CHESAPEAKE ENERGY CORP - 10-Q Quarterly Report

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

FORM 10-Q

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

For the quarterly period ended June 30, 2002

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

For the transition period from to

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

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 [ ]

At July 31, 2002, there were 166,122,358 shares of our $.01 par value common
stock outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2002

2

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

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

3

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)

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

4

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

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

5

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)

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

6

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2002
(UNAUDITED)

1. BASIS OF PRESENTATION AND ACCOUNTING POLICIES

Principles of Consolidation

The accompanying unaudited consolidated financial statements of Chesapeake
Energy Corporation and Subsidiaries have been prepared in accordance with the
instructions to Form 10-Q as prescribed by the Securities and Exchange
Commission. All material adjustments (consisting solely of normal recurring
adjustments) which, in the opinion of management, are necessary for a fair
presentation of the results for the interim periods have been reflected. The
results for the three and six months ended June 30, 2002 are not necessarily
indicative of the results to be expected for the full year. This Form 10-Q
relates to the three and six months ended June 30, 2001 (the "Prior Quarter" and
"Prior Period", respectively) and the three and six months ended June 30, 2002
(the "Current Quarter" and "Current Period", respectively).

2. HEDGING ACTIVITIES AND FINANCIAL INSTRUMENTS

Oil and Gas 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 the exposure to
adverse market changes, we have entered into various derivative instruments. As
of June 30, 2002, our derivative instruments were comprised of swaps, collars,
cap-swaps, straddles, strangles and basis protection swaps. These instruments
allow us to predict with greater certainty the effective oil and gas prices to
be received for our hedged production. 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.

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" limiting the counterparty's exposure.

o For straddles, Chesapeake receives a premium from the counterparty in
exchange for the sale of a call and a put option at an established fixed
price. To the extent that the floating market price differs from the
established fixed price, Chesapeake pays the counterparty.

o For strangles, Chesapeake receives a premium from the counterparty in
exchange for the sale of a call and a put option. If the market price
exceeds the fixed price of the call option or falls below the fixed
price of the put option, then Chesapeake pays the counterparty. If the
market price settles between the fixed price of the call and put option,
no payment is due from Chesapeake.

o Basis protection swaps are arrangements that guarantee a price
differential of oil and gas from a specified delivery point. Chesapeake
receives a payment from the counterparty if the price differential is
greater than the stated terms of the contract and pays the counterparty
if the price differential is less than the stated terms of the contract.

7

From time to time, we close certain swap transactions designed to hedge a
portion of our oil and natural gas production by entering into a counter-swap
instrument. Under the counter-swap we receive a floating price for the hedged
commodity and pay a fixed price to the counterparty. To the extent the
counter-swap, which does not qualify for hedge accounting under SFAS 133, is
designed to lock the value of an existing SFAS 133 cash flow hedge, the net
value of the swap and the counter-swap is frozen and shown as a derivative
receivable or payable in the consolidated balance sheets. At the same time, the
original swap is designated as a non-qualifying cash flow hedge under SFAS 133.

Pursuant to SFAS 133, our cap-swaps, straddles, strangles, counter-swaps and
basis protection 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 statements 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 SFAS 133 cash flow hedge accounting treatment. All amounts
initially recorded in this caption related to commodity derivatives 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 oil and gas derivative instruments as of
June 30, 2002 are provided below. The associated carrying values of these
instruments are equal to the estimated fair values.

(a) After adjusting for the $34.5 million premium paid to Chesapeake by the
counterparty at the inception of the straddle and strangle contracts (which
is recorded in cash provided by operating activities on the accompanying
consolidated statements of cash flows), the net value of the combined
hedging portfolio at June 30, 2002 was $31.2 million.

Based upon the market prices at June 30, 2002, we would expect to transfer
approximately $11.3 million of the balance in accumulated other comprehensive
income to earnings during the next 12 months when the transactions actually
occur. All transactions hedged as of June 30, 2002 are expected to mature by
December 31, 2004, with the exception of the basis protection swaps which extend
to 2009.

