 waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. In addition, our operations may 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 well plugging operations or cleanups 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 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.

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Income Taxes

Chesapeake recorded income tax expense of $289.8 million in 2004 compared to income tax expense of $191.8 million in 2003 and $26.9 million in 2002. Our effective income tax rate decreased to 36% in 2004 compared to 38% in 2003 and 40% in 2002. The decrease in 2004 and 2003 reflected the impact state income taxes had on our overall effective rate. Our effective income tax rate will increase to 36.5% in 2005 to reflect our current assessment of the impact state income taxes and permanent differences will have on our overall effective income tax rate.

At December 31, 2004, Chesapeake had federal income tax net operating loss (NOL) carryforwards of approximately $546 million. We also had approximately $114 million of alternative minimum tax (AMT) NOL carryforwards available as a deduction against future AMT income and approximately $10 million of percentage depletion carryforwards. The NOL carryforwards expire from 2012 through 2024. The value of the remaining 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. Certain NOLs acquired through various acquisitions are also subject to limitations. The following table summarizes our net operating losses as of December 31, 2004 and any related limitations:

Although no assurances can be made, we do not believe that an ownership change has occurred as of December 31, 2004. Future equity transactions 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 an 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.

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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.

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 is no assurance that this insurance will be adequate to cover all losses or exposure to liability. Chesapeake also carries a $125 million comprehensive general liability umbrella policy and a $75 million pollution liability policy. We provide workers’ compensation insurance coverage to employees in all states in which we operate and we maintain 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 1,718 employees as of December 31, 2004, which includes 209 employed by our drilling 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 of Oil and Gas Terms

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.

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Index to Financial Statements

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 interests owned in gross acres or gross wells.

NYMEX.    New York Mercantile Exchange.

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.

Reserve Replacement.    Calculated by dividing the sum of reserve additions from all sources (revisions, extensions and acquisitions) by the actual production for the corresponding period. The values for these reserve additions are derived directly from the proved reserves table on page 94. Management uses the reserve replacement ratio as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production.

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

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Index to Financial Statements

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.

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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 70% of our proved reserves, (ii) the South Texas and Texas Gulf Coast region, representing 8% of our proved reserves, (iii) the Permian Basin of western Texas and eastern New Mexico, representing 10% of our proved reserves, and (iv) the Ark-La-Tex area of central and eastern Texas and northern Louisiana, representing 11% of our proved reserves.

During the year ended December 31, 2004, we participated in 1,451 gross (546 net) wells, 561 (425 net) 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 55% during 2004 to an estimated 4,902 bcfe at December 31, 2004, compared to 3,169 bcfe of estimated proved reserves at December 31, 2003. See note 11 of notes to our consolidated financial statements in Item 8 of this report.

Chesapeake’s strategy for 2005 is to continue developing our natural gas assets through exploratory and developmental drilling and by selectively acquiring strategic properties in the Mid-Continent and in our secondary areas. We project that our 2005 production will be between 430 bcfe and 438 bcfe. We have budgeted $1.4 to $1.5 billion for drilling, acreage acquisition, seismic and related capitalized internal costs, all of which is expected to be funded with 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. We expect to fund future acquisitions through a combination of operating cash flow, our revolving bank credit facility and new debt and equity issuances.

Primary Operating Area

Mid-Continent.    Chesapeake’s Mid-Continent proved reserves of 3,437 bcfe represented 70% of our total proved reserves as of December 31, 2004, and this area produced 268.5 bcfe, or 74%, of our 2004 production. We anticipate the Mid-Continent will contribute approximately 292 bcfe, or 67%, of expected total production during 2005. During 2004, we invested approximately $800.1 million to drill 1,195 (417 net) wells in the Mid-Continent. We anticipate spending approximately 58% of our total budget for exploration and development activities in the Mid-Continent region during 2005.

Secondary Operating Areas

South Texas and Texas Gulf Coast.    Chesapeake’s South Texas and Texas Gulf Coast proved reserves represented 390 bcfe, or 8%, of our total proved reserves as of December 31, 2004. During 2004, the South

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Index to Financial Statements

Texas and Texas Gulf Coast assets produced 42.4 bcfe, or 12%, of our total production. We anticipate this area will contribute approximately 58 bcfe, or 13%, of expected total production during 2005. During 2004, we invested approximately $113.9 million to drill 67 (38 net) wells in the South Texas and Texas Gulf Coast region. We anticipate spending approximately 13% of our total budget for exploration and development activities in the South Texas and Texas Gulf Coast region during 2005.

Permian Basin.    Chesapeake’s Permian Basin proved reserves represented 482 bcfe, or 10%, of our total proved reserves as of December 31, 2004. During 2004, the Permian assets produced 29.5 bcfe, or 8%, of our total production. We anticipate the Permian Basin will contribute approximately 34 bcfe, or 8%, of expected total production during 2005. During 2004, we invested approximately $98.9 million to drill 107 (55 net) wells in the Permian Basin. For 2005, we anticipate spending approximately 13% of our total budget for exploration and development activities in the Permian Basin.

