CHESAPEAKE ENERGY CORP - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

[X] Annual Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2001

[ ] Transition Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

COMMISSION FILE NO. 1-13726

CHESAPEAKE ENERGY CORPORATION
(Exact Name of Registrant as Specified in Its Charter)

OKLAHOMA 73-1395733
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

6100 NORTH WESTERN AVENUE 73118
OKLAHOMA CITY, OKLAHOMA (Zip Code)
(Address of principal executive offices)

(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. [ ]

The aggregate market value of Common Stock held by non-affiliates on March
22, 2002 was $1,039,974,948. At such date, there were 165,773,281 shares of
Common Stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

PORTIONS OF THE REGISTRANT'S DEFINITIVE PROXY STATEMENT FOR THE 2002
ANNUAL MEETING OF SHAREHOLDERS ARE INCORPORATED BY REFERENCE IN PART III

- --------------------------------------------------------------------------------

PART I

ITEM 1. BUSINESS

GENERAL

We are one of the ten largest independent natural gas producers in the
United States. 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. Chesapeake maintains a website at
www.chkenergy.com. Information contained on our website is not part of this
report.

At the end of 2001, we owned interests in approximately 8,700 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 1996:

BUSINESS STRATEGY

From inception in 1989, our business strategy has been to aggressively build
and develop one of the largest onshore natural gas resource bases in the United
States. We are executing our strategy by:

o continuing to grow through the drillbit by conducting what we believe
is currently one of the most active drilling programs in the United
States. We currently have 15 rigs drilling on Chesapeake-operated
prospects and we are participating in 19 wells being drilled by others;

o continuing to make small to medium-sized acquisitions of strategically
located natural gas properties that provide high quality production and
significant drilling opportunities. In 2001, we invested approximately
$706 million to acquire 648 bcfe in 160 separate transactions. In our
experience, small to medium-sized acquisitions generally provide better
economics than large corporate acquisitions;

o maintaining a low operating cost structure so that we can deliver
attractive financial returns from our assets in all phases of the
commodity price cycle; and

o reducing our exposure to volatile oil and natural gas markets and
increasing our return on capital by periodically hedging projected
future period oil and natural gas production.

Based on our view that natural gas has become the fuel of choice to meet
growing power demand and increasing environmental concerns, we believe our
strategy should provide substantial growth opportunities in the years ahead.

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COMPANY STRENGTHS

We believe our past performance and future growth potential are primarily
attributable to five characteristics that distinguish us from other independent
oil and natural gas producers:

High-Quality Asset Base. Our properties are characterized by long-lived
reserves, established production profiles and an emphasis on natural gas.
Based upon 2001 production and our year-end reserves, our proved
reserves-to-production ratio, or reserve life, is more than eleven years. In
our primary operating area of the Mid-Continent, and in our three secondary
operating areas, our properties are concentrated in locations that enable us
to establish substantial economies of scale in drilling and production
operations and facilitate the application of more effective reservoir
management practices. We intend to continue concentrating our acquisition
and drilling efforts in the Mid-Continent region, where approximately 84% of
our proved reserves are located.

Low-Cost Producer. Our high-quality asset base has enabled us to
achieve a low operating cost structure. During 2001, our cash operating
costs per unit of production, which consist of general and administrative
expenses and production expenses and taxes, were $0.76 per mcfe. We believe
this is one of the lowest operating cost structures among publicly traded
independent oil and natural gas producers. We operate approximately 81% of
our proved reserves, providing a high degree of operating flexibility and
cost control.

Successful Acquisition Program. Our acquisition program is focused
primarily in the Mid-Continent region. This region is characterized by
long-lived natural gas reserves, low lifting costs, multiple geological
targets that provide substantial drilling potential, favorable basis
differentials to benchmark commodity prices, a well-developed oil and gas
transportation infrastructure and considerable potential for further
consolidation of assets. Beginning in 1998 and continuing throughout 2001,
we have successfully completed $1.6 billion in acquisitions at an average
cost of approximately $1.00 per mcfe. We believe we are well positioned to
continue this consolidation as a result of our large existing asset base,
our corporate presence in Oklahoma City and our knowledge and expertise in
the Mid-Continent.

Large Inventory of Drilling Projects. During the past 13 years, we
believe we have been one of the most active drillers in the United States,
especially of deep vertical and horizontal wells in challenging reservoir
conditions. As a result of our land acquisition strategy, we have developed
an onshore leasehold position of approximately 1.7 million net acres. In
addition, our technical teams have identified over 1,500 exploratory and
developmental drillsites, representing more than five years of future
drilling opportunities at our current rate of drilling.

Entrepreneurial Management. Our management team formed Chesapeake in
1989 with an initial capitalization of $50,000. Through the following years,
our management team has guided the company through operational challenges
and extremes of oil and gas prices to create one of the ten largest
independent natural gas producers in the United States with an enterprise
value of $2.7 billion at March 22, 2002, consisting of $1.2 billion in fair
market value related to our fully diluted common stock, $1.3 billion related
to our outstanding senior notes and $150 million related to our outstanding
preferred stock. In addition, our management and directors, through their
ownership of approximately 19.9 million shares of our common stock, have a
strong interest in increasing shareholder value.

2001 HIGHLIGHTS

Chesapeake's operating results for the year ended December 31, 2001
established several records for our company:

o income before income taxes and extraordinary item was $438 million,
compared to $196 million in 2000,

o operating cash flow increased to $522 million from $305 million in
2000,

o production of oil and natural gas grew to 161 bcfe, of which 89% was
natural gas, compared to 134 bcfe in 2000, and

o proved oil and gas reserves were 1,780 bcfe, an increase of 31% from
the year ended December 31, 2000.

During 2001, we also replaced 892 bcfe of proved reserves (excluding
downward revisions to proved reserves of 156 bcfe due to price decreases during
the year and the sale of our Canadian subsidiary) at a replacement cost of $1.27
per mcfe.

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2002 OUTLOOK

At the present time, we believe the outlook for Chesapeake is favorable
because of our large base of high quality natural gas properties, our geological
and operational expertise and a very strong portfolio of natural gas and oil
hedges in place. Our goals and the strategy to obtain those goals remain
unchanged for 2002:

o replace production by more than 200% at the lowest possible reserve
replacement cost,

o execute a capital expenditure plan balanced between drilling and
acquisitions, funded with operating cash flow,

o maintain a superior operating cost structure,

o reduce our net debt per mcfe, and

o deliver attractive financial returns from our assets in all phases of
our energy cycle.

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, 2001, we had 25 (9.2 net) wells in process.

WELL DATA

At December 31, 2001, we had interests in approximately 8,700 (3,600 net)
producing wells, including properties in which we held an overriding royalty
interest, of which 300 (150 net) were classified as primarily oil producing
wells and 8,400 (3,450 net) were classified as primarily gas producing wells.
Chesapeake operates approximately 4,000 of the total 8,700 producing wells. We
operate approximately 81% of our proved reserves.

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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:

Our hedging activities resulted in an increase in oil and gas revenues of
$105.4 million in 2001 as compared to a decrease of $30.6 million in 2000 and a
decrease of $1.7 million in 1999.

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, 2001 of $18.82 per barrel of oil and $2.51 per mcf of gas). These
prices were based on the cash spot prices for oil and natural gas at December
31, 2001.

As of December 31, 2001, the present value of our proved developed reserves
as a percentage of total proved reserves was 80%, and the volume of our proved
developed reserves as a percentage of total proved reserves was 71%. Natural gas
reserves accounted for 90% of total proved reserves at December 31, 2001.

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, 2001 present value of proved reserves of approximately $82 million
and $16 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, 2001 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 are stated in thousands and do not include our options to
acquire additional leasehold which had 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 and percentage-of-index contracts or 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 2001,
sales to Continental Natural Gas, Reliant Energy Field Services, and Aquila
Southwest Pipeline Corporation of $102.3 million, $87.6 million, and $71.9
million, respectively, accounted for 36% of our total oil and gas sales.
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.
No other customer accounted for more than 10% of total oil and gas sales in
2001.

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.

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 fixed 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

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properties depend primarily upon the prices we receive for our oil and gas.
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 semi-annual redeterminations based on prices
specified by our bank group at the time of redetermination. In addition, we may
have ceiling test writedowns in the future if prices fall significantly below
the prices at December 31, 2001.

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:

o worldwide and domestic supplies of oil and gas,

o weather conditions,

o the level of consumer demand,

o the price and availability of alternative fuels,

o risks associated with owning and operating drilling rigs,

o the availability of pipeline capacity,

o the price and level of foreign imports,

o domestic and foreign governmental regulations and taxes,

o the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls,

o political instability or armed conflict in oil-producing regions, and

o the overall economic environment.

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.

Our level of indebtedness may adversely affect operations, and we may have
difficulty repaying long-term indebtedness as it matures.

As of December 31, 2001, we had long-term indebtedness of $1.3 billion,
which included no bank indebtedness. Our long-term indebtedness represented 63%
of our total book capitalization at December 31, 2001.

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

o a significant portion of our cash flows must be used to service our
indebtedness; for example, for the year ended December 31, 2001,
interest (including capitalized interest) on our borrowings was $103.0
million and equaled approximately 17% of EBITDA. We cannot assure you
that our business will generate sufficient cash flows from operations
to enable us to continue to meet our obligations under our indentures.

o a high level of debt increases our vulnerability to general adverse
economic and industry conditions,

o the covenants contained in the agreements governing our outstanding
indebtedness limit our ability to borrow additional funds, dispose of
assets, pay dividends and make certain investments,

o our debt covenants may also affect our flexibility in planning for, and
reacting to, changes in the economy and in our industry, and

o a high level of debt may impair our ability to obtain additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes.

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 cannot
assure you that we will be able to generate sufficient cash flow to pay the
interest on our debt or that future working capital,

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borrowings or equity financing will 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 annual redeterminations.
We could be forced to repay a portion of our bank borrowings due to
redeterminations of our borrowing base. We cannot assure you that we will 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.

Higher oil and gas prices adversely affect the cost and availability of drilling
and production services.

Higher oil and gas prices generally stimulate increased demand for drilling
and production services and result in increased prices for drilling rigs, crews
and associated supplies, equipment and services. In the first nine months of
2001, we experienced significantly higher costs for drilling rigs and other
related services. While we have recently experienced lower service costs as
demand has decreased due to lower oil and gas prices, a return to higher prices
would likely increase service costs once again.

Our industry is extremely competitive.

The energy industry is extremely competitive. This is especially true with
regard to exploration for, and development and production of, new sources of oil
and natural gas. As an independent producer of oil and natural gas, we
frequently compete against companies that are larger and financially stronger in
acquiring properties suitable for exploration, in contracting for drilling
equipment and other services and in securing trained personnel.

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. These transactions are limited in life. While
intended to reduce the effects of volatile oil and gas prices, commodity price
risk management transactions may limit the prices we actually realize. We cannot
assure you that we will not experience reductions to oil and gas revenues from
our commodity price risk management activities in the future. In addition, our
commodity price risk management transactions may expose us to the risk of
financial loss in certain circumstances, including instances in which:

o our production is less than expected,

o there is a widening of price differentials between delivery points for
our production and the delivery point assumed in the hedge arrangement,
or

o the counterparties to our contracts fail to perform under the
contracts.

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 with respect to our commodity price
risk management transactions exceed certain levels. At December 31, 2001, we
were not required to post any collateral. Future collateral requirements are
uncertain and will depend on arrangements with our counterparties and highly
volatile natural gas and oil prices.

Estimates of oil and gas reserves are uncertain and inherently imprecise.

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.

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At December 31, 2001, approximately 29% by volume of our estimated proved
reserves were undeveloped. Recovery of undeveloped reserves requires significant
capital expenditures and successful drilling operations. The estimates of these
reserves include the assumption that we will make significant capital
expenditures to develop the reserves, including $224 million in 2002. Although
we have prepared estimates of our oil and gas reserves and the costs associated
with these reserves in accordance with industry standards, we cannot assure you
that the estimated costs are accurate, that development will occur as scheduled
or that the results will 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, 2001
present value is based on weighted average wellhead oil and gas prices of $18.82
per barrel of oil and $2.51 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. A change in price of $0.10 per mcf and $1.00 per barrel would
result in a change in our December 31, 2001 present value of proved reserves of
approximately $82 million and $16 million, respectively.

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 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.

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, our proved reserves will decline over time. Recovery
of such reserves will require significant capital expenditures and successful
drilling operations. We cannot assure you that we can successfully find and
produce reserves economically in the future. In addition, we may not be able to
acquire proved reserves at acceptable costs.

If we do not make significant capital expenditures, we may not be able to
replace 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 flow from operations is not
sufficient to fund our capital expenditure budget, there can be no assurance
that additional bank debt, debt or equity issuances or other methods of
financing will be available to meet these requirements.

Acquisitions are subject to the uncertainties of 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 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.

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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 which are substantially greater than those available to us. Therefore,
we cannot assure you that we will be able to acquire oil and gas properties that
contain economically recoverable reserves or that we will 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. While it
is our current intention to continue to concentrate on acquiring properties with
development and exploration potential located in the Mid-Continent region, there
can be no assurance that in the future we will not decide to pursue acquisitions
or properties located in other geographic regions. To the extent that such
acquired properties are substantially different than our existing properties,
our ability to efficiently realize the economic benefits of such transactions
may be limited.

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 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 occurs, we could
sustain substantial losses as a result of:

o injury or loss of life,

o severe damage to or destruction of property, natural resources and
equipment,

o pollution or other environmental damage,

o clean-up responsibilities,

o regulatory investigations and penalties, and

o suspension of operations.

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. In accordance with industry practice, we
maintain insurance against some, but not all, of the risks described above. We
cannot assure you that our insurance will be adequate to cover casualty losses
or liabilities. Also, we cannot predict the continued availability of 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. We cannot assure you that the new wells we drill or
participate in will be productive or that we will recover all or any portion of
our investment in wells drilled. 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:

o unexpected drilling conditions,

o title problems,

o pressure or irregularities in formations,

o equipment failures or accidents,

o adverse weather conditions,

o compliance with environmental and other governmental requirements, and

o cost of, or shortages or delays in the availability of, drilling rigs
and equipment.

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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 and
marketing oil and gas production. 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.

REGULATION

General. Numerous departments and agencies, foreign, federal, state and
local, issue rules and regulations binding on the oil and gas industry, some of
which carry substantial penalties for failure to comply. This regulatory burden
increases our cost of doing business and, consequently, affects our
profitability.

Exploration and Production. Our domestic operations are subject to various
types of regulation at the 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 domestic activities subject to regulation are:

o the location of wells,

o the method of drilling and completing wells,

o the surface use and restoration of properties upon which wells are
drilled,

o the plugging and abandoning of wells,

o the disposal of fluids used or other wastes obtained in connection with
operations,

o the marketing, transportation and reporting of production, and

o the valuation and payment of royalties.

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, foreign, 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. Such regulation
has increased the cost of 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 require us to obtain permits for,
among other things,

o discharges into surface waters,

o discharges of storm water runoff,

o the construction of facilities in wetland areas, and

o the construction and operation of underground injection wells or
surface pits to dispose of produced saltwater and other nonhazardous
oilfield wastes.

Under state and federal laws, we could be required to remove or remediate
previously disposed wastes, including

11

wastes disposed of or released by us or prior owners or operators, 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, 2001, Chesapeake had federal and state income tax net
operating loss (NOL) carryforwards of approximately $757.7 million.
Additionally, we had approximately $419.8 million of alternative minimum tax
(AMT) NOL carryforwards available as a deduction against future AMT income and
approximately $5.7 million of percentage depletion carryforwards. The NOL
carryforwards expire from 2010 through 2021. 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 ownership changes in January 1995 and March 1998
which triggered limitations. Certain NOLs acquired through various acquisitions
are also subject to limitations. Of the $757.7 million NOLs and $419.8 million
AMT NOLs, $339.5 million and $84.1 million, respectively, are limited under
Section 382. Therefore, $418.2 million of the NOLs and $335.7 million of the AMT
NOLs are not subject to the limitation. The utilization of $339.5 million of the
NOLs and the utilization of $84.1 million of the AMT NOLs subject to the Section
382 limitation are limited to approximately $37.9 million and $12.3 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,
2001. 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.

12

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 near future. However, there is no
assurance that the Internal Revenue Service will not challenge these
carryforwards or their utilization.

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. From time to time, Chesapeake's title to
oil and gas properties is challenged through legal proceedings. We are routinely
involved in litigation involving title to certain of our oil and gas properties,
some of which management believes could be adverse to us, individually or in the
aggregate. See Item 3 -- Legal Proceedings.

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, the occurrence of any of which could result in
substantial losses to Chesapeake 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. Chesapeake and our subsidiaries 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 677 employees as of December 31, 2001, including 107 employed
by our drilling rig subsidiary, Nomac Drilling Corporation. No employees are
represented by organized labor unions. We believe our employee relations are
good.

FACILITIES

Chesapeake owns an office building complex in Oklahoma City and field
offices in Lindsay and Waynoka, Oklahoma; Garden City, Kansas; and Borger,
Texas. In addition, Chesapeake leases field office space in Forgan, Kingfisher,
Oklahoma City, Watonga, Weatherford and Wilburton, Oklahoma; Navasota, Texas;
Lovington and Eunice, New Mexico; and Dickinson, North Dakota.

13

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.

Compound Annual Growth Rate. Annual growth rate of a particular unit of
measure or performance, expressed as an internal rate of return during a
specified time interval (e.g., 1996-2001).

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.

EBITDA. Net income (loss) before interest expense, income taxes,
depreciation, depletion and amortization, Gothic standby credit facility costs,
impairments of oil and gas properties and other assets, extraordinary items,
risk management income and gain on sale of Canadian subsidiary and certain other
non-cash charges. EBITDA is not a measure of cash flow as determined by
generally accepted accounting principles. EBITDA information has been included
in this report because EBITDA is a measure used by some investors in determining
historical ability to service indebtedness. EBITDA should not be considered as
an alternative to, or more meaningful than, net income or cash flows as
determined in accordance with generally accepted accounting principles as an
indicator of operating performance or liquidity.

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.

14

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.