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

Fair value of contracts outstanding at January 1, 2002 ............... $ 157,309
Change in fair value of contracts during period ...................... (55,623)
Contracts realized or otherwise settled during the period ............ (61,989)
Fair value of new contracts when entered into during the period ...... (42,991)
-------------
Fair value of contracts outstanding at June 30, 2002 ................. $ (3,294)
=============

8

Risk management income (loss) related to our oil and gas derivatives is
comprised of the following ($ in thousands):

Interest Rate Risk

We also utilize hedging strategies to manage interest rate exposure. In
March 2002, we entered into an interest rate swap to convert a portion of our
fixed rate debt to floating rate debt. The terms of this swap agreement are as
follows:

If the floating rate is less than the fixed rate, the counterparty will pay
us accordingly. If the floating rate exceeds the fixed rate, we will pay the
counterparty. Payments under the interest rate swap coincide with the
semi-annual interest payments on our 7.875% senior notes which are due September
15 and March 15 of each year beginning September 15, 2002.

A portion of the interest rate swap was originally entered into to convert
$129.0 million of the 7.875% senior notes from fixed rate debt to variable rate
debt. Under SFAS 133, a hedge of this interest rate risk in a recognized fixed
rate liability can be designated as a fair value hedge under which the
mark-to-market value of the swap is recorded on the consolidated balance sheets
as an asset or liability with a corresponding increase or decrease in the
carrying value of the debt. See Note 5 of the notes to consolidated financial
statements included in this report for the adjustments made to the carrying
value of the debt at June 30, 2002. During the Current Quarter, $21.2 million of
the 7.875% senior notes were purchased and subsequently retired resulting in a
$0.4 million gain on the repurchase of the debt related to the interest rate
swap. As a result of these repurchases, $107.8 million of the interest rate swap
was designated as a fair value hedge under SFAS 133 at June 30, 2002.

Results from interest rate hedging transactions are reflected as adjustments
to interest expense in the corresponding months covered by the swap agreement.

The remaining $92.2 million of the interest rate swap has not been
designated as a fair value hedge. The mark-to-market value of this portion of
the instrument is recorded as a derivative asset or liability on the
consolidated balance sheets with the offsetting amount reflected in risk
management income (loss) on the consolidated statements of operations. The
amount recorded in risk management income (loss) will be reversed and reflected
in interest expense over the term of the swap.

The estimated fair value of the interest rate swap at June 30, 2002 was an
asset of approximately $5.0 million comprised of $1.6 million reflected as risk
management income, $1.4 million reflected as an increase in the carrying value
of the long-term debt, $1.6 million reflected as a reduction in interest expense
and $0.4 reflected as other income related to the gain on the repurchase of
debt.

9

In June 2002, we entered into an additional interest rate swap. The terms of
this swap agreement are as follows:

If the floating rate is less than the fixed rate, the counterparty will pay
us accordingly. If the floating rate exceeds the fixed rate, we will pay the
counterparty. Payments under this interest rate swap are made on July 2 and
January 2 of each year beginning January 2, 2003. The estimated fair value of
the interest rate swap at June 30, 2002 was negligible.

In July 2002, we closed both interest rate swaps for a combined gain of $8.6
million. Gains totaling $6.6 million, in addition to the $2.0 million gain
already realized in the Current Quarter, will be recognized as reductions to
interest expense over the remaining terms of the swaps.

In April 2002, we entered into a swaption agreement in order to monetize the
embedded call option in the remaining $142.7 million of our 8.5% senior notes.
We received $7.8 million from the counterparty at the time we entered into this
agreement. The terms of the swaption are as follows:

Under the terms of the swaption agreement, the counterparty will have the
option to initiate an interest rate swap on March 11, 2004 pursuant to the terms
shown above. If the counterparty chooses to initiate the interest rate swap, the
payments under the swap will coincide with the semi-annual interest payments on
our 8.5% senior notes which are paid on September 15 and March 15 of each year.
On each payment date, if the fixed rate exceeds the floating rate, we will pay
the counterparty, and if the floating rate exceeds the fixed rate, the
counterparty will pay us accordingly. If the counterparty does not choose to
initiate the interest rate swap, the swaption agreement will expire and no
future obligations will exist for either party.

According to SFAS 133, a fair value hedge relationship exists between the
embedded call option in the 8.5% senior notes and our swaption agreement.
Accordingly, the mark-to-market value of the swaption is recorded on the
consolidated balance sheets as an asset or liability with a corresponding
increase or decrease to the debt's carrying value. Any change in the fair value
of the swaption resulting from ineffectiveness is recorded currently in the
consolidated statements of operations as risk management income (loss).

