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