Operating Cash Flow. Income (loss) before income taxes, depreciation,
depletion and amortization, Gothic standby credit facility costs, impairment of
oil and gas properties and other assets, extraordinary items, risk management
income, gain on Sale of Canadian subsidiary and certain other non-cash charges.
Operating cash flow should not be considered as an alternative to, or more
meaningful than, cash flow from operating activities as determined in accordance
with generally accepted accounting principles as an indicator of operating
performance or liquidity.

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.

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.

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 drilled to known reservoir on undrilled acreage or from existing wells
where a relatively major expenditure is required for recompletion.

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.

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.

15

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 84% 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 8% 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 2% 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, 2001, we participated in 530 gross (244.5
net) wells, 238 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 31% during 2001 to an estimated 1,780
bcfe at December 31, 2001, compared to 1,355 bcfe of estimated proved reserves
at December 31, 2000 (see note 11 of notes to consolidated financial statements
in Item 8).

Chesapeake's strategy for 2002 is to continue developing our natural gas
assets through exploratory and developmental drilling and by selectively
acquiring strategic properties in our core operating areas. We have budgeted
approximately $300 million for drilling, acreage acquisition, seismic and
related capitalized internal costs, all of which will 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 AREAS

Mid-Continent. Chesapeake's Mid-Continent proved reserves of 1,501.5 bcfe
represented 84% of our total proved reserves as of December 31, 2001, and this
area produced 116.1 bcfe, or 72%, of our 2001 production. During 2001, we
invested approximately $328.4 million to drill 477 (218.6 net) wells in the
Mid-Continent. We anticipate spending approximately 80% to 85% of our total
budget for exploration and development activities in the Mid-Continent region
during 2002. We anticipate the Mid-Continent will contribute approximately 148.0
bcfe, or 88%, of expected total production during 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 142.7 bcfe, or 8%, of our total proved reserves as of
December 31, 2001. During 2001, the Gulf Coast assets produced 27.5 bcfe, or
17%, of our total production. During 2001, we invested approximately $51.8
million to drill 21 (9.4 net) wells in the Gulf Coast. We anticipate the Gulf
Coast will contribute approximately 22.0 bcfe, or 13%, of expected total
production during 2002. We anticipate spending approximately 5% to 10% of our
total budget for exploration and development activities in the Gulf Coast region
during 2002.

Permian Basin. Chesapeake's Permian Basin proved reserves, consisting
primarily of the Lovington area in New Mexico, represented 94.4 bcfe, or 5%, of
our total proved reserves as of December 31, 2001. During 2001, the Permian
assets produced 5.0 bcfe, or 3%, of our total production. We anticipate the
Permian Basin will contribute approximately 7.7 bcfe, or 5%, of expected total
production during 2002. During 2001, we invested approximately $10.9 million to
drill 8 (4.7 net) wells in the Permian Basin. For 2002, we anticipate spending
approximately 2% to 3% of our total budget for exploration and development
activities in the Permian Basin.

16

Williston Basin. Chesapeake's Williston Basin proved reserves represented
29.8 bcfe, or 2%, of our total proved reserves as of December 31, 2001. During
2001, the Williston assets produced 3.3 bcfe, or 2% of our total production. We
anticipate the Williston Basin will contribute approximately 1.5 bcfe, or 1.6%,
of expected total production during 2002. During 2001, we invested approximately
$4.1 million to drill 6 (3.8 net) wells in the Williston Basin. For 2002, we
anticipate spending approximately 1% to 2% of our total budget for exploration
and development activities in the Williston Basin.

Canada. During 2001, production from Canada was 9.1 bcfe, or 6%, of our
total production. During 2001, we invested approximately $11.1 million to drill
18 (8.0 net) wells, install various pipelines and compressors and to perform
capital workovers in Canada. On October 1, 2001, we sold our Canadian subsidiary
for approximately $143.0 million, which resulted in a $27.0 million pre-tax
gain. We decided to sell our Canadian assets because we believe Chesapeake can
receive a greater return on its invested capital in the Mid-Continent region
rather than in Canada.

OIL AND GAS RESERVES

The tables below set forth information as of December 31, 2001 with respect
to our estimated proved reserves, and the associated estimated future net
revenue and the present value at such date. Ryder Scott Company L.P. evaluated
26%, Lee Keeling and Associates evaluated 24%, and Williamson Petroleum
Consultants, Inc. evaluated 22% of our combined discounted future net revenues
from our estimated proved reserves at December 31, 2001. The remaining 28% 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.

- ----------

(a) Estimated future net revenue represents 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
December 31, 2001. The amounts shown do not give 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. The prices used in the external and internal reports yield
weighted average wellhead prices of $18.82 per barrel of oil and $2.51 per
mcf of gas.

The future net revenue attributable to our estimated proved undeveloped
reserves of $665 million at December 31, 2001, and the $334 million present
value thereof, have been calculated assuming that we will expend approximately
$420 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 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, 2001. 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

17

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. Predictions about
prices and future production levels are subject to great uncertainty, and 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.

See Item 1 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.

ITEM 3. LEGAL PROCEEDINGS

We are subject to ordinary routine litigation incidental to our business. In
addition, the following matters were recently terminated or are pending:

West Panhandle Field Cessation Cases. One of our subsidiaries, Chesapeake
Panhandle Limited Partnership ("CP") (f/k/a MC Panhandle, Inc.), and two
subsidiaries of Kinder Morgan, Inc. have been defendants in 16 lawsuits filed
between June 1997 and December 2001 by royalty owners seeking the cancellation
of oil and gas leases in the West Panhandle Field in Texas. MC Panhandle, Inc.,
which we acquired in April 1998, has owned the leases since January 1, 1997. The
co-defendants are prior lessees.

The plaintiffs in these cases have claimed the leases terminated upon the
cessation of production for various periods, primarily during the 1960s. In
addition, the plaintiffs have sought to recover conversion damages, exemplary
damages, attorneys' fees and interest. The defendants have asserted that any
cessation of production was excused and have pled affirmative defenses of
limitations, waiver, temporary estoppel, laches and title by adverse possession.
As previously reported, four of the 16 cases have been tried, and there have
been appellate decisions in three of them.

In January 2001, CP and the other defendants settled the claims of the
principal plaintiffs in eight cases tried or pending in the District Court of
Moore County, Texas, 69th Judicial District. The settlement consideration was
not material to our financial condition or results of operations. In two of
these cases, we have filed petitions for review in the Texas Supreme Court with
respect to the claims of plaintiffs who were not covered by the settlement. The
Texas Supreme Court granted the petitions in December 2001 and heard oral
arguments in March 2002.

Related West Panhandle cessation cases which are pending are the following:

Lois Law, et al. v. NGPL, et al., District Court of Moore County, Texas,
69th Judicial District, No. 97-70, filed December 22, 1997, jury trial in June
1999, verdict for CP and co-defendants. The jury found plaintiffs' claims were
barred by adverse possession, laches and revivor. On January 19, 2000, the court
granted plaintiffs' motion for judgment notwithstanding verdict and entered
judgment in favor of plaintiffs. In addition to quieting title to the lease
(including existing gas wells and all attached equipment) in plaintiffs, the
court awarded actual damages against CP in the amount of $716,400 and exemplary
damages in the amount of $25,000. The court further awarded, jointly and
severally from all defendants, $160,000 in attorneys' fees and interest and
court costs. On March 28, 2001, the Amarillo Court of Appeals reversed and
rendered judgment in favor of CP and the other defendants, finding that the
subject leases had been revived as a matter of law, making all other issues
moot. Plaintiffs have petitioned the Texas Supreme Court to accept the case for
review. The Texas Supreme Court has asked for briefs but has not yet ruled on
the petition.

A.C. Smith, et al. v NGPL, et al., District Court of Moore County, Texas,
69th Judicial District, No. 98-47, first filed January 26, 1998, refiled May 29,
1998. On June 18, 1999, the court granted plaintiffs' motion for summary
judgment in part, finding that the lease had terminated due to the cessation of
production, subject to the defendants' affirmative defenses. On February 8,
2001, the court granted plaintiffs' motion for summary judgment on defendants'
affirmative defenses but reversed its ruling that the lease had terminated as a
matter of law. No trial date has been set.

Phillip Thompson, et al. v. NGPL, et al., U.S. District Court, Northern
District of Texas, Amarillo Division, Nos. 2:98-CV-012 and 2:98-CV-106, filed
January 8, 1998 and March 18, 1998, respectively (actions consolidated), jury

18

trial in May 1999, verdict for CP and co-defendants. The jury found plaintiffs'
claims were barred by the payment of shut-in royalties, laches and revivor.
Plaintiffs' motion for new trial pending.

Craig Fuller, et al. v. NGPL, et al., District Court of Carson County,
Texas, 100th Judicial District, No. 8456, filed June 23, 1997, cross motions for
summary judgment pending.

Pace v. NGPL, et al., U.S. District Court, Northern District of Texas,
Amarillo Division, filed January 29, 1999. Cross motions for summary judgment
pending.

The remaining three cases were filed in September 2001 in the U.S. District
Court, Northern District of Texas, Amarillo Division, in November 2001 in the
District Court of Moore County, Texas, 69th Judicial District and in December
2001 in the District Court of Carson County, Texas, 100th Judicial District. CP
and the other defendants have filed answers in each of them.

We have previously established an accrued liability we believe will be
sufficient to cover the estimated costs of litigation for each of the pending
cases. Because of the inconsistent verdicts reached by the juries in the four
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 the amount of
damages that might ultimately be awarded could differ from management's
estimates. CP and the other defendants are vigorously defending against the
plaintiffs' claims.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable.

19

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 March 22, 2002 there were 1,209 holders of record of our common stock and
approximately 52,000 beneficial owners.

DIVIDENDS

We did not pay dividends on our common stock in 2000 or 2001. The payment of
future cash dividends, if any, will depend upon, among other things, our
financial condition, funds from operations, the level of our capital and
development expenditures, our future business prospects and any contractual
restrictions. Other than payments of dividends on preferred stock, our current
policy is to retain cash for the continued growth of our business.

Two 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 the 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.

From December 31, 1998 through March 31, 2000, we did not meet the debt
incurrence test contained in one of our indentures, which required a coverage
ratio of at least 2.5 to 1. As a result, we were unable to pay dividends on our
previously outstanding 7% cumulative convertible preferred stock. Beginning June
30, 2000, we met the debt incurrence test and resumed paying quarterly preferred
stock dividends on November 1, 2000. The 7% preferred stock was redeemed and
retired in 2001. On November 13, 2001, we issued 3.0 million shares of 6.75%
cumulative preferred stock, par value $.01 per share and a liquidation
preference of $50 per share, in a private offering. Annual cumulative cash
dividends of $3.375 per share are payable quarterly on the fifteenth day of each
February, May, August and November. As of December 31, 2001, our coverage ratio
for purposes of the debt incurrence test was 6.3 to 1, compared to 2.25 to 1
required in our indentures.

Our revolving credit agreement limits the amount of cash dividends we may
pay to $10.0 million per year, excluding dividends on our 6.75% cumulative
preferred stock. The lending group has consented to the payment of these
preferred stock dividends as long as there is no default under the credit
agreement when dividends are declared.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected consolidated financial data of
Chesapeake for the fiscal year ended June 30, 1997, the six months ended
December 31, 1996, the six month transition period ended December 31, 1997 and
the twelve months ended December 31, 1997, 1998, 1999, 2000 and 2001. The data
are derived from our audited consolidated financial statements, although the
period for the six months ended December 31, 1996 and the twelve months ended
December 31, 1997 have not been audited. In 1997, we changed our fiscal year
from June 30 to

20

December 31. Acquisitions we made during the first and second quarters of 1998
and the first quarter of 2001 materially affect the comparability of the
selected financial data with the respective prior years. Each of the
acquisitions 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

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

OVERVIEW

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

RESULTS OF OPERATIONS

General. For the year ended December 31, 2001, Chesapeake had net income of
$217.4 million, or $1.25 per diluted common share, on total revenues of $969.1
million. This compares to net income of $455.6 million, or $3.01 per diluted
common share, on total revenues of $628.0 million during the year ended December
31, 2000, and net income of $33.3 million, or $0.16 per diluted common share, on
total revenues of $354.9 million during the year ended December 31, 1999. The
2001 net income included, on a pre-tax basis except for the extraordinary item,
$84.8 million in risk management income, a $10.1 million impairment of certain
equity investments, a $27.0 million gain on the sale of our Canadian subsidiary,
a $3.4 million cost for an unsecured standby credit facility associated with the
acquisition of Gothic Energy Corporation, and a $46.0 million extraordinary
after-tax loss on early extinguishment of debt. Net income in 2000 was
significantly enhanced by the reversal of a deferred tax valuation allowance in
the amount of $265.0 million during the fourth quarter. The reversal related to
Chesapeake's expected ability to generate sufficient future taxable income to
utilize net operating losses prior to their expiration.

Oil and Gas Sales. During 2001, oil and gas sales increased to $735.5
million versus $470.2 million in 2000 and $280.4 million in 1999. In 2001,
Chesapeake produced 161.5 bcfe at a weighted average price of $4.56 per mcfe,
compared to 134.2 bcfe produced in 2000 at a weighted average price of $3.50 per
mcfe, and 133.5 bcfe produced in 1999 at a weighted average price of $2.10 per
mcfe.

The following table shows our production by region for 1999, 2000 and 2001:

Natural gas production represented approximately 89% of our total production
volume on an equivalent basis in 2001, compared to 86% in 2000 and 81% in 1999.
The decrease in oil production from 1999 through 2001 is the result of
divestitures that occurred primarily in 1999 and our increasing focus on natural
gas.

For 2001, we realized an average price per barrel of oil of $26.92, compared
to $26.39 in 2000 and $16.01 in 1999. Natural gas prices per mcf were $4.56,
$3.36 and $1.97 in 2001, 2000 and 1999, respectively. Our hedging activities
resulted in an increase in oil and gas revenues of $105.4 million or $0.65 per
mcfe in 2001, a decrease of $30.6 million or $0.23 per mcfe in 2000, and a
decrease of $1.7 million or $0.01 per mcfe in 1999.

23

Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.
This statement establishes accounting and reporting standards requiring that
derivative instruments (including certain derivative instruments embedded in
other contracts) be recorded at fair value and included in the consolidated
balance sheet as assets or liabilities. The accounting for changes in the fair
value of a derivative instrument depends on the intended use of the derivative
and the resulting designation, which is established at the inception of a
derivative. Special accounting for qualifying hedges allows a derivative's gains
and losses to offset related results of the hedged item in the consolidated
statement of operations. For derivative instruments designated as cash flow
hedges, changes in fair value, to the extent the hedge is effective, are
recognized in other comprehensive income until the hedged item is recognized in
earnings. Hedge effectiveness is measured at least quarterly based on the
relative changes in fair value between the derivative contract and the hedged
item over time. Any change in fair value resulting from ineffectiveness, as
defined by SFAS 133, is recognized immediately in earnings. Changes in fair
value of contracts that do not meet the SFAS 133 definition of a cash flow hedge
are also recognized in earnings through risk management income.

Risk Management Income. Chesapeake recognized $84.8 million of risk
management income in 2001, compared to no such income (loss) in 2000 and 1999.
Risk management income for 2001 consisted of $106.8 million related to changes
in fair value of derivatives not designated as cash flow hedges less $24.5
million of reclassifications related to the settlement of such contracts plus
$2.5 million associated with the ineffective portion of derivatives qualifying
for hedge accounting.

Pursuant to SFAS 133, our cap-swaps do not qualify for designation as cash
flow hedges. Therefore, changes in fair value of these instruments that occur
prior to their maturity, together with any change in fair value of cash flow
hedges resulting from ineffectiveness, are reported in the statement of
operations as risk management income (loss). Amounts recorded in risk management
income (loss) do not represent cash gains or losses. Rather, these amounts are
temporary valuation swings in contracts or portions of contracts that are not
entitled to receive hedge accounting treatment. All amounts initially recorded
in this caption are ultimately reversed within this same caption and included in
oil and gas sales over the respective contract terms.

Oil and Gas Marketing Sales. Chesapeake realized $148.7 million in oil and
gas marketing sales for third parties in 2001, with corresponding oil and gas
marketing expenses of $144.4 million, for a net margin of $4.3 million. This
compares to sales of $157.8 million and $74.5 million, expenses of $152.3
million and $71.5 million, and margins of $5.5 million and $3.0 million in 2000
and 1999, respectively. In 2001, Chesapeake realized an increase in volumes
related to oil and gas marketing sales, which was partially offset by a decrease
in oil and gas prices. The increase in marketing sales and cost of sales in 2000
as compared to 1999 was due primarily to higher oil and gas prices in 2000 and
the fact that we began marketing oil in June 1999.

Production Expenses. Production expenses, which include lifting costs and
ad valorem taxes, were $75.4 million in 2001, compared to $50.1 million and
$46.3 million in 2000 and 1999, respectively. On a unit of production basis,
production expenses were $0.47 per mcfe in 2001 compared to $0.37 and $0.35 per
mcfe in 2000 and 1999, respectively. The increase in costs on a per unit basis
in 2001 is due primarily to increased field service costs, higher production
costs associated with properties acquired in 2001 and an increase in ad valorem
taxes. We expect that lease operating expenses per mcfe in 2002 will range from
$0.50 to $0.55.

Production Taxes. Production taxes were $33.0 million in 2001 compared to
$24.8 million in 2000 and $13.3 million in 1999. On a unit of production basis,
production taxes were $0.20, $0.19 and $0.10 per mcfe in 2001, 2000 and 1999,
respectively. The increase in 2001 of $8.2 million was due to an increase in
production volumes and, to a lesser extent, an increase in the average wellhead
prices received for natural gas in 2001. The increase from 1999 to 2000 was the
result of increased prices. In general, production taxes are calculated using
value-based formulas that produce higher per unit costs when oil and gas prices
are higher. We expect production taxes per mcfe to range from $0.18 to $0.22 in
2002 based on our assumption that oil and natural gas wellhead prices will range
from $2.50 to $3.20 per mcfe.

General and Administrative Expense. General and administrative expenses,
which are net of internal payroll and non-payroll costs capitalized in our oil
and gas properties (see note 11 of notes to consolidated financial statements),
were $14.4 million in 2001, $13.2 million in 2000 and $13.5 million in 1999. The
increase in 2001 is the result of the company's growth related to the various
acquisitions which occurred in late 2000 and during 2001.