We have recorded a decrease in the carrying value of the debt of $7.8
million related to the swaption as of June 30, 2002. Of this amount, $8.9
million represents the mark-to-market valuation of the swaption offset by $1.1
million of estimated ineffectiveness of the swaption as determined under SFAS
133. See Note 5 of the notes to consolidated financial statements included in
this report for the adjustments made to the carrying value of the debt at June
30, 2002. Results of the swaption will be reflected as adjustments to interest
expense in the corresponding months covered by the swaption agreement.

Risk management income related to our fair value hedges is comprised of the
following ($ in thousands):

10

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. Excluding the
impact of our fair value hedges, our carrying amount for such debt at December
31, 2001 and June 30, 2002 was $1,330.1 million and $1,287.9 million,
respectively, compared to approximate fair values of $1,343.0 and $1,297.3
million, respectively. The carrying value of other long-term debt, which
consists of amounts outstanding under our revolving bank credit facility,
approximates its fair value as interest rates on the facility are based on
prevailing market rates. The carrying amount for our 6.75% convertible preferred
stock at June 30, 2002 was $149.9 million, compared to the approximate fair
value of $173.9 million.

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 and interest rate volatility. These arrangements expose us to credit
risk from our counterparties. 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
concentration of these assets in the oil and gas industry 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.

3. 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 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 the non-settling
plaintiffs in two of the cases covered by the settlement. The Court heard oral
arguments in March 2002 and has not yet issued a decision.

There are eight other related West Panhandle cessation cases which are
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

11

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.

Royalty. Owner Litigation. Recently royalty owners have commenced
litigation against a number of companies in the oil and gas production business
claiming that amounts paid for production attributable to the royalty owners'
interest violated the terms of the applicable leases and state law, that
deductions from the proceeds of oil and gas production were unauthorized under
the applicable leases and that amounts received by upstream sellers should be
used to compute the amounts paid to the royalty owners. In the course of our oil
and gas marketing activities, a portion of the foregoing litigation has been
commenced as class action suits including four class action suits filed against
Chesapeake and others which we believe do not represent valid claims or, if
valid, are not material. As new cases are decided and the law in this area
continues to develop, our liability relating to the marketing of oil and gas may
increase or decrease. We will continue to monitor the court decisions to ensure
that our operations and practices minimize any exposure and to recognize any
charges that may be appropriate.

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.

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.

4. NET INCOME 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 Prior Quarter, the Current Quarter, the Prior Period and the Current
Period, 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 price of the
common stock.

o For the Prior Quarter, the Current Quarter, the Prior Period and the Current
Period, outstanding options to purchase 0.3 million, 0.3 million, 0.2
million and 0.4 million shares of common stock at a weighted average
exercise price of $15.98, $15.30, $18.78 and $14.44, respectively, were
antidilutive because the exercise prices of the options were greater than
the average market price of the common stock.

o As a result of the Current Period's net loss to common shareholders, the
diluted shares do not include the effect of outstanding stock options to
purchase 5.9 million shares of common stock at a weighted average exercise
price of $3.90, the assumed conversion of the outstanding 6.75% preferred
stock (convertible into 19.5 million common shares), the common stock
equivalent of preferred stock outstanding prior to conversion (11,480
shares) or warrants to purchase 6,574 shares of common stock at a weighted
average exercise price of $0.05 as the effects were antidilutive.

12

A reconciliation for the three months ended June 30, 2001 and 2002 and the
six months ended June 30, 2001 is as follows:

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

13

5. SENIOR NOTES AND REVOLVING CREDIT FACILITY

At June 30, 2002, our long-term debt, net of current maturities, consisted
of the following ($ in thousands):

7.875% senior notes, due 2004 ........................ $ 107,799
8.375% senior notes, due 2008 ........................ 250,000
8.125% senior notes, due 2011 ........................ 800,000
8.5% senior notes, due 2012 .......................... 142,665
Revolving bank credit facility ....................... 45,000
Discount on senior notes ............................. (12,697)
Discount for interest rate swap and swaption ......... (6,416)
-------------
Total .............................................. $ 1,326,351
=============

During the Current Period, we purchased and subsequently retired $42.2
million of the 7.875% senior notes for total consideration of $44.0 million,
including $0.8 million of accrued interest and $1.0 million of redemption
premium.

We have a $225 million revolving bank credit facility (with a committed
borrowing base of $225 million) which matures in September 2003. As of June 30,
2002, we had borrowed $45.0 million under this facility and were using $11.1
million of the facility to secure 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 at our option to June 2005 if we
satisfy certain conditions.