Ark-La-Tex.    Chesapeake’s Ark-La-Tex proved reserves represented 547 bcfe, or 11%, of our total proved reserves as of December 31, 2004. During 2004, the Ark-La-Tex assets produced 19.6 bcfe, or 5%, of our total production. We anticipate the Ark-La-Tex will contribute approximately 48 bcfe, or 11%, of expected total production during 2005. During 2004, we invested approximately $73.6 million to drill 82 (36 net) wells in Ark-La-Tex. For 2005, we anticipate spending approximately 16% of our total budget for exploration and development activities in Ark-La-Tex.

Oil and Gas Reserves

The tables below set forth information as of December 31, 2004 with respect to our estimated proved reserves, the associated estimated future net revenue and the present value at such date. Chesapeake employed third party engineers to prepare independent reserve forecasts for approximately 75% of our proved reserves (by volume) and 76% (by value) at year-end 2004. These are not audits or reviews of internally prepared reserve reports. The company’s own estimates of the proved reserves evaluated by third party engineers were within 99% of the third party estimates. Netherland, Sewell & Associates, Inc. evaluated 25%, Lee Keeling and Associates, Inc. evaluated 23%, Ryder Scott Company L.P. evaluated 12%, LaRoche Petroleum Consultants, Ltd. evaluated 7%, H. J. Gruy and Associates, Inc. evaluated 7% and Miller and Lents, Ltd. evaluated 2% of our estimated proved reserves at December 31, 2004 based on discounted future net revenues. Of the 25,264 properties included in the 2004 report, the reserve estimates prepared by the independent firms covered 8,761 properties, or 34.7% of the total well count. Because of the time, effort and cost involved in preparing reserve estimates on every oil and gas property owned by Chesapeake, the company’s internal reservoir engineers evaluated many of the properties, but these represent only 24% of our proved reserves. All estimates were prepared based upon a review of production histories and other geologic, economic, ownership and engineering data we developed. The estimates are not based on any single significant assumption due to the diverse nature of the reserves and there is no significant concentration of proved reserves volume or value in any one well. 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.

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Index to Financial Statements

As of December 31, 2004, our reserve estimates included 1,683.3 bcfe of reserves classified as proved undeveloped (PUD). Of this amount, approximately 68% (by volume) were initially classified as PUDs in 2004, 11% were initially classified as PUDs in 2003, 6% were initially classified as PUDs in 2002, and the remaining 15% were initially classified as PUDs prior to 2002. Of our proved developed reserves, 413 bcfe are non-producing, which are primarily “behind pipe” zones in producing wells.

The future net revenue attributable to our estimated proved undeveloped reserves of $6.3 billion at December 31, 2004, and the $3.1 billion present value thereof, has been calculated assuming that we will expend approximately $1.9 billion 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, but we have projected to incur $1.0 billion in 2005, $0.5 billion in 2006, $0.2 billion in 2007 and $0.2 billion in 2008 and beyond. We do not believe any of these proved undeveloped reserves are contingent upon installation of additional infrastructure and we are not subject to regulatory approval other than routine permits to drill, which we expect to obtain in the normal course of business.

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 was 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, 2004. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices.

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 costs 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 do 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 of this report for a description of drilling, production and other information regarding our oil and gas properties.

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Index to Financial Statements

Facilities

Chesapeake owns an office complex in Oklahoma City and also owns field offices in Arkoma, Lindsay, Waynoka, Weatherford and Wilburton, Oklahoma; Garden City, Kansas; Borger, Dumas and College Station, Texas; Van Buren, Arkansas; Cheneyville, Louisiana; and Eunice and Hobbs, New Mexico. In addition, Chesapeake leases office space in Oklahoma City, Forgan, Kingfisher and Sayre, Oklahoma; Zapata, Texas; Dickinson, North Dakota and Shreveport, Louisiana. Chesapeake owns approximately 55 gas gathering and processing facilities located in Oklahoma, Kansas, Texas and Louisiana.

ITEM 3.    Legal Proceedings

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

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, Related Stockholder Matters and Issuer Purchases of Equity Securities

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 March 2, 2005 there were 1,265 holders of record of our common stock and approximately 140,000 beneficial owners.

Dividends

The following table sets forth the amount of dividends per share declared on Chesapeake common stock during the two years ended December 31:

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, contractual restrictions and any other factors considered relevant by the board of directors.

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, 2004, our coverage ratio for purposes of the debt incurrence test was 6.39 to 1, compared to 2.25 to 1 required in our indentures. Our adjusted consolidated net tangible assets exceeded 200% of our total indebtedness, as required in our indentures, by more than $2.2 billion.

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Index to Financial Statements

The following table presents information about repurchases of our common stock during the three months ended December 31, 2004:

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Index to Financial Statements

ITEM 6.    Selected Financial Data

The following table sets forth selected consolidated financial data of Chesapeake for the years ended December 31, 2004, 2003, 2002, 2001 and 2000. The data are derived from our audited consolidated financial statements revised to reflect the reclassification of certain items. In addition to changes in the annual average prices for oil and gas and increased production from drilling activity, significant acquisitions in recent years also impacted comparability between years. See notes 11 and 13 to notes to financial statements. 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.