Chesapeake follows the full-cost method of accounting under which all costs
associated with property acquisition, exploration and development activities are
capitalized. We capitalize internal costs that can be directly identified with
our acquisition, exploration and development activities and do not include any
costs related to production, general corporate overhead or similar activities.
We capitalized $8.3 million, $7.0 million and $2.7

24

million of internal costs in 2001, 2000 and 1999, respectively, directly related
to our oil and gas exploration and development efforts. We anticipate that
general and administrative expenses for 2002 will be between $0.10 and $0.11 per
mcfe, which is approximately the same level as 2001.

Oil and Gas Depreciation, Depletion and Amortization. Depreciation,
depletion and amortization of oil and gas properties was $172.9 million, $101.3
million and $95.0 million during 2001, 2000 and 1999, respectively. The average
DD&A rate per mcfe, which is a function of capitalized costs, future development
costs, and the related underlying reserves in the periods presented, was $1.07
($1.08 in U.S. and $0.90 in Canada), $0.75 ($0.76 in U.S. and $0.71 in Canada)
and $0.71 ($0.73 in U.S. and $0.52 in Canada) in 2001, 2000 and 1999,
respectively. We expect the 2002 DD&A rate to be between $1.15 and $1.25 per
mcfe.

Depreciation and Amortization of Other Assets. Depreciation and
amortization of other assets was $8.7 million in 2001, compared to $7.5 million
in 2000 and $7.8 million in 1999. The increase in 2001 was primarily the result
of higher depreciation cost on fixed assets related to recent capital
expenditures. Other property and equipment costs are depreciated on both
straight-line and accelerated methods. Buildings are depreciated on a
straight-line basis over 31.5 years. Drilling rigs are depreciated on a
straight-line basis over 12 years. All other property and equipment are
depreciated over the estimated useful lives of the assets, which range from five
to seven years.

Interest and Other Income. Interest and other income was $2.9 million, $3.6
million and $8.6 million in 2001, 2000 and 1999, respectively. The decrease in
2001 was the result of a decrease in miscellaneous non-oil and gas income offset
by an increase in interest income. The decrease in 2000 was due primarily to
gains on sales of various non-oil and gas assets during 1999 which did not occur
in 2000.

Interest Expense. Interest expense increased to $98.3 million in 2001,
compared to $86.3 million in 2000 and $81.1 million in 1999. The increase in
2001 is due to a $260.0 million increase in average long-term borrowings in 2001
compared to 2000, partially offset by a decrease in the overall average interest
rate. The increase in 2000 compared to 1999 was due to additional borrowings
under our bank credit facility. In addition to the interest expense reported, we
capitalized $4.7 million of interest during 2001, compared to $2.4 million
capitalized in 2000, and $3.5 million capitalized in 1999 on significant
investments in unproved properties that were not being currently depreciated,
depleted or amortized and on which exploration activities were in progress.
Interest is capitalized using the weighted average interest rate on our
outstanding borrowings. We anticipate that capitalized interest for 2002 will be
between $5.0 million and $6.0 million.

Impairments of Investments in Securities. During 2001 we recorded
impairments to two equity investments of $10.1 million. The majority of this
impairment was related to our investment in RAM Energy, Inc. In March 2001, we
issued 1.1 million shares of Chesapeake common stock in exchange for 49.5% of
RAM's outstanding common stock. Our shares were valued at $8.854 each, or $9.9
million in total. During 2001, we recorded our equity in RAM's net losses, which
had the effect of reducing our carrying value in these securities to $8.6
million. In December 2001, we sold the RAM shares for minimal consideration. In
addition, we reduced the carrying value of our $2.0 million investment in an
Internet-based oil and gas business by $1.5 million to $0.5 million.

Gain on Sale of Canadian Subsidiary. In October 2001, we sold our Canadian
subsidiary, which had oil and gas operations primarily in northeast British
Columbia, for approximately $143.0 million. Under full-cost accounting, our
investment in these Canadian oil and gas properties was treated as a separate
cost center for accounting purposes. As a result of the sale of this cost
center, any gain or loss on the disposition is required to be recognized
currently in earnings. In the fourth quarter of 2001, we recorded a gain on sale
of our Canadian subsidiary of $27.0 million.

Gothic Standby Credit Facility Costs. During 2000, we obtained a standby
commitment for a $275 million credit facility, consisting of a $175 million term
loan and a $100 million revolving credit facility which, if needed, would have
replaced our then existing revolving credit facility. The term loan was
available to provide funds to repurchase any of Gothic Production Corporation's
11.125% senior secured notes tendered following the closing of the Gothic
acquisition in January 2001 pursuant to a change-of-control offer to purchase.
In February 2001, we purchased $1.0 million of notes tendered for 101% of such
amount. We did not use the standby credit facility and the commitment terminated
on February 23, 2001. Chesapeake incurred $3.4 million of costs for the standby
facility, which were recognized in the first quarter of 2001.

Extraordinary Loss on Early Extinguishment of Debt. During 2001, we
purchased or redeemed $500.0 million principal amount of our 9.625% senior
notes, $202.3 million principal amount of the 11.125% senior secured notes of
Gothic Production Corporation, a Chesapeake subsidiary, and all $120.0 million
principal amount of our 9.125% senior notes. The purchase and redemption of
these notes included payment of aggregate make-whole and redemption premiums of
$75.6 million and the write-off of unamortized debt costs and debt issue
premiums. These costs associated with early extinguishment of debt are reflected
as a $46.0 million after-tax extraordinary loss in 2001.

25

Provision (Benefit) for Income Taxes. Chesapeake recorded income tax
expense of $175.0 million in 2001, compared to income tax benefit of $259.4
million in 2000 and income tax expense of $1.8 million in 1999. Income tax
expense for 2001 is comprised of $158.3 million related to our domestic
operations, $7.1 million related to our Canadian operations and $9.6 million
related to the sale of our Canadian subsidiary. The income tax benefit in 2000
was comprised of $5.6 million of income tax expense related to our Canadian
operations and the reversal of a $265 million deferred tax valuation allowance
which was established in prior years. The valuation allowance had been
established due to uncertainty surrounding our ability to utilize extensive
regular tax NOLs prior to their expiration. Based upon our results of operations
as of December 31, 2000, the improved outlook for the natural gas industry and
our projected results of future operations, we believed it was more likely than
not that Chesapeake would be able to generate sufficient future taxable income
to utilize our existing NOLs prior to their expiration. Consequently, we
determined that a valuation allowance was no longer required at December 31,
2000. Our expectations remain unchanged as of December 31, 2001. The income tax
expense recorded in 1999 was related entirely to our Canadian operations.

CASH FLOWS FROM OPERATING, INVESTING AND FINANCING ACTIVITIES

Cash Flows from Operating Activities. Cash provided by operating activities
(exclusive of changes in working capital) was $518.6 million in 2001, compared
to $305.8 million in 2000 and $138.7 million in 1999. The $212.8 million
increase from 2000 to 2001 was primarily due to increased oil and gas revenues
resulting from higher sales volume and higher prices. The $167.1 million
increase from 1999 to 2000 was primarily due to increased oil and gas revenues
resulting from higher prices.

Cash Flows from Investing Activities. Cash used in investing activities
increased to $670.1 million in 2001, compared to $325.2 million in 2000 and
$153.9 million in 1999. During 2001, Chesapeake invested $421.0 million for
exploration and development drilling, invested $316.7 million for the
acquisition of oil and gas properties, received $1.4 million related to
divestitures of oil and gas properties and received $142.9 million for the sale
of our Canadian subsidiary. In 2001, we invested $40.2 million in securities of
other companies, including $22.5 million in notes and warrants of Seven Seas
Petroleum Inc., $14.6 million in notes of RAM Energy, Inc. and $3.1 million in
other equity securities. We also invested $14.1 million in drilling rig
equipment, $11.0 million in our Oklahoma City office complex and $10.6 million
on upgrading various other properties and equipment.

During 2000, Chesapeake invested $188.8 million for exploration and
development drilling, invested $78.9 million for the acquisition of oil and gas
properties, and received $1.5 million related to divestitures of oil and gas
properties. We invested $36.7 million in connection with our acquisition of
Gothic Energy Corporation, including the purchase of Gothic notes and
acquisition related costs. We also invested $7.9 million in drilling rig
equipment. Additionally in 2000, we invested $4.0 million in our Oklahoma City
office complex. In 1999, we invested $153.3 million for exploration and
development drilling, invested $49.9 million for the acquisition of oil and gas
properties, and received $45.6 million related to divestitures of oil and gas
properties.

Cash Flows from Financing Activities. Cash provided by financing activities
was $234.5 million in 2001, compared to $27.7 million used in 2000 and $13.1
million provided in 1999. During 2001, we borrowed $433.5 million under our bank
credit facility and made repayments under this facility of $458.5 million. In
2001, we received $780.6 million from the issuance of our $800.0 million 8.125%
senior notes in April and $247.7 million from the issuance of our $250.0 million
8.375% senior notes in November. We used $906.0 million to purchase or redeem
various Chesapeake and Gothic senior notes. We incurred $6.6 million of deferred
charges related to our credit facility. In November 2001, we issued $150.0
million in preferred stock and received $145.1 million of net proceeds. We
received $3.2 million from the exercise of employee and director stock options.
We paid $3.3 million for make-whole provisions in the fourth quarter 2001
related to the exchange of our common stock for RAM Energy, Inc. common stock
which occurred in March 2001. Preferred stock dividends of $1.1 million were
paid in 2001.

During 2000, we borrowed $244.0 million under our bank credit facility and
made repayments under this facility of $262.5 million. Also in 2000, we paid
$8.3 million in connection with exchanges of our preferred stock for our common
stock and paid cash dividends of $4.6 million on our preferred stock. In
connection with our purchase of Gothic notes in 2000, we received $7.1 million
cash from the sellers of Gothic notes pursuant to make-whole provisions included
in the purchase agreements. These provisions required payments to be made by the
sellers to us, or additional payments to be made by us to the sellers, depending
upon changes in market value of our common stock during a specified period
pending registration of our common stock issued to the sellers of Gothic notes.
During 1999, we borrowed $116.5 million under our bank credit facility and made
repayments under this facility of $98.0 million.

26

LIQUIDITY AND CAPITAL RESOURCES

Sources of Liquidity

Chesapeake had working capital of $188.0 million at December 31, 2001, of
which $125.0 million was cash. Another source of liquidity is our $225 million
revolving bank credit facility (with a committed borrowing base of $225 million)
which matures in September 2003. We believe we will have adequate resources,
including budgeted operating cash flows, working capital and proceeds from our
revolving bank credit facility, to fund our capital expenditure budget for
exploration and development activities during 2002, which is currently estimated
to be approximately $300 million. However, higher drilling and field operating
costs, unfavorable drilling results or other factors could cause us to reduce
our drilling program, which is largely discretionary. Based on our current cash
flow assumptions, we expect operating cash flow to be between $325 million and
$350 million. Any operating cash flow not needed to fund our drilling program
will be available for acquisitions, debt repayment or other general corporate
purposes in 2002.

A significant portion of our liquidity is concentrated in cash and cash
equivalents, including restricted cash, and derivative instruments that enable
us to hedge a portion of our exposure to price volatility from producing oil and
natural gas. These arrangements expose us to credit risk from our
counterparties. Our mark-to-market position and closed but uncollected
receivable with our largest counterparty, Morgan Stanley Capital Group Inc.,
totaled $137.8 million at December 31, 2001. We do not expect that Morgan
Stanley or our other counterparties will fail to meet their obligations given
their high credit ratings. Other financial instruments which potentially subject
us to concentrations of credit risk consist principally of investments in debt
instruments and accounts receivables. Our accounts receivable are primarily from
purchasers of oil and natural gas products and exploration and production
companies which own interests in properties we operate. The industry
concentration has the potential to impact our overall exposure to credit risk,
either positively or negatively, in that our customers may be similarly affected
by changes in economic, industry or other conditions. We generally require
letters of credit for receivables from customers which are judged to have
sub-standard credit, unless the credit risk can otherwise be mitigated. Cash and
cash equivalents are deposited with major banks or institutions with high credit
ratings.

Our liquidity is not dependent on the use of off-balance sheet financing
arrangements, such as the securitization of receivables or obtaining access to
assets through special purpose entities. We have not relied on off-balance sheet
financing arrangements in the past and we do not intend to rely on such
arrangements in the future as a source of liquidity. We are not a commercial
paper issuer.

Contractual Obligations and Commercial Commitments

We have a $225 million revolving bank credit facility (with a committed
borrowing base of $225 million) which matures in September 2003. As of December
31, 2001, we had no outstanding borrowings under this facility and had $1.1
million of the facility securing various letters of credit. Borrowings under the
facility are collateralized by certain producing oil and gas properties and bear
interest at either the reference rate of Union Bank of California, N.A., or
London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies
according to total facility usage. The collateral value and borrowing base are
redetermined periodically. The unused portion of the facility is subject to an
annual commitment fee of 0.50%. Interest is payable quarterly.

The credit facility agreement contains various covenants and restrictive
provisions including incurring additional indebtedness, selling properties,
paying dividends, purchasing or redeeming our capital stock, making investments
or loans or purchasing certain of our senior notes, creating liens, and making
acquisitions. The credit facility agreement requires us to maintain a current
ratio of at least 1 to 1 and a fixed charge coverage ratio of at least 2.5 to 1.
If we should fail to perform our obligations under these and other covenants,
the revolving credit commitment could be terminated and any outstanding
borrowings under the facility could be declared immediately due and payable.
Such acceleration, if involving a principal amount of $10 million or more, would
constitute an event of default under our senior note indentures, which could in
turn result in the acceleration of our senior note indebtedness. The credit
facility agreement also has cross default provisions that apply to other
indebtedness we may have with an outstanding principal amount in excess of $5.0
million.

As of December 31, 2001, senior notes represented $1.3 billion of our
long-term debt and consisted of the following: $800.0 million principal amount
of 8.125% senior notes due 2011, $250.0 million principal amount of 8.375%
senior notes due 2008, $150.0 million principal amount of 7.875% senior notes
due 2004 and $142.7 million principal amount of 8.5% senior notes due 2012.
There are no scheduled principal payments required on any of the senior notes
until March 2004, when $137.0 million is due, as a result of the repurchase and
retirement of

27

$13.0 million of our 7.875% senior notes in March 2002. Debt ratings for the
senior notes are B1 by Moody's Investor Service, B+ by Standard & Poor's Ratings
Services and BB- by Fitch Ratings as of December 31, 2001. Debt ratings for our
secured bank credit facility are Ba3 by Moody's Investor Service, BB by Standard
& Poor's Ratings Services and BB+ by Fitch Ratings.

Our senior notes are unsecured senior obligations of Chesapeake and rank
equally with all of our other unsecured indebtedness. All of our wholly owned
subsidiaries except Chesapeake Energy Marketing, Inc. guarantee the notes. The
7.875% senior notes are redeemable at our option at any time prior to March 15,
2004 at the make-whole price determined in accordance with the indenture. On or
after March 15, 2004, we may redeem the 8.5% senior notes at the redemption
price set forth in the indenture. We may redeem all or some of the 8.125% senior
notes at any time on and after April 1, 2006 at the redemption prices set forth
in the indenture and prior to such date pursuant to make-whole provisions in the
indenture. We may redeem the 8.375% senior notes at any time on and after
November 1, 2005 at the redemption prices set forth in the indenture and prior
to such date pursuant to make-whole provisions in the indenture. If we
repurchase at least $75 million of the 7.875% senior notes by August 31, 2003,
we may extend the bank credit facility until June 2005 for an amount equal to
the total revolving credit facility commitment less the outstanding amount of
the 7.875% senior notes plus $50 million.

The indentures for the 8.125% and 8.375% senior notes contain covenants
limiting our ability and our restricted subsidiaries' ability to incur
additional indebtedness; pay dividends on our capital stock or redeem,
repurchase or retire our capital stock or subordinated indebtedness; make
investments and other restricted payments; create restrictions on the payment of
dividends or other amounts to us from our restricted subsidiaries; incur liens;
engage in transactions with affiliates; sell assets; and consolidate, merge or
transfer assets. The debt incurrence covenants do not affect our ability to
borrow under or expand our secured credit facility. As of December 31, 2001, we
estimate that secured commercial bank indebtedness of approximately $383 million
could have been incurred under the most restrictive indenture covenant. The
indenture covenants do not apply to Chesapeake Energy Marketing, Inc., an
unrestricted subsidiary.

The table below summarizes our contractual obligations and commercial
commitments as of December 31, 2001:

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 with respect to our commodity price
risk management transactions exceed certain levels. At December 31, 2001, we
were not required to post any collateral. Future collateral requirements are
uncertain and will depend on arrangements with our counterparties and highly
volatile natural gas and oil prices.

Investing and Financing Transactions During 2001

We completed the acquisition of Gothic Energy Corporation on January 16,
2001 by merging a wholly-owned subsidiary into Gothic. We issued a total of 4.0
million common shares in the merger. Gothic shareholders (other than Chesapeake)
received 0.1908 of a share of Chesapeake common stock for each share of Gothic
common stock. In addition, outstanding warrants and options to purchase Gothic
common stock were converted to the right to purchase Chesapeake common stock
based on the merger exchange ratio. As of December 31, 2001, 1.1 million

28

shares of Chesapeake common stock may be purchased upon the exercise of such
warrants and options at an average price of $12.48 per share. In 2000,
Chesapeake purchased substantially all of Gothic's 14.125% senior secured
discount notes for total consideration of $80.8 million in cash and Chesapeake
common stock. We also purchased $31.6 million principal amount of 11.125% senior
secured notes due 2005 issued by Gothic's operating subsidiary for total
consideration of $34.8 million in cash and Chesapeake common stock. Subsequent
to the acquisition, we redeemed all remaining Gothic 14.125% discount notes for
total consideration of $243,000. In February 2001, we purchased $1.0 million
principal amount of Gothic senior secured notes tendered pursuant to a
change-of-control offer at a purchase price of 101%. During April and May 2001,
we purchased or redeemed the remaining $202.3 million of Gothic 11.125% senior
secured notes for total consideration of $225.9 million. On May 14, 2001, Gothic
Energy Corporation and Gothic Production Corporation became guarantor
subsidiaries of Chesapeake's senior notes.