The credit facility contains various covenants and restrictive provisions
which restrict our ability to incur additional indebtedness, sell properties,
pay dividends, purchase or redeem our capital stock, make investments or loans,
purchase certain of our senior notes, create liens, and make acquisitions. The
credit facility requires us to maintain a current ratio of at least 1 to 1 (as
defined in the credit facility) 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. If such an acceleration involved principal in excess of $10 million,
the acceleration 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 also has cross default provisions that apply
to other indebtedness we may have with an outstanding principal balance in
excess of $5.0 million.

Our senior notes are unsecured senior obligations of Chesapeake and rank
equally with all of our other unsecured indebtedness. 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.

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.

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

14

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

15

CONDENSED CONSOLIDATED BALANCE SHEET
AS OF JUNE 30, 2002
($ IN THOUSANDS)

16

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ IN THOUSANDS)

17

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ IN THOUSANDS)

18

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)

19

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

20

6. SEGMENT INFORMATION

Chesapeake has two reportable segments under SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information. One segment relates to our
exploration and production activities, and the other segment relates to oil and
gas marketing activities. The reportable segment information can be derived from
Note 5 as Chesapeake Energy Marketing, Inc., is the only significant
non-guarantor subsidiary and the only entity conducting marketing activities for
all income statement periods presented.

7. ACQUISITIONS

On June 28, 2002, we acquired Canaan Energy Corporation in a cash merger
through a Chesapeake subsidiary. Under the agreement, all outstanding common
shares of Canaan, other than the Canaan shares already owned by Chesapeake, were
purchased at $18.00 per share in cash, and the outstanding options to acquire
Canaan common stock were converted into the right to receive, for each share of
Canaan common stock to be received upon exercise, the merger consideration less
the per share exercise price and withholding taxes. The aggregate net cash
consideration for the merger was $120 million, including the retirement of
Canaan's outstanding indebtedness of approximately $43 million.

8. 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 was effective in January
2002. We have adopted these new standards, which have not had a significant
effect on our results of operations or our financial position.

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. SFAS No. 143 is effective for fiscal year beginning after June 15,
2002 and establishes an accounting standard requiring the recording of the fair
value of liabilities associated with the retirement of long-term assets (mainly
plugging and abandonment costs for our depleted wells) in the period in which
the liability is incurred (at the time the wells are drilled). We are currently
evaluating our oil and natural gas properties to determine the impact of the
adoption of SFAS No. 143 or our financial position and results of operations.

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. SFAS 144 was effective January 1, 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. Adoption of SFAS 144 did not
affect our financial position or results of operations.

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. SFAS No. 145 is effective for fiscal years beginning after May 15,
2002. We have not yet adopted SFAS No. 145 nor have we determined the effect of
the adoption on our financial position or results of operations.

In July 2002, the FASB issued SFAS No. 146, Accounting For Costs Associated
with Exit or Disposal Activities. SFAS No. 146 is effective for exit or disposal
activities initiated after December 31, 2002. We have not yet adopted SFAS No.
146 nor determined the effect of the adoption of SFAS No. 146 on our financial
position or results of operations.

21

PART I. FINANCIAL INFORMATION

ITEM 2. 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 -- THREE MONTHS ENDED JUNE 30, 2002 ("CURRENT QUARTER")
VS. JUNE 30, 2001 ("PRIOR QUARTER")

General. For the Current Quarter, Chesapeake had net income available to
common shareholders of $22.5 million, or $0.13 per diluted common share, on
total revenues of $194.3 million. This compares to net income available to
common shareholders of $39.3 million, or $0.23 per diluted common share, on
total revenues of $275.7 million during the Prior Quarter. The Current Quarter's
results included, on a pre-tax basis, a non-cash $0.5 million risk management
loss, while the Prior Quarter's results included, on a pre-tax basis, non-cash
risk management income of $62.5 million.

Oil and Gas Sales. During the Current Quarter, oil and gas sales decreased
13% to $152.0 million from $175.2 million in the Prior Quarter. For the Current
Quarter, we produced 43.4 billion cubic feet equivalent (bcfe), consisting of
0.8 million barrels of oil (mmbbl) and 38.5 billion cubic feet of gas (bcf),
compared to 0.7 mmbbl and 35.0 bcf, or 39.1 bcfe, in the Prior Quarter. The
production increase is primarily the result of successful drilling results
complemented with production from various acquisitions which occurred in late
2001, partially offset by the sale of our Canadian reserves effective October 1,
2001. Average oil prices realized were $26.55 per bbl in the Current Quarter
compared to $27.70 per bbl in the Prior Quarter, a decrease of 4%. Average gas
prices realized were $3.38 per thousand cubic feet in the Current Quarter
compared to $4.46 per mcf in the Prior Quarter, a decrease of 24%.

For the Current Quarter, we realized an average price of $3.50 per mcfe,
compared to $4.48 per mcfe in the Prior Quarter, including in each case the
effects of hedging. Our hedging activities resulted in increased oil and gas

22

revenues of $13.4 million, or $0.31 per mcfe, in the Current Quarter, compared
to an increase in oil and gas revenues of $7.2 million, or $0.18 per mcfe, in
the Prior Quarter.

The following table shows our production by region for the Prior Quarter and
the Current Quarter:

Gas production represented approximately 89% of our total production volume
on an equivalent basis in the Current Quarter, compared to 90% in the Prior
Quarter.

Risk Management Income (Loss). Chesapeake recognized a $0.5 million non-cash
risk management loss in the Current Quarter, compared to a $62.5 million
non-cash gain in the Prior Quarter. The risk management loss for the Current
Quarter consisted of a $10.9 million non-cash gain related to changes in fair
value of derivatives not designated as cash flow hedges, $10.6 million of
reclassifications related to the settlement of such contracts, a $1.4 million
non-cash loss associated with the ineffective portion of derivatives qualifying
for cash flow hedge accounting, a $1.7 million non-cash gain associated with the
portion of our interest rate swap that does not qualify for fair value hedge
accounting, and a $1.1 million non-cash loss associated with the ineffective
portion of our swaption. Risk management income in the Prior Quarter included a
$61.5 million non-cash gain attributable to the change in fair value of certain
derivatives not designated as cash flow hedges and a non-cash gain of $1.0
million associated with the ineffective portion of our cash flow hedges.

Pursuant to SFAS 133, our cap-swaps, straddles, strangles, counter-swaps and
basis protection swaps do not qualify for designation as cash flow hedges. There
is also a portion of our interest rate swap that does not qualify as a fair
value hedge. Therefore, changes in fair value of these instruments that occur
prior to their maturity, together with any change in fair value of 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 cash flow or fair value hedge accounting treatment. All amounts
initially recorded in this caption are ultimately reversed within this same
caption and are included in oil and gas sales and interest expense, as
applicable, over the respective contract terms. Detailed information about our
oil and gas hedging positions appears in Item 3 - Quantitative and Qualitative
Disclosures About Market Risk.

Oil and Gas Marketing Sales. We generated $42.8 million in oil and gas
marketing sales for third parties in the Current Quarter, with corresponding oil
and gas marketing expenses of $41.2 million, for a net margin of $1.6 million.
This compares to sales of $38.0 million, expenses of $36.9 million, and a net
margin of $1.1 million in the Prior Quarter. The increase in marketing sales and
cost of sales was due primarily to an increase in oil and gas sales volumes in
the Current Quarter compared to the Prior Quarter, partially offset by a
decrease in oil and gas prices in the Current Quarter.

Production Expenses. Production expenses, which include lifting costs and ad
valorem taxes, increased to $24.2 million in the Current Quarter, a $5.4 million
increase from the $18.8 million of production expenses incurred in the Prior
Quarter. On a unit of production basis, production expenses were $0.56 and $0.48
per mcfe in the Current and Prior Quarters, respectively. The increase in costs
on a per unit basis in the Current Quarter 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 for the remainder of 2002 will range from $0.53 to $0.57.

Production Taxes. Production taxes were $7.9 million and $10.0 million in
the Current and Prior Quarters, respectively. On a per unit basis, production
taxes were $0.18 per mcfe in the Current Quarter compared to $0.26 per mcfe in
the Prior Quarter. The decrease in the Current Quarter was the result of
decreased prices and new

23

statutory exemptions on certain wells in Oklahoma and Texas. 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
for the remainder of 2002 to be approximately 6% - 7% of oil and gas sales
revenues excluding any impact from hedging.

General and Administrative. General and administrative expenses, which are
net of capitalized internal costs, were $3.9 million in the Current Quarter
compared to $2.9 million in the Prior Quarter. The increase in the Current
Quarter is the result of Chesapeake's continued growth.