During the first quarter 2001, we purchased and subsequently retired $7.3
million of our 8.5% senior notes due 2012 for total consideration of $7.4
million, including accrued interest of $0.2 million and the write-off of $0.1
million of unamortized bond discount.

On March 30, 2001, we issued 1.1 million shares of Chesapeake common stock
in exchange for 49.5% of RAM Energy, Inc.'s, outstanding common stock. Our
shares were valued at $8.854 each, or $9.9 million in total. We agreed to adjust
the consideration for our acquisition of RAM shares by making a cash payment to
the selling RAM shareholders equal to the shortfall if they sold the Chesapeake
shares they received at a price less than $8.854 per share. In the third quarter
of 2001, the RAM shareholders sold all their shares of Chesapeake common stock
at prices below this level and we made make-whole cash payments of $3.3 million
to them to cover the shortfall. In December 2001, we sold all the RAM shares we
owned for minimal consideration. In addition during 2001, we purchased $17.4
million principal amount of RAM's corporate notes for a total purchase price of
$15.2 million, including accrued interest of $0.6 million. On December 4, 2001
we purchased certain oil and gas assets owned by RAM located primarily in the
Mid-Continent. The consideration for this acquisition was $74.4 million,
consisting of $61.7 million of cash, surrender of $11.5 million principal amount
of our RAM notes including $0.4 million in accrued interest, and cancellation of
a $1.2 million receivable by us from RAM. Subsequent to year-end, we sold the
remaining $6.3 million principal amount of RAM notes, which had a carrying value
on our books of $3.8 million, for $4.4 million, including accrued interest of
$0.2 million.

On April 6, 2001, we issued $800.0 million principal amount of 8.125%
senior notes due 2011, all of which were subsequently exchanged for
substantially identical notes registered under the Securities Act of 1933. The
net proceeds were approximately $780.6 million. During April 2001, we used a
portion of the offering proceeds to purchase $140.7 million principal amount of
our 9.625% senior notes and $3.0 million principal amount of the 11.125% senior
secured notes of Gothic Production Corporation, a Chesapeake subsidiary. On May
7, 2001, we redeemed all $120.0 million principal amount of our 9.125% senior
notes, the remaining $359.3 million principal amount of our 9.625% senior notes
and the remaining $199.3 million principal amount of Gothic Production
Corporation's 11.125% senior secured notes. The purchase and redemption of these
notes included payment of aggregate make-whole and redemption premiums of $75.6
million and the write-off of unamortized debt costs and debt issue premiums. The
costs associated with the early extinguishment of debt were reflected as a $46.0
million after-tax extraordinary loss in 2001. The refinancing lowered the
interest rate and extended the maturity of approximately 74% of our senior notes
outstanding at that time.

In 2001, holders of our 7% cumulative convertible preferred stock converted
622,768 shares into 4,480,171 shares of common stock (at a conversion price of
$6.95 per share), and we redeemed the remaining 1,269 shares of 7% preferred
stock for 7,239 shares of common stock and $3,000 of cash (at a redemption price
of $52.45 per share, paid in 5.7 shares of common stock and cash of $2.45).

In July 2001, we purchased $22.5 million principal amount of 12% senior
secured notes due 2004 issued by Seven Seas Petroleum Inc. and detachable
seven-year warrants to purchase approximately 12.6 million shares of Seven Seas
common stock at an exercise price of approximately $1.78 per share. The shares
issuable upon exercise of the warrants represent approximately 20% of Seven Seas
outstanding common stock on a fully diluted basis. Seven Seas common stock is
listed for trading on the American Stock Exchange and the common shares
underlying our warrants have been registered under the federal securities laws
for resale. The 12% senior secured notes held by us and the $22.5 million of
notes acquired by other parties are secured by a pledge of substantially all of
the assets owned by Seven Seas, including all of the Seven Seas subsidiaries
which hold the concessions to the company's oil and gas interests in Colombia.

On September 21, 2001, our board of directors authorized the repurchase of
up to $50 million of our common stock, either through direct purchases or put
options. We have not made any repurchases or written any put options to date
under this program. The consent to the stock repurchase program we obtained
under our bank credit facility expires June 30, 2002.

29

On November 5, 2001, Chesapeake closed a private offering of $250.0 million
of 8.375% senior notes due 2008, all of which were exchanged on January 23, 2002
for substantially identical notes registered under the Securities Act of 1933.
The net proceeds were approximately $247.7 million. The 8.375% senior notes will
be redeemable by us prior to November 1, 2005 by payment of a make-whole
premium, and on and after November 1, 2005 at annually declining redemption
prices. The 8.375% senior notes are guaranteed by the same subsidiaries that
guarantee our other outstanding senior notes and are subject to covenants
substantially similar to those contained in the indenture for our 8.125% senior
notes.

On November 13, 2001, Chesapeake issued 3.0 million shares of 6.75%
cumulative convertible preferred stock, par value $.01 per share and a
liquidation preference of $50 per share, in a private offering. The net proceeds
from the offering were $145.1 million. Each preferred share is convertible at
any time at the option of the holder into 6.4935 shares of our common stock,
subject to adjustment. The conversion rate is based on an initial conversion
price of $7.70 per common share, plus cash in lieu of fractional shares. The
preferred stock is subject to mandatory conversion, at our option, (1) on or
after November 20, 2004 at the same rate if the market price of the common stock
equals or exceeds 130% of the conversion price at the time and (2) on or after
November 20, 2006 at the lower of the conversion price and the then current
market price of the common stock if there are less than 250,000 shares of
preferred stock outstanding at the time. Annual cumulative cash dividends of
$3.375 per share are payable quarterly on the fifteenth day of each February,
May, August and November. We have registered under the Securities Act of 1933
shares of the preferred stock and underlying common stock for resale by the
holders.

In private transactions completed in the fourth quarter of 2001 and January
2002, we acquired 7.65% of the outstanding common stock of Canaan Energy
Corporation, an oil and gas exploration and production company, for cash
consideration totaling $4.0 million, or $12.00 per share. On March 11, 2002, we
announced our intention to commence a cash tender offer to acquire Canaan for
$12.00 per share of common stock. The $12.00 offer price represents an aggregate
purchase price for the common stock on a fully diluted basis of approximately
$55.0 million plus the assumption of Canaan's debt, which was approximately
$42.0 million as of December 31, 2001. On March 15, 2002, we announced that we
would defer commencement of the tender offer based upon the representations of
Canaan senior management of their willingness to engage in good faith
discussions with us regarding the offer and upon their request that we delay
commencement of the tender offer until after the discussions. We may at any time
commence or modify our proposed tender offer for Canaan shares or terminate our
tender offer plans. If and when the tender offer is commenced, the complete
terms and conditions of the offer will be set forth in tender offer materials
that we will file with the Securities and Exchange Commission.

In March 2002, we purchased and subsequently retired $13.0 million of our
7.875% senior notes due 2004 for total consideration of $13.7 million, including
accrued interest of $0.4 million.

CRITICAL ACCOUNTING POLICIES

Readers of this document and users of the information contained in it
should be aware of how certain events may impact our financial results based on
the accounting policies in place. The three most significant policies are
discussed below.

Hedging. From time to time, Chesapeake uses commodity price risk management
instruments to hedge our exposure to price fluctuations in oil and natural gas
and interest rates. Recognized gains and losses on hedge contracts are reported
as a component of the related transaction. Results of oil and gas hedging
transactions are reflected in oil and gas sales to the extent related to our oil
and gas production. The changes in fair value of derivative instruments not
qualifying for designation as cash flow hedges that occur prior to maturity are
initially reported in the consolidated statement of operations as risk
management income (loss). All amounts initially recorded in this caption are
ultimately reversed within the same caption and included in oil and gas sales
over the respective contracts terms.

Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.
This statement establishes accounting and reporting standards requiring that
derivative instruments (including certain derivative instruments embedded in
other contracts) be recorded at fair value and included in the consolidated
balance sheet as assets or liabilities. The accounting for changes in the fair
value of a derivative instrument depends on the intended use of the derivative
and the resulting designation, which is established at the inception of a
derivative. Special accounting for qualifying hedges allows a derivative's gains
and losses to offset related results of the hedged item in the consolidated
statement of operations. For derivative instruments designated as cash flow
hedges, changes in fair value, to the extent the hedge is effective, are
recognized in other comprehensive income until the hedged item is recognized in
earnings. Hedge effectiveness is measured at least quarterly based on the
relative changes in fair value between the derivative contract and the

30

hedged item over time. Any change in fair value resulting from ineffectiveness,
as defined by SFAS 133, is recognized immediately in earnings. Changes in fair
value of contracts that do not meet the SFAS 133 definition of a cash flow hedge
are also recognized in earnings through risk management income. See Hedging
Activities and Item 7A - Quantitative and Qualitative Disclosures about Market
Risk for additional information regarding our hedging activities.

Oil and Gas Properties. Chesapeake follows the full-cost method of
accounting under which all costs associated with property acquisition,
exploration and development activities are capitalized. We capitalize internal
costs that can be directly identified with our acquisition, exploration and
development activities and do not include any costs related to production,
general corporate overhead or similar activities. Capitalized costs are
amortized on a composite unit-of-production method based on proved oil and gas
reserves. As of December 31, 2001, approximately 72% of our present value
(discounted at 10%) of estimated future net revenues of proved reserves was
evaluated by independent petroleum engineers, with the balance evaluated by our
internal reservoir engineers. In addition, our internal engineers reevaluate our
reserves on a quarterly basis.

Proceeds from the sale of properties are accounted for as reductions of
capitalized costs unless such sales involve a significant change in the
relationship between costs and the value of proved reserves or the underlying
value of unproved properties, in which case a gain or loss is recognized. The
costs of unproved properties are excluded from amortization until the properties
are evaluated. We review all of our unevaluated properties quarterly to
determine whether or not and to what extent proved reserves have been assigned
to the properties, and otherwise if impairment has occurred. Unevaluated
properties are grouped by major producing area where individual property costs
are not significant and are assessed individually when individual costs are
significant.

We review the carrying value of our oil and gas properties under the
full-cost accounting rules of the Securities and Exchange Commission on a
quarterly basis. Under these rules, capitalized costs, less accumulated
amortization and related deferred income taxes, may not exceed an amount equal
to the sum of the present value of estimated future net revenues less estimated
future expenditures to be incurred in developing and producing the proved
reserves, less any related income tax effects.

Income Taxes. As part of the process of preparing the consolidated
financial statements, we are required to estimate the income taxes in each of
the jurisdictions in which Chesapeake operates. This process involves estimating
the actual current tax exposure together with assessing temporary differences
resulting from differing treatment of items, such as derivative instruments,
depreciation, depletion and amortization, and certain accrued liabilities for
tax and accounting purposes. These differences and the net operating loss
carryforwards result in deferred tax assets and liabilities, which are included
in our consolidated balance sheet. We must then assess the likelihood that the
deferred tax assets will be recovered from future taxable income and to the
extent we believe that recovery is not likely, we must establish a valuation
allowance. To the extent Chesapeake establishes a valuation allowance or
increases or decreases this allowance in a period, we must include an expense or
reduction of expense within the tax provisions in the consolidated statement of
operations.

HEDGING ACTIVITIES

Our results of operations and operating cash flows are impacted by changes
in market prices for oil and gas. To mitigate a portion of this exposure to
adverse market changes, we have entered into derivative instruments. All of our
derivative instruments have been entered into as hedges of oil and gas price
risk and not for speculative purposes.

We utilize derivative instruments to reduce exposure to unfavorable changes
in oil and gas prices which are subject to significant and often volatile
fluctuations. As of December 31, 2001, our derivative instruments were comprised
of swaps, collars, cap-swaps and locked swaps. These instruments allow us to
predict with greater certainty the effective oil and gas prices to be received
for our hedged production.

Pursuant to SFAS 133, our cap-swaps do not qualify for designation as cash
flow hedges. Therefore, changes in the fair value of these instruments that
occur prior to their maturity, together with any changes in fair value of cash
flow hedges resulting from ineffectiveness, are reported in the consolidated
statement of operations as risk management income (loss). Amounts recorded in
risk management income (loss) do not represent cash gains or losses. Rather,
these amounts are temporary valuation swings in contracts or portions of
contracts that are not entitled to receive hedge accounting treatment. All
amounts initially recorded in this caption are ultimately reversed within this
same caption and included in oil and gas sales over the respective contract
terms.

31

The estimated fair values of our derivative instruments as of December 31,
2001 are provided below. The associated carrying values of these instruments are
equal to the estimated fair values.

We have established the fair value of all derivative instruments using
estimates of fair value reported by our counterparties. The actual contribution
to our future results of operations will be based on the market prices at the
time of settlement and may be more or less than the fair value estimates used at
December 31, 2001.

Additional information concerning the fair value of our derivative
instruments is as follows ($ in thousands):

Fair value of contracts outstanding at January 1, 2001 ............. $ (89,288)
Change in fair value of contracts during period .................... 351,989
Contracts realized or otherwise settled during the period .......... (105,392)
Fair value of new contracts when entered into during the period .... --
Changes in fair values attributable to changes in valuation
techniques and assumptions ...................................... --
---------
Fair value of contracts outstanding at December 31, 2001 ........... $ 157,309
=========

DISCLOSURES ABOUT EFFECTS OF TRANSACTIONS WITH RELATED PARTIES

Since Chesapeake was founded in 1989, our chief executive officer and chief
operating officer have acquired small working interests in certain of our oil
and gas properties by participating in our drilling activities. As of December
31, 2001, we had accounts receivable from our CEO and COO of $5.0 million and
$4.9 million, respectively, representing joint interest billings payable within
90 days. Under their employment agreements, the CEO and COO are permitted to
participate in all, or none, of the wells spudded by or on behalf of Chesapeake
during each calendar quarter, but they are not allowed to only participate in
select wells. A participation election is required to be received by the
Compensation Committee of Chesapeake's board of directors' 30 days prior to the
start of a quarter. Their participation is permitted only under the terms
outlined in their employment agreements, which, among other things, limit their
participation to a maximum working interest of 2.5% in a well and prohibits
participation in situations where Chesapeake's working interest would be reduced
below 12.5% as a result of their participation.

In October 2001, we sold Chesapeake Canada Corporation, a wholly-owned
subsidiary, for net proceeds of approximately $143.0 million. Our CEO and COO
each received $2.0 million related to their fractional ownership interest in
these Canadian assets, which they acquired and paid for pursuant to the terms of
their employment agreements. The portion of the proceeds allocated to our CEO
and COO was based upon the estimated fair values of the assets sold as
determined by management and the independent members of our board of directors
using a methodology similar to that used by Chesapeake for acquisitions of
assets from disinterested third parties.

During 2001, 2000 and 1999, we paid legal fees of $391,000, $439,000 and
$398,000, respectively, for legal services provided by a law firm of which a
director is a member.

32

RECENTLY ISSUED ACCOUNTING STANDARDS

In June 2001, the Financial Accounting Standards Board issued SFAS Nos. 141
and 142. SFAS No. 141, Business Combinations, requires that the purchase method
of accounting be used for all business combinations initiated after June 30,
2001. SFAS No. 142, Goodwill and Other Intangible Assets, changes the accounting
for goodwill from an amortization method to an impairment-only approach and will
be effective January 2002. We believe that adoption of this new standard will
not have an effect on our results of operations or our financial position. In
June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. We have not yet determined the effect of the adoption of SFAS 143
on our financial position or results of operations.

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. SFAS 144 is effective for fiscal years
beginning after December 15, 2002. This statement supersedes SFAS No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of, and amends Accounting Principles Board Opinion No. 30 for the
accounting and reporting of discontinued operations, as it relates to long-lived
assets. We believe the future impact of the adoption of SFAS 144 on our
financial position or results of operations will not be material.

FORWARD-LOOKING STATEMENTS

This report includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. Forward-looking statements give our current expectations
or forecasts of future events. They include statements regarding oil and gas
reserve estimates, planned capital expenditures, the drilling of oil and gas
wells and future acquisitions, expected oil and gas production, cash flow and
anticipated liquidity, business strategy and other plans and objectives for
future operations, expected future expenses and utilization of net operating
loss carryforwards. Statements concerning the fair values of derivative
contracts and their estimated contribution to our future results of operations
are based upon market information as of a specific date. These market prices are
subject to significant volatility.

Although we believe the expectations and forecasts reflected in these and
other forward-looking statements are reasonable, we can give no assurance they
will prove to have been correct. They can be affected by inaccurate assumptions
or by known or unknown risks and uncertainties. Factors that could cause actual
results to differ materially from expected results are described under "Risk
Factors" in Item 1 and include:

o the volatility of oil and gas prices,

o our substantial indebtedness,

o the cost and availability of drilling and production services,

o our commodity price risk management activities, including counterparty
contract performance risk,

o uncertainties inherent in estimating quantities of oil and gas
reserves, projecting future rates of production and the timing of
development expenditures,

o our ability to replace reserves,

o the availability of capital,

o uncertainties in evaluating oil and gas reserves of acquired
properties and associated potential liabilities,

o drilling and operating risks,

o our ability to generate future taxable income sufficient to utilize
our NOLs before expiration,

o future ownership changes which could result in additional limitations
to our NOLs,

o adverse effects of governmental and environmental regulation,

o losses possible from pending or future litigation,

o the strength and financial resources of our competitors, and

o the loss of officers or key employees.

We caution you not to place undue reliance on these forward-looking
statements, which speak only as of the date of this report, and we undertake no
obligation to update this information. We urge you to carefully review and
consider the disclosures made in this and our other reports filed with the
Securities and Exchange Commission that attempt to advise interested parties of
the risks and factors that may affect our business.

33

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

COMMODITY RISK MANAGEMENT ACTIVITY

Our results of operations and operating cash flows are impacted by changes
in market prices for oil and gas. To mitigate a portion of this exposure to
adverse market changes, we have entered into derivative instruments. All of our
derivative instruments have been entered into as hedges of oil and gas price
risk and not for speculative purposes.