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 $2.8 million and $2.1 million of internal costs in the Current
Quarter and Prior Quarter, respectively, directly related to our oil and gas
exploration and development efforts. We anticipate that general and
administrative expenses for the remainder of 2002 will be between $0.10 and
$0.11 per mcfe, which is approximately the same level as 2001 and the Current
Quarter.

Oil and Gas Depreciation, Depletion and Amortization. Depreciation,
depletion and amortization of oil and gas properties for the Current Quarter was
$50.8 million, compared to $39.9 million in the Prior Quarter. The DD&A rate per
mcfe, which is a function of capitalized costs, future development costs and the
related underlying reserves in the periods presented, increased from $1.02 in
the Prior Quarter to $1.17 per mcfe in the Current Quarter. We expect the DD&A
rate for the remainder of 2002 to be between $1.25 and $1.35 per mcfe.

Depreciation and Amortization of Other Assets. Depreciation and amortization
of other assets was $3.7 million in the Current Quarter, compared to $1.8
million in the Prior Quarter. The increase in the Current Quarter was primarily
the result of higher depreciation recorded on recently acquired fixed assets.
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 three to seven years. We expect
depreciation and amortization of other assets to average between $0.08 and $0.10
per mcfe for the remainder of 2002 which approximates the current rate.

Interest and Other Income. Interest and other income for the Current Quarter
was $3.7 million compared to $0.7 million in the Prior Quarter. The increase was
primarily the result of additional interest income from significantly higher
cash balances held during the Current Quarter, as well as interest income
recorded on our investment in senior secured notes issued by Seven Seas
Petroleum Inc.

Interest Expense. Interest expense increased to $24.7 million in the Current
Quarter from $23.0 million in the Prior Quarter. The increase in the Current
Quarter was due primarily to a $113 million increase in average long-term
borrowings in the Current Quarter compared to the Prior Quarter, partially
offset by income of $1.6 million earned on our interest rate swap during the
Current Quarter. In addition to the interest expense reported, we capitalized
$1.1 million of interest during the Current Quarter, compared to $1.4 million
capitalized in the Prior Quarter, 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 of our outstanding borrowings. We anticipate
that capitalized interest for the remainder of 2002 will be between $2.0 million
and $2.5 million.

Provision (Benefit) for Income Taxes. Chesapeake recorded income tax expense
of $16.7 million in the Current Quarter, compared to income tax expense of $57.5
million in the Prior Quarter. Income tax expense for the Prior Quarter was
comprised of $54.7 million related to our domestic operations and $2.8 million
related to our Canadian operations which were sold on October 1, 2001. We
anticipate that all 2002 income tax expense will be deferred.

24

RESULTS OF OPERATIONS -- SIX MONTHS ENDED JUNE 30, 2002 ("CURRENT PERIOD") VS.
JUNE 30, 2001 ("PRIOR PERIOD")

General. For the Current Period, Chesapeake had a net loss available to
common shareholders of $7.6 million, or a loss of $0.05 per diluted common
share, on total revenues of $284.1 million. This compares to net income
available to common shareholders of $109.0 million, or $0.64 per diluted common
share, on total revenues of $553.1 million during the Prior Period. The Current
Period's net loss included, on a pre-tax basis, a non-cash $79.9 million risk
management loss, while the Prior Period's results included, on a pre-tax basis,
non-cash risk management income of $62.5 million.

Oil and Gas Sales. During the Current Period, oil and gas sales decreased
26% to $294.0 million from $396.4 million in the Prior Period. For the Current
Period, we produced 85.3 billion cubic feet equivalent, consisting of 1.7
million barrels of oil and 75.4 billion cubic feet of gas, compared to 1.4 mmbbl
and 71.1 bcf, or 79.3 bcfe, in the Prior Period. The production increase is
primarily the result of successful drilling results complemented with production
from various acquisitions which occurred in late 2001, partially offset by the
sale of our Canadian reserves effective October 1, 2001. Average oil prices
realized were $25.29 per bbl in the Current Period compared to $28.36 per bbl in
the Prior Period, a decrease of 11%. Average gas prices realized were $3.34 per
thousand cubic feet in the Current Period compared to $5.03 per mcf in the Prior
Period, a decrease of 34%.

For the Current Period, we realized an average price of $3.45 per mcfe,
compared to $5.00 per mcfe in the Prior Period, including in each case the
effects of hedging. Our hedging activities resulted in increased oil and gas
revenues of $62.0 million, or $0.73 per mcfe, in the Current Period, compared to
decreases in oil and gas revenues of $23.3 million, or $0.29 per mcfe, in the
Prior Period.

The following table shows our production by region for the Prior Period and
the Current Period:

Gas production represented approximately 88% of our total production volume
on an equivalent basis in the Current Period, compared to 90% in the Prior
Period.

Risk Management Income (Loss). Chesapeake recognized a $79.9 million
non-cash risk management loss in the Current Period, compared to a $62.5 million
non-cash gain in the Prior Period. The risk management loss for the Current
Period consisted of a $42.5 million non-cash loss related to changes in fair
value of derivatives not designated as cash flow hedges, $35.7 million of
reclassifications related to the settlement of such contracts, a $2.2 million
non-cash loss associated with the ineffective portion of derivatives qualifying
for cash flow hedge accounting, a $1.6 million non-cash gain associated with the
portion of our interest rate swap that does not qualify for fair value hedge
accounting, and a $1.1 million non-cash loss associated with the ineffective
portion of our swaption. Risk management income for the Prior Period included a
$61.5 million non-cash gain attributable to the change in fair value of certain
derivatives not designated as cash flow hedges, and a non-cash gain of $1.0
million associated with the ineffective portion of our cash flow hedges.

Pursuant to SFAS 133, our cap-swaps, straddles, strangles, counter-swaps and
basis protection swaps do not qualify for designation as cash flow hedges. There
is also a portion of our interest rate swap that does not qualify as a fair
value hedge. Therefore, changes in fair value of these instruments that occur
prior to their maturity, together with any change in fair value of 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 cash flow or fair value hedge accounting treatment. All amounts
initially recorded in this caption are ultimately reversed within this same
caption and are included in oil and gas sales and interest expense, as

25

applicable, over the respective contract terms. Detailed information about our
oil and gas hedging positions appears in Item 3 - Quantitative and Qualitative
Disclosures About Market Risk.

Oil and Gas Marketing Sales. We generated $70.1 million in oil and gas
marketing sales for third parties in the Current Period, with corresponding oil
and gas marketing expenses of $67.7 million, for a net margin of $2.4 million.
This compares to sales of $94.2 million, expenses of $91.4 million, and a net
margin of $2.8 million in the Prior Period. The decrease in marketing sales and
cost of sales was due primarily to a decrease in oil and gas prices in the
Current Period compared to the Prior Period, partially offset by an increase in
volumes marketed by Chesapeake Energy Marketing, Inc. in the Current Period.

Production Expenses. Production expenses, which include lifting costs and ad
valorem taxes, increased to $46.3 million in the Current Period, a $9.7 million
increase from the $36.6 million of production expenses incurred in the Prior
Period. On a unit of production basis, production expenses were $0.54 and $0.46
per mcfe in the Current and Prior Periods, respectively. The increase in costs
on a per unit basis in the Current Period 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 for the remainder of 2002 will range from $0.53 to $0.57.

Production Taxes. Production taxes were $13.1 million and $24.3 million in
the Current and Prior Periods, respectively. On a per unit basis, production
taxes were $0.15 per mcfe in the Current Period compared to $0.31 per mcfe in
the Prior Period. The decrease in the Current Period was the result of decreased
prices and new statutory exemptions on certain wells in Oklahoma and Texas. 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 for the remainder of 2002 to be approximately 6% - 7% of oil and gas sales
revenues excluding any impact from hedging.

General and Administrative. General and administrative expenses, which are
net of capitalized internal costs, were $8.2 million in the Current Period
compared to $6.9 million in the Prior Period. The increase in the Current Period
is a result of Chesapeake's continued growth.

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 $5.3 million and $3.9 million of internal costs in the Current
Period and Prior Period, respectively, directly related to our oil and gas
exploration and development efforts. We anticipate that general and
administrative expenses for the remainder of 2002 will be between $0.10 and
$0.11 per mcfe, which is approximately the same level as 2001 and the Current
Period.

Oil and Gas Depreciation, Depletion and Amortization. Depreciation,
depletion and amortization of oil and gas properties for the Current Period was
$99.4 million, compared to $78.1 million in the Prior Period. The DD&A rate per
mcfe, which is a function of capitalized costs, future development costs and the
related underlying reserves in the periods presented, increased from $0.98 in
the Prior Period to $1.17 per mcfe in the Current Period. We expect the DD&A
rate for the remainder of 2002 to be between $1.25 and $1.35 per mcfe.