We utilize derivative instruments to reduce exposure to unfavorable changes
in oil and gas prices which are subject to significant and often volatile
fluctuations. As of December 31, 2001, our derivative instruments were comprised
of swaps, collars, cap-swaps and locked swaps. These instruments allow us to
predict with greater certainty the effective oil and gas prices to be received
for our hedged production.

o For swap instruments, we receive a fixed price for the hedged
commodity and pay a floating market price, as defined in each
instrument, to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due to or
from the counterparty.

o Collars contain a fixed floor price (put) and ceiling price (call). If
the market price exceeds the call strike price or falls below the put
strike price, then we receive the fixed price and pay the market
price. If the market price is between the call and the put strike
price, then no payments are due from either party.

o For cap-swaps, we receive a fixed price for the hedged commodity and
pay a floating market price. The fixed price received by Chesapeake
includes a premium in exchange for a "cap" on the floating market
price, which limits the counterparty's exposure.

o Locked swaps consist of swap positions which have been effectively
closed by entering into a counter-swap instrument where we receive the
floating price for the hedged commodity and pay a fixed price to the
counterparty. At the time we enter into the counter-swap, the original
swap is designated as a non-qualifying cash flow hedge under SFAS 133.
The net values of both the swap and counter-swap are frozen and shown
as derivatives receivable or payable in the consolidated balance
sheet.

Pursuant to SFAS 133, our cap-swaps do not qualify for designation as cash
flow hedges. Therefore, changes in the fair value of these instruments that
occur prior to their maturity are reported in the statement of operations as
risk management income (loss). Amounts recorded in risk management income (loss)
do not represent cash gains or losses. Rather, these amounts are temporary
valuation swings in contracts or portions of contracts that are not entitled to
receive hedge accounting treatment. All amounts initially recorded in this
caption are ultimately reversed within this same caption and included in oil and
gas sales over the respective contract terms.

The estimated fair values of our derivative instruments as of December 31,
2001 are provided below. The associated carrying values of these instruments are
equal to the estimated fair values.

Although derivatives often fail to achieve 100% effectiveness for
accounting purposes, our derivative instruments continue to be highly effective
in achieving the risk management objectives for which they were intended.

The change in fair value of our derivative instruments since January 1,
2001 resulted from a decrease in market prices for natural gas and crude oil.
The majority of this change in fair value is reflected in accumulated other
comprehensive income, net of deferred income tax effects, in the December 31,
2001 consolidated balance sheet. Derivative assets reflected as current in the
consolidated balance sheet represent the estimated fair value of derivative
instrument settlements scheduled to occur over the subsequent twelve-month
period based on market prices for oil and gas as of the balance sheet date. The
derivative settlement amounts are not due and payable until the month in which
the related underlying hedged transaction occurs.

We expect to transfer approximately $33.7 million of the balance in
accumulated other comprehensive income, based upon the market prices at December
31, 2001, to earnings during the next 12 months when the forecasted transactions
actually occur. All forecasted transactions hedged as of December 31, 2001 are
expected to occur by December 2003.

As of December 31, 2001, we had the following open derivative instruments
designed to hedge a portion of our gas production for periods after December
2001:

The above table does not include locked swaps of 43,510,000 mmbtu for 2002
and 55,340,000 mmbtu for 2003.

Subsequent to December 31, 2001, we settled the gas swaps, gas cap-swaps
and gas collars for January, February and March 2002. Gains totaling $45.2
million will be recognized as price adjustments in the first quarter of 2002 and
are comprised of $19.1 million for gas swaps, $23.2 million for gas cap-swaps
and $2.9 million for gas collars. Any associated gains related to cap-swaps and
the ineffective portion of derivatives qualifying for hedge accounting that were
recognized during 2001 as risk management income will be reclassified from risk
management income to oil and gas sales during 2002.

35

As of December 31, 2001, we had the following open derivative instruments
designed to hedge a portion of our domestic crude oil production for periods
after December 2001:

Subsequent to December 31, 2001, we settled the oil cap-swaps for January
and February 2002 for gains of $1.0 million for oil swaps and $0.8 million for
oil cap-swaps. Any associated gains related to cap-swaps and the ineffectiveness
portions of derivatives qualifying for hedge accounting that were recognized
during 2001 as risk management income will be reclassified from risk management
income to oil and gas sales during 2002.

As of December 31, 2001, we closed certain swap transactions designed to
hedge a portion of our domestic oil and natural gas production. We refer to
these transactions as locked swaps. The net unrecognized gains resulting from
these transactions will be recognized as price adjustments in the months of
related production. At December 31, 2001, these amounts are classified as
derivative receivables on the consolidated balance sheet. These hedging gains
and losses are set forth below:

INTEREST RATE RISK

The table below presents principal cash flows and related weighted average
interest rates by expected maturity dates. The fair value of the fixed-rate
long-term debt has been estimated based on quoted market prices.

- ----------

(1) This amount does not include the discount of $13.2 million included in
long-tem debt.

Changes in interest rates affect the amount of interest we earn on our
cash, cash equivalents and short-term investments and the interest rate we pay
on borrowings under our revolving credit facility. At December 31, 2001, we were
not using any interest rate derivative instruments to manage exposure to
interest rate changes. All of our other long-term indebtedness is fixed rate and
therefore does not expose us to the risk of earnings or cash flow loss due to
changes in market interest rates. However, changes in interest rates do affect
the fair value of our debt.

36

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

CHESAPEAKE ENERGY CORPORATION

37

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholders
of Chesapeake Energy Corporation

In our opinion, the consolidated financial statements listed in the
accompanying index appearing under Item 8 of the Form 10-K present fairly, in
all material respects, the financial position of Chesapeake Energy Corporation
and its subsidiaries (the "Company") at December 31, 2000 and 2001, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule also listed in the accompanying index presents
fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. These financial
statements and financial statement schedule are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits. We
conducted our audits of these financial statements in accordance with auditing
standards generally accepted in the United States of America, which require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

As discussed in Note 1 to the financial statements, in 2001, the Company
changed its method of accounting for its hedging activities as a result of
adopting the provisions of Statement of Financial Accounting Standards No. 133
"Accounting for Derivative Instruments and Hedging Activities".

PricewaterhouseCoopers LLP
Oklahoma City, Oklahoma
March 8, 2002

38

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these
consolidated financial statements.

39

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

The accompanying notes are an integral part of these
consolidated financial statements.

40

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of these
consolidated financial statements.

41

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS --(CONTINUED)

SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:

In 2001, holders of our 7% cumulative convertible preferred stock converted
622,768 shares into 4,480,171 shares of common stock (at a conversion price of
$6.95 per share), and we redeemed the remaining 1,269 shares of preferred stock
for 7,239 shares of common stock and $3,000 of cash (at a redemption price of
$52.45 per share, paid in 5.7 shares of common stock and cash of $2.45).

In 2001, Chesapeake completed the acquisition of Gothic Energy Corporation.
We issued 3,989,813 shares of Chesapeake common stock to Gothic shareholders
(other than Chesapeake).

In 2001, we issued 1,117,216 shares of Chesapeake common stock in exchange
for 49.5% of RAM Energy, Inc.'s outstanding common stock. Chesapeake shares were
valued at $8.854 per share. Subsequently, we made a make-whole payment to the
former RAM shareholders of $3.3 million.

In 2001, Chesapeake purchased certain oil and gas assets from RAM Energy,
Inc. for a total consideration of $74.4 million, consisting of $61.7 million of
cash, surrender of $11.5 million principal amount of our RAM notes including
$0.4 million in accrued interest, and cancellation of a $1.2 million receivable
by us from RAM.

During 2000, Chesapeake engaged in unsolicited transactions in which a
total of 43.4 million shares of Chesapeake common stock, plus a cash payment of
$8.3 million, were exchanged for 3,972,363 shares of Chesapeake preferred stock.

During 2000, Chesapeake Energy Marketing, Inc. purchased 99.8% of Gothic
Energy Corporation's $104 million 14.125% Series B senior secured discount notes
for total consideration of $80.8 million, comprised of $17.2 million in cash and
$63.6 million of Chesapeake common stock (8,875,775 shares valued at $7.16 per
share), as adjusted for make-whole provisions. Through the make-whole
provisions, Chesapeake Energy Marketing, Inc. received $6.1 million in cash and
$7.2 million of Chesapeake common stock (982,562 shares).

In 2000, Chesapeake purchased $31.6 million of the $235 million of 11.125%
senior secured notes issued by Gothic Production Corporation for total
consideration of $34.8 million, comprised of $11.5 million in cash and $23.3
million of Chesapeake common stock (3,694,939 shares valued at $6.30 per share),
as adjusted for make-whole provisions. Through the make-whole provisions,
Chesapeake received $1.0 million in cash.

In 1999, the chief executive officer and chief operating officer of
Chesapeake tendered to Chesapeake Energy Marketing, Inc. 2,320,107 shares of
Chesapeake common stock in full satisfaction of two notes payable to CEMI with a
combined outstanding balance of $7.6 million. At the time, Chesapeake's stock
price was $3.29 per share and Chesapeake received full value for the
satisfaction of the two notes.

During 1999, we issued a $2.2 million note payable as consideration for the
acquisition of certain oil and gas properties.

The accompanying notes are an integral part of these
consolidated financial statements.

42

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)

The accompanying notes are an integral part of these
consolidated financial statements.

43

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

The accompanying notes are an integral part of these
consolidated financial statements.

44

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Company

Chesapeake Energy Corporation is an oil and natural gas exploration and
production company engaged in the acquisition, exploration, and development of
properties for the production of crude oil and natural gas from underground
reservoirs and the marketing of natural gas and oil for other working interest
owners in properties we operate. Our properties are located in Oklahoma, Texas,
Arkansas, Louisiana, Kansas, Montana, Colorado, North Dakota and New Mexico.

Principles of Consolidation

The accompanying consolidated financial statements of Chesapeake Energy
Corporation include the accounts of our direct and indirect wholly-owned
subsidiaries. All significant intercompany accounts and transactions have been
eliminated. Investments in companies and partnerships which give us significant
influence, but not control, over the investee are accounted for using the equity
method. Other investments are generally carried at cost.

Accounting Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the dates of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from those estimates.

Cash Equivalents

For purposes of the consolidated financial statements, Chesapeake considers
investments in all highly liquid debt instruments with maturities of three
months or less at date of purchase to be cash equivalents.

Inventory

Inventory, which is included in other current assets, consists primarily of
tubular goods and other lease and well equipment which we plan to utilize in our
ongoing exploration and development activities and is carried at the lower of
cost or market using the specific identification method.

Oil and Gas Properties

Chesapeake follows the full-cost method of accounting under which all costs
associated with property acquisition, exploration and development activities are
capitalized. We capitalize internal costs that can be directly identified with
our acquisition, exploration and development activities and do not include any
costs related to production, general corporate overhead or similar activities
(see note 11). Capitalized costs are amortized on a composite unit-of-production
method based on proved oil and gas reserves. As of December 31, 2001,
approximately 72% of our present value (discounted at 10%) of estimated future
net revenues of proved reserves was evaluated by independent petroleum
engineers, with the balance evaluated by our internal reservoir engineers. In
addition, our internal engineers evaluate all properties quarterly. The average
composite rates used for depreciation, depletion and amortization were $1.07
($1.08 in U.S. and $0.90 in Canada) per equivalent mcf in 2001, $0.75 ($0.76 in
U.S. and $0.71 in Canada) per equivalent mcf in 2000, and $0.71 ($0.73 in U.S.
and $0.52 in Canada) per equivalent mcf in 1999.

Proceeds from the sale of properties are accounted for as reductions of
capitalized costs unless such sales involve a significant change in the
relationship between costs and the value of proved reserves or the underlying
value of unproved properties, in which case a gain or loss is recognized. The
costs of unproved properties are excluded from amortization until the properties
are evaluated. We review all of our unevaluated properties quarterly to
determine whether or not and to what extent proved reserves have been assigned
to the properties, and otherwise if impairment has occurred. Unevaluated
properties are grouped by major producing area where individual property costs
are not significant and are assessed individually when individual costs are
significant.

45

We review the carrying value of our oil and gas properties under the
full-cost accounting rules of the Securities and Exchange Commission on a
quarterly basis. Under these rules, capitalized costs, less accumulated
amortization and related deferred income taxes, may not exceed an amount equal
to the sum of the present value of estimated future net revenues less estimated
future expenditures to be incurred in developing and producing the proved
reserves, less any related income tax effects.

Other Property and Equipment

Other property and equipment consists primarily of gas gathering and
processing facilities, drilling rigs, vehicles, land, office buildings and
equipment, and software. Major renewals and betterments are capitalized while
the costs of repairs and maintenance are charged to expense as incurred. The
costs of assets retired or otherwise disposed of and the applicable accumulated
depreciation are removed from the accounts, and the resulting gain or loss is
reflected in operations. Other property and equipment costs are depreciated on
both straight-line and accelerated methods. Buildings are depreciated on a
straight-line basis over 31.5 years. Drilling rigs are depreciated on a
straight-line basis over 12 years. All other property and equipment are
depreciated over the estimated useful lives of the assets, which range from five
to seven years.

Capitalized Interest

During 2001, 2000 and 1999, interest of approximately $4.7 million, $2.4
million and $3.5 million, respectively, was capitalized on significant
investments in unproved properties that were not being currently depreciated,
depleted, or amortized and on which exploration activities were in progress.
Interest is capitalized using the weighted average interest rate on our
outstanding borrowings.

Income Taxes

Chesapeake has adopted Statement of Financial Accounting Standards No. 109,
Accounting for Income Taxes. SFAS 109 requires deferred tax liabilities or
assets to be recognized for the anticipated future tax effects of temporary
differences that arise as a result of the differences in the carrying amounts
and the tax bases of assets and liabilities.

Net Income (Loss) Per Share

Statement of Financial Accounting Standards No. 128, Earnings Per Share,
requires presentation of "basic" and "diluted" earnings per share, as defined,
on the face of the statements of operations for all entities with complex
capital structures. SFAS 128 requires a reconciliation of the numerator and
denominator of the basic and diluted EPS computations.

The following securities were not included in the calculation of diluted
earnings per share, as the effect was antidilutive:

o For the year ended December 31, 2001, outstanding warrants to purchase
1.1 million shares of common stock at a weighted average exercise
price of $12.61 were antidilutive because the exercise prices of the
warrants were greater than the average market price of the common
stock.

o For the years ended December 31, 2001, 2000 and 1999, outstanding
options to purchase 0.3 million, 1.1 million, and 1.3 million shares
of common stock at a weighted average exercise price of $15.54, $8.73,
and $7.14, respectively, were antidilutive because the exercise prices
of the options were greater than the average market price of the
common stock.

o For the year ended December 31, 1999, the assumed conversion of the
outstanding 7% preferred stock (convertible into 33 million common
shares) was not included as the effect was antidilutive.

46

A reconciliation for the years ended December 31, 1999, 2000 and 2001 is as
follows:

In 2001, holders of our 7% cumulative convertible preferred stock converted
622,768 shares into 4,480,171 shares of common stock (at a conversion price of
$6.95 per share), and we redeemed the remaining 1,269 shares of 7% preferred
stock for 7,239 shares of common stock and $3,000 of cash (at a redemption price
of $52.45 per share, paid in 5.7 shares of common stock and cash of $2.45).

On November 13, 2001, we issued 3.0 million shares of 6.75% cumulative
convertible preferred stock, par value $0.01 per share and liquidation
preference $50 per share, in a private offering. We subsequently registered
under the Securities Act of 1933 shares of the preferred stock and underlying
common stock for resale by the holders.

During the year ended December 31, 2000, Chesapeake engaged in a number of
unsolicited stock transactions with institutional investors. A total of 43.4
million shares of common stock, plus a cash payment of $8.3 million, were
exchanged for 3,972,363 shares of 7% preferred stock. These transactions reduced
(i) the number of preferred shares from 4.6 million to 0.6 million, (ii) the
liquidation value of the preferred stock from $229.8 million to $31.2 million,
and (iii) dividends in arrears by $22.9 million. A gain on redemption of all
preferred shares exchanged during 2000 of $6.6 million is reflected in net
income available to common shareholders in determining basic earnings per share.
All preferred shares acquired in these transactions were canceled and retired
and restored to the status of authorized but unissued shares of undesignated
preferred stock. The gain represented the excess of (i) the liquidation value of
the preferred shares that were retired plus dividends in arrears which had
reduced prior EPS over (ii) the market value of the common stock issued and cash
paid in exchange for the preferred shares.

47

Gas Imbalances -- Revenue Recognition

Revenues from the sale of oil and gas production are recognized when title
passes, net of royalties. We follow the "sales method" of accounting for our gas
revenue whereby we recognize sales revenue on all gas sold to our purchasers,
regardless of whether the sales are proportionate to our ownership in the
property. A liability is recognized only to the extent that we have an imbalance
in excess of the remaining gas reserves on the underlying properties.

Hedging

Chesapeake periodically uses commodity price risk management instruments to
hedge our exposure to price fluctuations in oil and natural gas transactions and
interest rates. Recognized gains and losses on hedge contracts are reported as a
component of the related transaction. Results of oil and gas hedging
transactions are reflected in oil and gas sales to the extent related to our oil
and gas production. The changes in fair value of derivative instruments not
qualifying for designation as cash flow hedges that occur prior to maturity are
initially reported in the statement of operations as risk management income
(loss). All amounts recorded in this caption are ultimately reversed within the
same caption and included in oil and gas sales over the respective contract
terms.

Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.
This statement establishes accounting and reporting standards requiring that
derivative instruments (including certain derivative instruments embedded in
other contracts) be recorded at fair value and included in the consolidated
balance sheet as assets or liabilities. The accounting for changes in the fair
value of a derivative instrument depends on the intended use of the derivative
and the resulting designation, which is established at the inception of a
derivative. Special accounting for qualifying hedges allows a derivative's gains
and losses to offset related results of the hedged item in the consolidated
statement of operations. For derivative instruments designated as cash flow
hedges, changes in fair value, to the extent the hedge is effective, are
recognized in other comprehensive income until the hedged item is recognized in
earnings. Hedge effectiveness is measured at least quarterly based on the
relative changes in fair value between the derivative contract and the hedged
item over time. Any change in fair value resulting from ineffectiveness, as
defined by SFAS 133, is recognized immediately in earnings. Changes in fair
value of contracts that do not meet the SFAS 133 definition of a cash flow hedge
are also recognized in earnings through risk management income.

Adoption of SFAS 133 at January 1, 2001 resulted in the recognition of $9.3
million of current derivative assets and $98.6 million in current derivative
liabilities. The cumulative effect of the accounting change decreased
accumulated other comprehensive income by $53.6 million, net of income tax, but
did not have an effect on our net income or earnings per share amounts.

Debt Issue Costs

Included in other assets are costs associated with the issuance of our
senior notes and amendments to our revolving bank credit facility. The remaining
unamortized debt issue costs at December 31, 2001 and 2000 totaled $16.6 million
and $15.8 million, respectively, and are being amortized over the life of the
senior notes or revolving credit facility.

Currency Translation

The results of operations for non-U.S. subsidiaries are translated from
local currencies into U.S. dollars using average exchange rates during each
period; assets and liabilities are translated using exchange rates at the end of
each period. Adjustments resulting from the translation process are reported in
a separate component of stockholders' equity, and are not included in the
determination of the results of operations. In October 2001, we sold our
Canadian subsidiary. As a result, all translation adjustments related to our
investment in this subsidiary were reclassified in the fourth quarter of 2001.

Reclassifications

Certain reclassifications have been made to the consolidated financial
statements for 1999 and 2000 to conform to the presentation used for the 2001
consolidated financial statements.

2. SENIOR NOTES

On November 5, 2001, Chesapeake closed a private offering of $250.0 million
of 8.375% senior notes due 2008, all of which were exchanged on January 23, 2002
for substantially identical notes registered under the Securities Act of 1933.
The 8.375% senior notes will be redeemable by us prior to November 1, 2005 by
payment of a call or redemption premium, and on and after November 1, 2005 at
annually declining redemption prices. The 8.375%

48

senior notes are guaranteed by the same subsidiaries that guarantee our other
outstanding senior notes and are subject to covenants substantially similar to
those contained in the indenture for our 8.125% senior notes.

On April 6, 2001, we issued $800.0 million principal amount of 8.125%
senior notes due 2011, substantially all of which were exchanged on July 12,
2001 for substantially identical notes registered under the Securities Act of
1933. During April 2001, we used a portion of the offering proceeds to purchase
$140.7 million principal amount of our 9.625% senior notes and $3.0 million
principal amount of the 11.125% senior secured notes of Gothic Production
Corporation, a Chesapeake subsidiary. On May 7, 2001, we redeemed all $120.0
million principal amount of our 9.125% senior notes, the remaining $359.3
million principal amount of our 9.625% senior notes and the remaining $199.3
million principal amount of Gothic Production Corporation's 11.125% senior
secured notes. The purchase and redemption of these notes included payment of
aggregate make-whole and redemption premiums of $75.6 million and the write-off
of unamortized debt costs and debt issue premiums. The costs associated with the
early extinguishment of debt are reflected as a $46.0 million after-tax
extraordinary loss in 2001.

On January 16, 2001, we acquired Gothic Energy Corporation and assumed its
note obligations. At that date, there was outstanding $203.3 million principal
amount of 11.125% senior secured notes due 2005 which had been issued by Gothic
Production Corporation and guaranteed by Gothic Energy Corporation, its parent.
In February 2001, we purchased $1.0 million principal amount of these notes
tendered pursuant to a change-of-control offer at a purchase price of 101%. In
April 2001, we purchased $3.0 million of these notes for total consideration of
$3.5 million, including $0.1 million in interest and $0.4 million in premium. On
May 7, 2001, we redeemed the remaining notes ($199.3 million principal amount)
for total consideration of $222.5 million, including $0.4 million in interest
and $22.8 million in redemption premium.

On April 22, 1998, we issued $500.0 million principal amount of 9.625%
senior notes due 2005. In April 2001, we purchased $140.7 million of these notes
for total consideration of $160.2 million, including a $13.6 million premium and
interest of $5.9 million. On May 7, 2001, we redeemed the remaining notes,
$359.3 million principal amount, for total consideration of $393.3 million,
including $0.6 million of interest and $33.4 million of redemption premium.

On March 17, 1997, we issued $150.0 million principal amount of 7.875%
senior notes due 2004. The 7.875% senior notes are redeemable at our option at
any time prior to March 15, 2004 at the make-whole prices determined in
accordance with the indenture.

Also on March 17, 1997, we issued $150.0 million principal amount of 8.5%
senior notes due 2012. The 8.5% senior notes are redeemable at our option at any
time prior to March 15, 2004 at the make-whole prices determined in accordance
with the indenture and, on or after March 15, 2004, at the redemption prices set
forth in the indenture. During the quarter ended March 31, 2001, Chesapeake
purchased and subsequently retired $7.3 million of these notes for total
consideration of $7.4 million, including accrued interest of $0.2 million and
the write-off of $0.1 million of unamortized bond discount.

On April 9, 1996, we issued $120.0 million principal amount of 9.125%
senior notes due 2006. On May 7, 2001, we redeemed these notes for total
consideration of $126.1 million, including $0.7 million in interest and $5.4
million of redemption premium.

Chesapeake is a holding company and owns no operating assets and has no
significant operations independent of its subsidiaries. Our obligations under
the 8.375% senior notes, the 8.125% senior notes, the 7.875% senior notes and
the 8.5% senior notes have been fully and unconditionally guaranteed, on a joint
and several basis, by each of our "restricted subsidiaries" (as defined in the
respective indentures governing these notes) (collectively, the "guarantor
subsidiaries"). Each guarantor subsidiary is a direct or indirect wholly-owned
subsidiary.

The senior note indentures contain covenants limiting us and the guarantor
subsidiaries with respect to asset sales; restricted payments; the incurrence of
additional indebtedness and the issuance of preferred stock; liens; sale and
leaseback transactions; lines of business; dividend and other payment
restrictions affecting guarantor subsidiaries; mergers or consolidations; and
transactions with affiliates.

The senior note indentures also limit our ability to make restricted
payments (as defined), including the payment of cash dividends, unless the debt
incurrence and other tests are met. From December 31, 1998 through March 31,
2000, we were unable to meet the requirements to incur additional unsecured
indebtedness, and consequently were restricted from paying cash dividends on our
7% cumulative convertible preferred stock. On September 22, 2000, we declared a
regular quarterly dividend and a special dividend equal to all unpaid dividends
on our preferred stock, both payable November 1, 2000 to shareholders of record
on October 16, 2000. A total combined dividend of $7.444 per outstanding
preferred share was paid November 1, 2000.

49

Set forth below are condensed consolidating financial statements of the
guarantor subsidiaries and our subsidiaries which are not guarantors of the
senior notes. Chesapeake Energy Marketing, Inc. was a non-guarantor subsidiary
for all periods presented. All of our other wholly-owned subsidiaries were
guarantor subsidiaries during all periods presented.

50

CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2000
($ IN THOUSANDS)

51

CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2001
($ IN THOUSANDS)

52

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)

53

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)

54

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)

55

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)

56

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
($ IN THOUSANDS)

57

3. NOTES PAYABLE AND LONG-TERM DEBT

Notes payable and long-term debt consist of the following:

We have a $225 million revolving bank credit facility (with a committed
borrowing base of $225 million) which matures in September 2003. As of December
31, 2001, we had no outstanding borrowings under this facility and had $1.1
million of the facility securing various letters of credit. Borrowings under the
facility are collateralized by certain producing oil and gas properties and bear
interest at either the reference rate of Union Bank of California, N.A., or
London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies
according to total facility usage. The unused portion of the facility is subject
to an annual commitment fee of 0.50%. Interest is payable quarterly. The
collateral value and borrowing base are redetermined periodically. The maturity
of the bank credit facility can be extended to June 2005 provided certain
conditions are met.

The credit facility agreement contains various covenants and restrictive
provisions including incurring additional indebtedness, selling properties,
paying dividends, purchasing or redeeming our capital stock, making investments
or loans, purchasing certain of our senior notes, creating liens, and making
acquisitions. The credit facility agreement requires us to maintain a current
ratio of at least 1 to 1 and a fixed charge coverage ratio of at least 2.5 to 1.
If we should fail to perform our obligations under these and other covenants,
the revolving credit commitment could be terminated and any outstanding
borrowings under the facility could be declared immediately due and payable.
Such acceleration, if involving a principal amount of $10 million or more, would
constitute an event of default under our senior note indentures, which could in
turn result in the acceleration of our senior note indebtedness. The credit
facility agreement also has cross default provisions that apply to other
indebtedness we may have with an outstanding principal amount in excess of $5.0
million.

The aggregate scheduled maturities of notes payable and long-term debt for
the five fiscal years ending December 31, 2006 and thereafter were as follows as
of December 31, 2001 ($ in thousands):

2002 ............................................ $ 602
2003 ............................................ --
2004 ............................................ 149,962
2005 ............................................ --
2006 ............................................ --
After 2006 ...................................... 1,179,491
----------
$1,330,055
==========

4. CONTINGENCIES AND COMMITMENTS

West Panhandle Field Cessation Cases. One of our subsidiaries, Chesapeake
Panhandle Limited Partnership ("CP") (f/k/a MC Panhandle, Inc.), and two
subsidiaries of Kinder Morgan, Inc. have been defendants in 16 lawsuits filed
between June 1997 and December 2001 by royalty owners seeking the cancellation
of oil and gas leases in the West Panhandle Field in Texas. MC Panhandle, Inc.,
which we acquired in April 1998, has owned the leases since January 1, 1997. The
co-defendants are prior lessees. The plaintiffs in these cases have claimed the
leases terminated upon the cessation of production for various periods,
primarily during the 1960s. In addition, the plaintiffs have sought to recover
conversion damages, exemplary damages, attorneys' fees and interest. The
defendants have asserted that any cessation of production was excused and have
pled affirmative defenses of

58

limitations, waiver, temporary estoppel, laches and title by adverse possession.
Four of the 16 cases have been tried, and there have been appellate decisions in
three of them.

In January 2001, we settled the claims of the principal plaintiffs in eight
cases tried or pending in the District Court of Moore County, Texas, 69th
Judicial District. The settlement was not material to our financial condition or
results of operations. In December 2001, the Texas Supreme Court accepted for
review petitions we filed with respect to the claims of plaintiffs in two of
these cases who were not covered by the settlement. The Court heard oral
arguments in March 2002.

There are eight other related West Panhandle cessation cases which continue
to be pending, three in the District Court of Moore County, Texas, 69th Judicial
District, two in the District Court of Carson County, Texas, 100th Judicial
District, and three in the U.S. District Court, Northern District of Texas,
Amarillo Division. In one of the Moore County cases, CP and the other defendants
have appealed a January 2000 judgment notwithstanding verdict in favor of
plaintiffs. In addition to quieting title to the lease (including existing gas
wells and all attached equipment) in plaintiffs, the court awarded actual
damages against CP in the amount of $716,400 and exemplary damages in the amount
of $25,000. The court further awarded, jointly and severally from all
defendants, $160,000 in attorneys' fees and interest and court costs. On March
28, 2001, the Amarillo Court of Appeals reversed and rendered judgment in favor
of CP and the other defendants, finding that the subject leases had been revived
as a matter of law, making all other issues moot. Plaintiffs have filed
petitions requesting that the Texas Supreme Court accept the case for review. In
another of the Moore County, Texas cases, in June 1999, the court granted
plaintiffs' motion for summary judgment in part, finding that the lease had
terminated due to the cessation of production, subject to the defendants'
affirmative defenses. In February 2001, the court granted plaintiffs' motion for
summary judgment on defendants' affirmative defenses but reversed its ruling
that the lease had terminated as a matter of law. In one of the U.S. District
Court cases, after a trial in May 1999, the jury found plaintiffs' claims were
barred by the payment of shut-in royalties, laches and revivor. Plaintiffs have
moved for a new trial. There are motions pending in two other cases, and the
remaining three cases are in the pleading stage.

We have previously established an accrued liability we believe will be
sufficient to cover the estimated costs of litigation for each of the pending
cases. Because of the inconsistent verdicts reached by the juries in the four
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 the amount of
damages that might ultimately be awarded could differ from management's
estimates. CP and the other defendants are vigorously defending against the
plaintiffs' claims.

Chesapeake is currently involved in various other routine disputes
incidental to its business operations. Management, after consultation with legal
counsel, is of the opinion that the final resolution of all such currently
pending or threatened litigation is not likely to have a material adverse effect
on the consolidated financial position or results of operations of Chesapeake.

Chesapeake has employment agreements with its chief executive officer,
chief operating officer and chief financial officer and various other senior
management personnel which provide for annual base salaries, bonus compensation
and various benefits. The agreements provide for the continuation of salary and
benefits for varying terms in the event of termination of employment without
cause. The agreements with the chief executive officer and chief operating
officer have terms of five years commencing July 1, 2001. The term of each
agreement is automatically extended for one additional year on each June 30
unless one of the parties provides 30 days notice of non-extension. The
agreements with the chief financial officer and other senior managers expire on
June 30, 2003. The employment agreements with the chief executive officer and
chief operating officer provide that in the event of a change in control, under
some circumstances, each is entitled to receive a payment in the amount of five
times his base compensation and the prior year's benefits, plus a tax gross-up
payment.

Due to the nature of the oil and gas business, Chesapeake and its
subsidiaries are exposed to possible environmental risks. Chesapeake has
implemented various policies and procedures to avoid environmental contamination
and risks from environmental contamination. Chesapeake is not aware of any
potential material environmental issues or claims.

Chesapeake has entered into various operating leases for office space and
equipment. Future minimum lease payments required as of December 31, 2001
related to these operating leases are as follows ($ in thousands):

2002 .................... $1,336
2003 .................... 683
2004 .................... 567
2005 .................... 244
------
Total ................. $2,830
======

Rent expense, including short-term rentals, for the years ended December
31, 2001, 2000, 1999 was $6.4 million, $4.4 million and $4.1 million,
respectively.

59

5. INCOME TAXES

The components of the income tax provision (benefit) for each of the
periods presented below are as follows:

The effective income tax expense (benefit) differed from the computed
"expected" federal income tax expense (benefit) on earnings before income taxes
and extraordinary item for the following reasons:

Deferred income taxes are provided to reflect temporary differences in the
basis of net assets for income tax and financial reporting purposes. The
tax-effected temporary differences and tax loss carryforwards which comprise
deferred taxes are as follows:

SFAS 109 requires that we record a valuation allowance when it is more
likely than not that some portion or all of deferred tax assets will not be
realized. In the fourth quarter of 2000, we eliminated our existing valuation
allowance which resulted in the recognition of a $265.0 million income tax
benefit. This resulted in an increase to 2000 net income of $265.0 million, or
$1.75 per diluted share. Based upon results of operations as of December 31,
2000 and anticipated improvement in Chesapeake's outlook for sustained
profitability, we believed that it was more likely than not that we would
generate sufficient future taxable income to realize the tax benefits associated
with our NOL carryforwards prior to their expiration. As of December 31, 2001,
we have determined that it is more likely than not that $2.4 million of the net
deferred tax assets related to Louisiana net operating losses will not be
realized and have recorded a valuation allowance equal to such amounts.

60

At December 31, 2000, we classified $40.8 million of our deferred tax
assets as current to recognize the portion of the NOL carryover that was
expected to be utilized to reduce taxable income in 2001. As of December 31,
2001, we classified $48.9 million of deferred tax assets related to NOLs as
current to offset the current deferred tax liability attributable to the current
portion of derivative assets.

At December 31, 2001, Chesapeake had federal and state income tax net
operating loss (NOL) carryforwards of approximately $757.7 million.
Additionally, we had approximately $419.8 million of alternative minimum tax
(AMT) NOL carryforwards available as a deduction against future AMT income and
approximately $5.7 million of percentage depletion carryforwards. The NOL
carryforwards expire from 2010 through 2021. 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. A summary of our NOLs follows:

The ability of Chesapeake to utilize NOL carryforwards to reduce future
federal taxable income and federal income tax of Chesapeake 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 or 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 ownership changes in January 1995 and March 1998
which triggered limitations. Certain NOLs acquired through various acquisitions
are also subject to limitations. Of the $757.7 million NOLs and $419.8 million
AMT NOLs, $339.5 million and $84.1 million, respectively, are limited under
Section 382. Therefore, $418.2 million of the NOLs and $335.7 million of the AMT
NOLs are not subject to the limitation. The utilization of $339.5 million of the
NOLs and the utilization of $84.1 million of the AMT NOLs subject to the Section
382 limitation are limited to approximately $37.9 million and $12.3 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,
2001. 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.

6. RELATED PARTY TRANSACTIONS

Since Chesapeake was founded in 1989, our chief executive officer and chief
operating officer have acquired small working interests in certain of our oil
and gas properties by participating in our drilling activities. As of December
31, 2001, we had accounts receivable from our CEO and COO of $5.0 million and
$4.9 million, respectively, representing joint interest billings payable within
90 days. Under their employment agreements, the CEO and COO are permitted to
participate in all, or none, of the wells spudded by or on behalf of Chesapeake
during each calendar quarter, but they are not allowed to only participate in
select wells. A participation election is required to be received by the
Compensation Committee of Chesapeake's board of directors' 30 days prior to the
start of a quarter. Their participation is permitted only under the terms
outlined in their employment agreements, which, among other things, limit their
participation to a maximum working interest of 2.5% in a well and prohibits
participation in situations where Chesapeake's working interest would be reduced
below 12.5% as a result of their participation.

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As of December 31, 1998, our CEO and COO had notes payable to Chesapeake
Energy Marketing, Inc..in the principal amount of $9.9 million. In November
1999, our CEO and COO tendered 2,320,107 shares of Chesapeake common stock in
full satisfaction of the notes, which had a combined outstanding balance of $7.6
million. The common stock was valued at $3.29 per share, which was the market
value of the stock at the time of the transaction.

In October 2001, we sold Chesapeake Canada Corporation, a wholly-owned
subsidiary, for net proceeds of approximately $143.0 million. Our CEO and COO
each received $2.0 million related to their fractional ownership interest in
these Canadian assets, which they acquired and paid for pursuant to the terms of
their employment agreements. The portion of the proceeds allocated to our CEO
and COO was based upon the estimated fair values of the assets sold as
determined by management and the independent members of our board of directors
using a methodology similar to that used by Chesapeake for acquisitions of
assets from disinterested third parties.

During 2001, 2000, and 1999, we paid legal fees of $391,000, $439,000 and
$398,000, respectively, for legal services provided by a law firm of which a
director is a member.

7. EMPLOYEE BENEFIT PLANS

We maintain the Chesapeake Energy Corporation Savings and Incentive Stock
Bonus Plan, a 401(k) profit sharing plan. Eligible employees may make voluntary
contributions to the plan which Chesapeake matches up to 10% of the employee's
annual salary with Chesapeake's common stock purchased in the open-market. The
amount of employee contribution is limited as specified in the plan. We may, at
our discretion, make additional contributions to the plan. We contributed $2.0
million, $1.5 million and $1.2 million to the plan during 2001, 2000 and 1999,
respectively.

8. MAJOR CUSTOMERS AND SEGMENT INFORMATION

Sales to individual customers constituting 10% or more of total oil and gas
sales were as follows:

Management believes that the loss of any of the above customers would not
have a material impact on our results of operations or our financial position.

Chesapeake has two reportable segments under SFAS No. 131, Disclosures
about Segments of an Enterprise and Related Information, consisting of
exploration and production, and marketing. The reportable segment information
can be derived from note 2 as Chesapeake Energy Marketing, Inc., which is our
marketing segment, is the only non-guarantor subsidiary for all periods
presented. The geographic distribution of our revenue, operating income and
long-lived assets is summarized below:

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9. STOCKHOLDERS' EQUITY AND STOCK-BASED COMPENSATION

In January 2001, we issued 4.0 million common shares to the Gothic
shareholders. They received 0.1908 of a share of Chesapeake common stock for
each share of the Gothic common stock. In addition, outstanding warrants and
options to purchase Gothic common stock were converted to the right to purchase
Chesapeake common stock based on the merger exchange ratio. As of December 31,
2001, 1.1 million shares of Chesapeake common stock may be purchased upon the
exercise of such warrants and options at an average price of $12.48 per share.

In 2001, holders of our 7% cumulative convertible preferred stock converted
622,768 shares into 4,480,171 shares of common stock (at a conversion price of
$6.95 per share), and we redeemed the remaining 1,269 shares of preferred stock
for 7,239 shares of common stock and $3,000 of cash (at a redemption price of
$52.45 per share, paid in 5.7 shares of common stock and cash of $2.45).

On March 30, 2001, we issued 1.1 million shares of Chesapeake common stock
in exchange for 49.5% of RAM Energy, Inc.'s, outstanding common stock. Our
shares were valued at $8.854 each, or $9.9 million in total. We agreed to adjust
the consideration for our acquisition of RAM shares by making a cash payment to
the selling RAM shareholders equal to the shortfall if they sold the Chesapeake
shares they received at a price less than $8.854 per share. In the third quarter
of 2001, the RAM shareholders sold all their shares of Chesapeake common stock
at prices below this level and we made make-whole cash payments of $3.3 million
to them to cover the shortfall. In December 2001, we sold all the RAM shares we
owned for minimal consideration.

On September 21, 2001, our board of directors authorized the repurchase of
up to $50 million of our common stock, either through direct purchases or put
options. We have not made any repurchases or written any put options to date
under this program. The consent to the stock repurchase program we obtained
under our bank credit facility expires June 30, 2002.

On November 13, 2001, we issued 3.0 million shares of 6.75% cumulative
convertible preferred stock, par value $.01 per share and liquidation preference
$50 per share, in a private offering. The net proceeds from the offering were
$145.1 million. Each preferred share is convertible at any time at the option of
the holder into 6.4935 shares of our common stock, subject to adjustment. At
December 31, 2001, 19,480,500 shares of our common stock were reserved for
issuance upon conversion. The conversion rate is based on an initial conversion
price of $7.70 per common share, plus cash in lieu of fractional shares. The
preferred stock is subject to mandatory conversion, at our option, (1) on or
after November 20, 2004 at the same rate if the market price of the common stock
equals or exceeds 130% of the conversion price at the time and (2) on or after
November 20, 2006 at the lower of the conversion price and the then current
market price of the common stock if there are less than 250,000 shares of
preferred stock outstanding at the time. Annual cumulative cash dividends of
$3.375 per share are payable quarterly on the fifteenth day of each February,
May, August and November.

During 2000, we entered into a number of unsolicited transactions whereby
we issued 43.4 million shares of our common stock, plus a cash payment of $8.3
million, in exchange for 3,972,363 shares of our preferred stock. This reduced
the liquidation amount of preferred stock outstanding by $198.6 million to $31.2
million and reduced the amount of preferred dividends in arrears by $22.9
million.

During 2000, Chesapeake Energy Marketing, Inc. purchased 99.8% of Gothic
Energy Corporation's $104 million 14.125% Series B senior secured discount notes
for total consideration of $80.8 million, comprised of $17.2 million in cash and
$63.6 million of our common stock (8,875,775 shares valued at $7.16 per share),
as adjusted for make-whole provisions. Chesapeake Energy Marketing, Inc.
received $6.1 million in cash and $7.2 million of our common stock (982,562
shares) from the sellers of Gothic notes pursuant to make-whole provisions
included in the purchase agreements. These provisions required payments to be
made by the sellers to us or additional payments to be made by us to the
sellers, depending upon changes in market value of our common stock during a
specified period pending registration of our common stock issued to the sellers
of Gothic notes.

In 2000, we purchased $31.6 million of the $235 million of 11.125% senior
secured notes issued by Gothic Production Corporation for total consideration of
$34.8 million consisting of $11.5 million in cash and $23.3 million of our
common stock (3,694,939 shares valued at $6.30 per share), as adjusted for
make-whole provisions similar to those described above. Through the make-whole
provisions, we received cash of $1.0 million.

In November 1999, the chief executive officer and the chief operating
officer of Chesapeake tendered to Chesapeake Energy Marketing, Inc. 2,320,107
shares of Chesapeake common stock in full satisfaction of two notes payable to
CEMI with a combined outstanding balance of $7.6 million. At the time,
Chesapeake's stock price was $3.29 per share. See note 6.

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Stock Option Plans

Under Chesapeake's 2001 Stock Option Plan, incentive and nonqualified stock
options to purchase our common stock may be granted to employees and consultants
of Chesapeake. Subject to any adjustment as provided by the plan, the aggregate
number of shares which may be issued and sold may not exceed 3,200,000 shares.
The maximum period for exercise of an option may not be more than ten years from
the date of grant and the exercise price may not be less than the fair market
value of the shares underlying the options on the date of grant; provided,
however, nonqualified stock options not exceeding 10% of the options issuable
under this plan may be granted at an exercise price which is not less than 85%
of the grant date fair market value. Options granted become exercisable at dates
determined by the Stock Option Committee of the board of directors. No options
can be granted under this plan after February 28, 2011.

Under Chesapeake's 2000 and 2001 Executive Officer Stock Option Plans,
nonqualified stock options to purchase our common stock may be granted to
executive officers of Chesapeake. Subject to any adjustment as provided by the
plan, the aggregate number of shares which may be issued and sold may not exceed
2,500,000 shares under the 2000 Plan and 4,000,000 shares under the 2001 Plan
and must represent issued shares which have been reacquired by Chesapeake. The
maximum period for exercise of an option may not be more than ten years from the
date of grant and the exercise price may not be less than the fair market value
of the shares underlying the options on the date of grant; provided, however,
nonqualified stock options not exceeding 10% of the options issuable under this
plan may be granted at an exercise price which is not less than 85% of the grant
date fair market value. Options granted become exercisable at dates determined
by the Stock Option Committee of the board of directors. No options can be
granted under the 2000 plan after April 25, 2010 or after April 14, 2011 under
the 2001 Plan.

Under Chesapeake's 1999 Stock Option Plan, 2000 Employee Stock Option Plan
and our 2001 Nonqualified Stock Option Plan, nonqualified stock options to
purchase our common stock may be granted to employees and consultants of
Chesapeake. Subject to any adjustment as provided by the respective plans, the
aggregate number of shares which may be issued and sold may not exceed 3,000,000
shares from each plan. The maximum period for exercise of an option may not be
more than ten years from the date of grant and the exercise price may not be
less than the fair market value of the shares underlying the options on the date
of grant; provided, however, nonqualified stock options not exceeding 10% of the
options issuable under this plan may be granted at an exercise price which is
not less than 85% of the grant date fair market value. Options granted become
exercisable at dates determined by the Stock Option Committee of the board of
directors. No options can be granted after March 4, 2009 under the 1999 Plan,
after April 25, 2010 under the 2000 Employee Plan and after April 14, 2011 under
the 2001 Nonqualified Plan.

Under Chesapeake's 1994 Stock Option Plan, and our 1996 Stock Option Plan,
incentive and nonqualified stock options to purchase our common stock may be
granted to employees and consultants of Chesapeake. Subject to any adjustment as
provided by the respective plans, the aggregate number of shares which may be
issued and sold may not exceed 4,886,910 shares under the 1994 Plan and
6,000,000 shares under the 1996 Plan. The maximum period for exercise of an
option may not be more than ten years from the date of grant and the exercise
price of nonqualified stock options may not be less than par value and, under
the 1996 Plan, 85% of the fair market value of the shares underlying the options
on the date of grant. Options granted become exercisable at dates determined by
the Stock Option Committee of the board of directors. No options can be granted
under the 1994 Plan after October 17, 2004 or under the 1996 Plan after October
14, 2006.

Under our 1992 Nonstatutory Stock Option Plan, non-qualified options to
purchase our common stock may be granted only to directors and consultants of
Chesapeake. Subject to any adjustment as provided by this plan, the aggregate
number of shares which may be issued and sold may not exceed 3,132,000 shares.
The maximum period for exercise of an option may not be more than ten years from
the date of grant, and the exercise price may not be less than the fair market
value of the shares underlying the options on the date of grant. Options granted
become exercisable at dates determined by the Stock Option Committee of the
board of directors. This plan also contains a formula award provision pursuant
to which each director who is not an executive officer receives every quarter a
ten-year immediately exercisable option to purchase 8,750 shares of common stock
at an option price equal to the fair market value of the shares on the date of
grant. The amount of the award was changed from 20,000 shares to 15,000 shares
per year in 1998, to 25,000 shares per year in 1999, to 30,000 shares per year
in 2000 and to 35,000 shares per year in 2001. No options can be granted under
this plan after December 10, 2002.

Chesapeake's 1992 Incentive Stock Option Plan terminated on December 16,
1994. Until then, we granted incentive stock options to purchase our common
stock under the ISO Plan to employees. Subject to any adjustment as provided by
the ISO Plan, the aggregate number of shares which may be issued and sold may
not exceed 3,762,000 shares. The maximum period for exercise of an option may
not be more than ten years (or five years for

64

an optionee who owns more than 10% of the common stock) from the date of grant,
and the exercise price may not be less than the fair market value of the shares
underlying the options on the date of grant (or 110% of such value for an
optionee who owns more than 10% of the common stock). Options granted become
exercisable at dates determined by the Stock Option Committee of the board of
directors.

Chesapeake has elected to follow APB No. 25, Accounting for Stock Issued to
Employees and related interpretations in accounting for its employee stock
options. Under APB No. 25, compensation expense is recognized for the difference
between the option price and market value on the measurement date. In March
2000, the Financial Accounting Standards Board issued FASB Interpretation No. 44
which provided clarification regarding the application of APB No. 25. FIN 44
specifically addressed the accounting consequence of various modifications to
the terms of a previously granted fixed stock option. Compensation expense of
$0.8 million was recognized in 2001 as a result of modifications that were made
during the years ended December 31, 2001 and 2000. No compensation expense has
been recognized for newly issued stock options in 2001, 2000 or 1999 because the
exercise price of the stock options granted under the plans equaled the market
price of the underlying stock on the date of grant.

Pro forma information regarding net income and earnings per share is
required by SFAS No. 123 and has been determined as if we had accounted for our
employee stock options under the fair value method of the statement. The fair
value for these options was estimated at the date of grant using a Black-Scholes
option pricing model with the following weighted-average assumptions for 2001,
2000 and 1999, respectively: interest rates (zero-coupon U.S. government issues
with a remaining life equal to the expected term of the options) of 4.67%, 6.32%
and 5.88%, dividend yields of 0.0%, 0.0% and 0.0%, volatility factors of the
expected market price of our common stock of 0.58, 0.73, and 0.82, and
weighted-average expected life of the options of five years.

The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because our employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.

Pro forma information applying the fair value method follows:

For purposes of the pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period, which is four
years. Because our stock options vest over four years and additional awards are
typically made each year, the above pro forma disclosures are not likely to be
representative of the effects on pro forma net income for future years. A
summary of our stock option activity and related information follows:

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The following table summarizes information about stock options outstanding
at December 31, 2001:

The exercise of certain stock options results in state and federal income
tax benefits to us related to the difference between the market price of the
common stock at the date of disposition and the option price. During 2001 and
2000, we recognized a tax benefit of $5.4 million and $3.8 million, which was
recorded as adjustments to additional paid-in capital and deferred income taxes
with respect to such benefits. There was no similar tax benefit in 1999.

Shareholder Rights Plan

Chesapeake maintains a shareholder rights plan designed to deter coercive
or unfair takeover tactics, to prevent a person or group from gaining control of
Chesapeake without offering fair value to all shareholders and to deter other
abusive takeover tactics which are not in the best interest of shareholders.

Under the terms of the plan, each share of common stock is accompanied by
one right, which given certain acquisition and business combination criteria,
entitles the shareholder to purchase from Chesapeake one one-thousandth of a
newly issued share of Series A preferred stock at a price of $25.00, subject to
adjustment by Chesapeake.

The rights become exercisable 10 days after Chesapeake learns that an
acquiring person (as defined in the plan) has acquired 15% or more of the
outstanding common stock of Chesapeake or 10 business days after the
commencement of a tender offer which would result in a person owning 15% or more
of such shares. Chesapeake may redeem the rights for $0.01 per right within ten
days following the time Chesapeake learns that a person has become an acquiring
person. The rights will expire on July 27, 2008, unless redeemed earlier by
Chesapeake.

10. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Our results of operations and operating cash flows are impacted by changes
in market prices for oil and gas. To mitigate a portion of this exposure to
adverse market changes, we have entered into derivative instruments. All of our
derivative instruments have been entered into as hedges of oil and gas price
risk and not for speculative purposes.

We utilize derivative instruments to reduce exposure to unfavorable changes
in oil and gas prices which are subject to significant and often volatile
fluctuations. As of December 31, 2001, our derivative instruments were comprised
of swaps, collars, cap-swaps, and locked swaps. These instruments allow us to
predict with greater certainty the effective oil and gas prices to be received
for our hedged production.

o For swap instruments, we receive a fixed price for the hedged
commodity and pay a floating market price, as defined in each
instrument, to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due to or
from the counterparty.

o Collars contain a fixed floor price (put) and ceiling price (call). If
the market price exceeds the call strike price or falls below the put
strike price, then we receive the fixed price and pay the market
price. If the market price is between the call and the put strike
price, then no payments are due from either party.

o For cap-swaps, we receive a fixed price for the hedged commodity and
pay a floating market price. The fixed price received by Chesapeake
includes a premium in exchange for a "cap" on the floating market
price, which limits the counterparty's exposure.

o Locked swaps consist of swap positions which have been effectively
closed by entering into a counter-swap instrument where we receive the
floating price for the hedged commodity and pay a fixed price to the

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counterparty. At the time we enter into the counter-swap, the original
swap is designated as a non-qualifying cash flow hedge under SFAS 133.
The net values of both the swap and counter-swap are frozen and shown
as derivatives receivable or payable in the consolidated balance
sheet.

Pursuant to SFAS 133, our cap-swaps do not qualify for designation as cash
flow hedges. Therefore, changes in the fair value of these instruments that
occur prior to their maturity are reported in the statement of operations as
risk management income (loss). Amounts recorded in risk management income (loss)
do not represent cash gains or losses. Rather, these amounts are temporary
valuation swings in contracts or portions of contracts that are not entitled to
receive hedge accounting treatment. All amounts initially recorded in this
caption are ultimately reversed within this same caption and recorded in oil and
gas sales over the respective contract terms.

The estimated fair values of our derivative instruments as of December 31,
2001 are provided below. The associated carrying values of these instruments are
equal to the estimated fair values.

Although derivatives often fail to achieve 100% effectiveness for
accounting purposes, our derivative instruments continue to be highly effective
in achieving the risk management objectives for which they were intended.

We expect to transfer approximately $33.7 million of the balance in
accumulated other comprehensive income, based upon the market prices at December
31, 2001, to earnings during the next 12 months when the forecasted transactions
actually occur. All forecasted transactions hedged as of December 31, 2001 are
expected to occur by December 2003.

Fair Value of Financial Instruments

The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of Statement of
Financial Accounting Standards No. 107, Disclosures About Fair Value of
Financial Instruments. We have determined the estimated fair value amounts by
using available market information and valuation methodologies. Considerable
judgment is required in interpreting market data to develop the estimates of
fair value. The use of different market assumptions or valuation methodologies
may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. We estimate the fair value of our long-term (including current
maturities), fixed-rate debt using primarily quoted market prices. Our carrying
amount for such debt at December 31, 2001 and 2000 was $1,330.1 million and
$920.7 million, respectively, compared to approximate fair values of $1,343.0
million and $894.7 million, respectively. The carrying value of other long-term
debt approximates its fair value as interest rates are primarily variable, based
on prevailing market rates. The carrying amount for our 6.75% convertible
preferred stock at December 31, 2001 was $150.0 million, which approximated its
fair value as of that date.

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Concentration of Credit Risk

A significant portion of our liquidity is concentrated in cash and cash
equivalents, including restricted cash, and derivative instruments that enable
us to hedge a portion of our exposure to price volatility from producing oil and
natural gas. These arrangements expose us to credit risk from our
counterparties. Our mark-to-market position and closed but uncollected
receivable with our largest counterparty, Morgan Stanley Capital Group Inc.,
totaled $137.8 million at December 31, 2001. Other financial instruments which
potentially subject us to concentrations of credit risk consist principally of
investments in debt instruments and accounts receivables. Our accounts
receivable are primarily from purchasers of oil and natural gas products and
exploration and production companies which own interests in properties we
operate. The industry concentration has the potential to impact our overall
exposure to credit risk, either positively or negatively, in that our customers
may be similarly affected by changes in economic, industry or other conditions.
We generally require letters of credit for receivables from customers which are
judged to have sub-standard credit, unless the credit risk can otherwise be
mitigated. Cash and cash equivalents are deposited with major banks or
institutions.

11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

Net Capitalized Costs

Evaluated and unevaluated capitalized costs related to Chesapeake's oil and
gas producing activities are summarized as follows:

Unproved properties not subject to amortization at December 31, 2001 and
2000 consisted mainly of lease acquisition costs. We capitalized approximately
$4.7 million, $2.4 million and $3.5 million of interest during 2001, 2000 and
1999, respectively, on significant investments in unproved properties that were
not yet included in the amortization base of the full-cost pool. We will
continue to evaluate our unevaluated properties; however, the timing of the
ultimate evaluation and disposition of the properties has not been determined.

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Costs Incurred in Oil and Gas Acquisition, Exploration and Development

Costs incurred in oil and gas property acquisition, exploration and
development activities which have been capitalized are summarized as follows:

Results of Operations from Oil and Gas Producing Activities (unaudited)

Chesapeake's results of operations from oil and gas producing activities are
presented below for 1999, 2000 and 2001. The following table includes revenues
and expenses associated directly with our oil and gas producing activities. It
does not include any interest costs and general and administrative costs and,
therefore, is not necessarily indicative of the contribution to consolidated net
operating results of our oil and gas operations.

- ---------
(a) The imputed income tax provision is hypothetical (at the statutory rate)
and determined without regard to our deduction for general and
administrative expenses, interest costs and other income tax credits and
deductions, nor whether the hypothetical tax provision will be payable.

Oil and Gas Reserve Quantities (unaudited)

The reserve information presented below is based upon reports prepared by
independent petroleum engineers and Chesapeake's petroleum engineers.

o As of December 31, 2001, Ryder Scott Company L.P., Lee Keeling and
Associates, Williamson Petroleum Consultants, Inc. and our internal
reservoir engineers evaluated 26%, 24%, 22% and 28%, respectively, of
the combined discounted future net revenues from our estimated proved
reserves.

o As of December 31, 2000, Williamson, Ryder Scott, Lee Keeling and
Associates and our internal reservoir engineers evaluated 31%, 25%,
16% and 28%, respectively, of the combined discounted future net
revenues from our estimated proved reserves.

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o As of December 31, 1999, Williamson, Ryder Scott, and our internal
reservoir engineers evaluated 50%, 16%, and 34%, respectively, of the
combined discounted future net revenues from our estimated proved
reserves.

The information is presented in accordance with regulations prescribed by
the Securities and Exchange Commission. Chesapeake emphasizes that reserve
estimates are inherently imprecise. Our reserve estimates were generally based
upon extrapolation of historical production trends, analogy to similar
properties and volumetric calculations. Accordingly, these estimates are
expected to change, and such changes could be material and occur in the near
term as future information becomes available.

Proved oil and gas reserves represent 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. Proved
developed oil and gas reserves are those expected to be recovered through
existing wells with existing equipment and operating methods.

Presented below is a summary of changes in estimated reserves of Chesapeake
for 1999, 2000 and 2001:

During 2001, Chesapeake acquired 648 bcfe of proved reserves for
consideration of $706 million in approximately 160 separate transactions. In
October 2001, we sold our Canadian subsidiary, which had oil and gas operations
primarily in northeast British Columbia, for approximately $143.0 million. Also
during 2001, we recorded downward revisions to our U.S. oil and gas reserves of
183 bcfe. Approximately 156 bcfe of the downward revisions to our reserves were
related to significantly lower gas and oil prices at December 31, 2001,

70

which had the effect of reducing the economic life of our properties. The
weighted average oil and gas wellhead prices used in computing our reserves were
$18.82 per bbl and $2.51 per mcf at December 31, 2001, compared to $26.41 per
bbl and $10.12 per mcf at December 31, 2000.

During 2000, Chesapeake acquired 108 bcfe of proved reserves for
consideration of $75 million. Also during 2000, we recorded downward revisions
to our U.S. oil reserves of 3.2 million barrels and upward revisions to our U.S.
natural gas reserves of 25.7 bcf. The downward revisions to our U.S. oil
reserves were related to lower estimates primarily in the Knox, Permian and
Williston areas. The upward revisions to our U.S. gas reserves were due
primarily to additional reserves added as a result of the significant increase
in natural gas prices as of December 31, 2000, which had the effect of extending
the economic life of our properties. These upward revisions were partially
offset by the elimination of proved undeveloped locations primarily in the Knox,
Independence and Sahara fields, as well as lower estimates in various areas
located primarily in the Mid-Continent area. During 2000, we also had negative
revisions to our Canadian gas reserves of 28 bcf. This decrease was primarily
due to the increase in crown royalties resulting from higher natural gas prices
at December 31, 2000, as well as lower estimates on various properties in the
Helmet field.

During 1999, Chesapeake acquired approximately 101 bcfe of proved reserves
through purchases of oil and gas properties for consideration of $52 million. We
also sold 59 bcfe of proved reserves for consideration of approximately $46
million. During 1999, we recorded upward revisions of 80 bcfe to the December
31, 1998 estimates of our U.S. reserves, and downward revisions of 99 bcfe to
the December 31, 1998 estimates of our Canadian reserves, for a total revision
of 19 bcfe, or approximately 1.7%. The upward revisions to our U.S. reserves
were caused by higher oil and gas prices at December 31, 1999, and actual
performance in excess of predicted performance. Higher prices extend the
economic lives of the underlying oil and gas properties and thereby increase the
estimated future reserves. The downward revisions of our Canadian reserves were
caused by a reduction of our proved undeveloped locations and an increase in
projected transportation and operating costs in Canada, which decreased the
economic lives of the underlying properties.

Standardized Measure of Discounted Future Net Cash Flows (unaudited)

Statement of Financial Accounting Standards No. 69 prescribes guidelines
for computing a standardized measure of future net cash flows and changes
therein relating to estimated proved reserves. Chesapeake has followed these
guidelines which are briefly discussed below.

Future cash inflows and future production and development costs are
determined by applying year-end prices and costs to the estimated quantities of
oil and gas to be produced. Estimates are made of quantities of proved reserves
and the future periods during which they are expected to be produced based on
year-end economic conditions. Estimated future income taxes are computed using
current statutory income tax rates including consideration for the current tax
basis of the properties and related carryforwards, giving effect to permanent
differences and tax credits. The resulting future net cash flows are reduced to
present value amounts by applying a 10% annual discount factor.

The assumptions used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and, as such, do not
necessarily reflect our expectations of actual revenue to be derived from those
reserves nor their present worth. The limitations inherent in the reserve
quantity estimation process, as discussed previously, are equally applicable to
the standardized measure computations since these estimates are the basis for
the valuation process.

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The following summary sets forth our future net cash flows relating to
proved oil and gas reserves based on the standardized measure prescribed in SFAS
69:

- --------

(a) Calculated using weighted average prices of $24.72 per barrel of oil and
$2.25 per mcf of gas.

(b) Calculated using weighted average prices of $26.41 per barrel of oil and
$10.12 per mcf of gas.

(c) Calculated using weighted average prices of $18.82 per barrel of oil and
$2.51 per mcf of gas.

In October 2001, we sold our Canadian subsidiary, which had oil and gas
operations primarily in northeast British Columbia, for net proceeds of
approximately $143.0 million.

72

The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:

12. ACQUISITIONS, INVESTMENTS AND DIVESTITURES

We completed the acquisition of Gothic Energy Corporation on January 16,
2001 by merging a wholly-owned subsidiary into Gothic. We issued a total of 4.0
million common shares in the merger. Gothic shareholders (other than Chesapeake)
received 0.1908 of a share of Chesapeake common stock for each share of Gothic
common stock. In addition, outstanding warrants and options to purchase Gothic
common stock were converted to the right to purchase Chesapeake common stock
based on the merger exchange ratio. As of December 31, 2001, 1.1 million shares
of Chesapeake common stock may be purchased upon the exercise of such warrants
and options at an average price of $12.48 per share. In 2000, Chesapeake
purchased substantially all of Gothic's 14.125% senior secured discount notes
for total consideration of $80.8 million in cash and Chesapeake common stock. We
also purchased $31.6 million principal amount of 11.125% senior secured notes
due 2005 issued by Gothic's operating subsidiary for total consideration of
$34.8 million in cash and Chesapeake common stock. Subsequent to the
acquisition, we redeemed all remaining Gothic 14.125% discount notes for total
consideration of $243,000. In February 2001, we purchased $1.0 million principal
amount of Gothic senior secured notes tendered pursuant to a change-of-control
offer at a purchase price of 101%. During April and May 2001, we purchased or
redeemed the remaining $202.3 million of Gothic 11.125% senior secured notes for
total consideration of $225.9 million. On May 14, 2001, Gothic Energy
Corporation and Gothic Production Corporation became guarantor subsidiaries of
Chesapeake's senior notes.

During 2000, we obtained a standby commitment for a $275 million credit
facility, consisting of a $175 million term loan and a $100 million revolving
credit facility which, if needed, would have replaced our then existing
revolving credit facility. The term loan was available to provide funds to
repurchase any of Gothic Production Corporation's 11.125% senior secured notes
tendered following the closing of the Gothic acquisition in January 2001
pursuant to a change-of-control offer to purchase. In February 2001, we
purchased $1.0 million of notes tendered for 101% of such amount. We did not use
the standby credit facility and the commitment terminated on February 23, 2001.
Chesapeake incurred $3.4 million of costs for the standby facility, which were
recognized in the first quarter of 2001.

The acquisition of Gothic was accounted for using the purchase method as of
January 1, 2001 because we had effective control as of that date, and the
results of operations of Gothic have been included since that date.

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The following unaudited pro forma information has been prepared assuming
Gothic had been acquired as of the beginning of the period presented. The pro
forma information is presented for information purposes only and is not
necessarily indicative of what would have occurred if the acquisition had been
made as of that date. In addition, the pro forma information is not intended to
be a projection of future results and does not reflect any efficiencies that may
result from the integration of Gothic.

PRO FORMA INFORMATION
(UNAUDITED)
($ IN THOUSANDS, EXCEPT PER SHARE DATA)

During 2001, we also completed a number of individually insignificant
acquisitions, which totaled $316.7 million. During 2000 and 1999, we acquired
working interests in proved oil and gas properties for total consideration of
$78.9 million and $49.9 million, respectively. All of the acquisitions were
accounted for using the purchase method and, accordingly, results of operations
of these acquired entities and oil and gas properties have been included in
Chesapeake's results of operations from the respective effective dates of
acquisition.

From time to time, Chesapeake also invests in debt and equity securities of
both private and public energy companies. During 2001, we purchased $17.4
million principal amount of RAM Energy, Inc. notes for $15.2 million, including
accrued interest of $0.6 million. We later used $11.1 million principal amount
of the RAM notes as a portion of the consideration for our purchase of oil and
gas assets from RAM. Subsequent to year-end, we sold the remaining RAM notes for
an amount that approximated their carrying value. In March 2001, we also
purchased 49.5% of RAM's outstanding common stock for approximately $9.9
million. We sold the RAM common stock in December 2001 for minimal
consideration, realizing a pre-tax loss of $8.6 million. In July 2001, we
invested $22.5 million in 12% senior secured notes of Seven Seas Petroleum Inc.
We intend to hold these notes to maturity, and thus carry them at amortized cost
rather than market value. The Seven Seas notes we purchased were accompanied by
seven-year warrants to purchase approximately 20.0% of Seven Seas' outstanding
common stock on a fully diluted basis at an exercise price of $1.78 per share.
We are carrying the warrants at allocated cost, which approximates fair value at
year-end.

In October 2001, we sold Chesapeake Canada Corporation, a wholly-owned
subsidiary, for net proceeds of approximately $143.0 million.

13. QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized unaudited quarterly financial data for 2000 and 2001 are as
follows ($ in thousands except per share data):

- --------
(a) Total revenue less total operating costs.

(b) In the fourth quarter of 2000, we eliminated our valuation allowance
resulting in the recognition of a $265 million income tax benefit. Based
upon recent results of operations and anticipated improvement in
Chesapeake's outlook for sustained profitability, we believed that it was
more likely than not that we would generate sufficient future taxable
income to realize the tax benefits associated with our NOL carryforwards
prior to their expiration.

(c) Net of an extraordinary loss on extinguishment of debt of $46.0 million,
net of income taxes.

(d) Includes pretax gain on sale of Canadian subsidiary of $27.0 million and
pretax impairments of investments in securities of $10.1 million.

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14. RECENT ACCOUNTING PRONOUNCEMENTS

In June 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards Nos. 141 and 142. SFAS No. 141, Business
Combinations, requires that the purchase method of accounting be used for all
business combinations initiated after June 30, 2001. SFAS No. 142, Goodwill and
Other Intangible Assets, changes the accounting for goodwill from an
amortization method to an impairment-only approach and will be effective January
2002. We believe that adoption of this new standard will not have an effect on
our results of operations or our financial position. In June 2001, the FASB
issued SFAS No. 143, Accounting for Asset Retirement Obligations. We have not
yet determined the effect of the adoption of SFAS No. 143 on our financial
position or results of operations.

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. SFAS 144 is effective for fiscal years
beginning after December 15, 2002. This statement supersedes SFAS No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of, and amends Accounting Principles Board Opinion No. 30 for the
accounting and reporting of discontinued operations, as it relates to long-lived
assets. We believe the future impact of the adoption of SFAS 144 on our
financial position or results of operations will not be material.

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SCHEDULE II

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
($ IN THOUSANDS)

- --------

(a) At December 31, 1998, $5.9 million of the valuation allowance was related
to our Canadian deferred tax assets. During 1999, this valuation allowance
was eliminated as part of a purchase price reallocation related to a 1998
acquisition.

(b) In the fourth quarter of 2000, we eliminated the valuation allowance for
deferred tax assets. The reversal was based upon recent results of
operations and anticipated improvements in Chesapeake's outlook for
sustained profitability. During 2000, we revised our estimate of the 1999
U.S. net deferred tax asset and related valuation allowance from $442
million to $330 million as a result of further evaluation of the income tax
basis of several acquisitions.

(c) At December 31, 2001, we determined that it was more likely than not that
$2.4 million of the deferred tax assets related to Louisiana net operating
losses will not be realized and we have recorded a valuation allowance
equal to such amount.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

Not applicable.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information called for by this Item 10 is incorporated herein by
reference to the definitive Proxy Statement to be filed by Chesapeake pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 2002.

ITEM 11. EXECUTIVE COMPENSATION

The information called for by this Item 11 is incorporated herein by
reference to the definitive Proxy Statement to be filed by Chesapeake pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 2002.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

The information called for by this Item 12 is incorporated herein by
reference to the definitive Proxy Statement to be filed by Chesapeake pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 2002.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information called for by this Item 13 is incorporated herein by
reference to the definitive Proxy Statement to be filed by Chesapeake pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 2002.

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PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) The following documents are filed as part of this report:

1. Financial Statements. Chesapeake's consolidated financial statements are
included in Item 8 of this report. Reference is made to the accompanying Index
to Financial Statements.

2. Financial Statement Schedules. Schedule II is included in Item 8 of this
report with our consolidated financial statements. No other financial statement
schedules are applicable or required.

3. Exhibits. The following exhibits are filed herewith pursuant to the
requirements of Item 601 of Regulation S-K:

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10.10 -- Partnership Agreement of Chesapeake Exploration Limited
Partnership dated December 27, 1994 between Chesapeake Energy
Corporation and Chesapeake Operating, Inc. Incorporated herein by
reference to Exhibit 10.10 to Registrant's registration statement
on Form S-4 (No. 33-93718).

10.11 -- Amended and Restated Limited Partnership Agreement of Chesapeake
Louisiana, L.P. dated June 30, 1997 between Chesapeake Operating,
Inc. and Chesapeake Energy Louisiana Corporation.

12* -- Ratios of Earnings to Fixed Charges and Preferred Dividends.

21* -- Subsidiaries of Registrant

23.1* -- Consent of PricewaterhouseCoopers LLP

23.2* -- Consent of Williamson Petroleum Consultants, Inc.

23.3* -- Consent of Ryder Scott Company L.P.

23.4* -- Consent of Lee Keeling and Associates, Inc.

- ---------

* Filed herewith.

+ Management contract or compensatory plan or arrangement.

(b) Reports on Form 8-K

During the quarter ended December 31, 2001, Chesapeake filed the following
current reports on Form 8-K:

On October 3, 2001, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing the sale of our Canadian
subsidiary, confirmation of hedge positions and $50 million stock buyback
program.

On October 24, 2001, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing third quarter 2001 earnings
release and conference call dates.

On October 25, 2001, we furnished a current report on Form 8-K reporting
under Item 9 the posting on our web site of key operating assumptions and
projections for the fourth quarter of 2001 and full year 2002.

On October 25, 2001 (and as amended on October 26, 2001), we filed a
current report on Form 8-K reporting under Item 5 that we had issued a press
release reporting earnings of $0.38 per fully diluted share of the 2001 third
quarter and furnishing under Item 9 certain forecasts that we made in such press
release.

On October 29, 2001, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing the pricing on $250 million
of 8.375% Senior Notes due 2008.

On November 1, 2001, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing the commencement of a
private offering of 2.5 million shares of convertible preferred stock. We also
reported under Item 5 the status of negotiations for certain acquisitions.

On November 2, 2001, we furnished a current report on Form 8-K reporting
under Item 9 that we had posted a slide show presentation on our web site which
was being presented to institutional investors in various meetings in the first
week of November 2001.

On November 7, 2001, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing the pricing and the setting
of terms on our $150 million of 6.75% Cumulative Convertible Preferred Stock.

On December 5, 2001, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing the purchase of proved gas
reserves and daily gas production, hedging gains of $250 million and no hedging
exposure with Enron. We furnished under Item 9, updates to our fourth quarter
2001 and full year 2002 forecasts and our posting of such forecasts on our web
site.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.

CHESAPEAKE ENERGY CORPORATION

By /s/ Aubrey K. McClendon
----------------------------
Aubrey K. McClendon
Chairman of the Board and
Chief Executive Officer
Date: March 28, 2002

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

83

INDEX TO EXHIBITS

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* Filed herewith.

+ Management contract or compensatory plan or arrangement.

88