Depreciation and Amortization of Other Assets. Depreciation and amortization
of other assets was $6.8 million in the Current Period, compared to $3.8 million
in the Prior Period. The increase in the Current Period was primarily the result
of higher depreciation recorded on recently acquired fixed assets. 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 three to seven years. We expect
depreciation and amortization of other assets to average between $0.08 and $0.10
per mcfe for the remainder of 2002 which approximates the current rate.

Interest and Other Income. Interest and other income for the Current Period
was $4.7 million compared to $1.3 million in the Prior Period. The increase was
primarily the result of additional interest income from significantly higher
cash balances held during the Current Period as well as interest income recorded
on our investment in senior secured notes issued by Seven Seas Petroleum Inc.

26

Interest Expense. Interest expense increased to $51.7 million in the Current
Period from $48.9 million in the Prior Period. The increase in the Current
Period was due to a $167 million increase in average long-term borrowings in the
Current Period compared to the Prior Period, partially offset by income of $1.6
million earned on our interest rate swap during the Current Period. In addition
to the interest expense reported, we capitalized $2.3 million of interest during
each of the Current Period and Prior Period 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 of our outstanding
borrowings. We anticipate that capitalized interest for the remainder of 2002
will be between $2.0 million and $2.5 million.

Gothic Standby Credit Facility Costs. During the Prior Period, 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 in February 2001. Chesapeake incurred $3.4 million of costs for the
standby facility, which were recognized in the Prior Period.

Provision (Benefit) for Income Taxes. Chesapeake recorded an income tax
benefit of $1.7 million in the Current Period, compared to income tax expense of
$105.2 million in the Prior Period. Income tax expense for the Prior Period was
comprised of $97.9 million related to our domestic operations and $7.3 million
related to our Canadian operations which were sold on October 1, 2001. We
anticipate that all 2002 income tax expense will be deferred.

CASH FLOWS FROM OPERATING, INVESTING, AND FINANCING ACTIVITIES

Cash Flows from Operating Activities. Cash provided by operating activities
decreased 28% to $214.8 million during the Current Period compared to $297.0
million during the Prior Period. The decrease was due primarily to lower oil and
gas prices realized during the Current Period.

Cash Flows from Investing Activities. Cash used in investing activities
increased to $324.6 million during the Current Period from $302.0 million in the
Prior Period. During the Current Period, we expended approximately $176.4
million to initiate drilling on 281 (123.7 net) wells and invested approximately
$7.2 million in unproved properties. This compares to $179.9 million to initiate
drilling on 280 (143.0 net) wells and $48.5 million to purchase unproved
properties in the Prior Period. During the Current Period, we had acquisitions
of oil and gas companies and properties of $124.3 million and no divestitures of
oil and gas properties. This compares to acquisitions of oil and gas companies
and properties of $53.1 million and divestitures of $0.2 million in the Prior
Period. During the Current Period, we had additional investments in drilling rig
equipment and other fixed assets of $18.6 million compared to $20.8 million in
the Prior Period. The Current Period included additional investments in the
common stock of two oil and gas companies totaling $2.4 million and $4.2 million
in proceeds from the sale of RAM Energy, Inc. notes.

Cash Flows from Financing Activities. There was $1.6 million of cash used in
financing activities in the Current Period, compared to cash provided by
financing activities of $5.1 million in the Prior Period. The activity in the
Current Period reflects the net increase in borrowings under our commercial bank
credit facility of $45.0 million. This was primarily offset by the repurchase of
$42.2 million of our 7.875% senior notes. We received $2.0 million in cash from
the exercise of stock options, and $5.1 million was used to pay dividends on our
6.75% preferred stock. The activity in the Prior Period included increased
borrowings under our credit facility of $135.0 million, $786.7 million received
from the issuance of $800.0 million of 8.125% senior notes, $906.0 million used
to redeem various senior notes, $12.2 million used to pay financing costs
related to new debt issuance, and $2.8 million received from the exercise of
stock options.

27

LIQUIDITY AND CAPITAL RESOURCES

Sources of Liquidity

Chesapeake had a working capital deficit of $19.6 million at June 30, 2002,
including $6.3 million in cash. We have a $225 million revolving bank credit
facility (with a committed borrowing base of $225 million) which matures in
September 2003 but under certain circumstances can be extended through June
2005. As of June 30, 2002, we had borrowed $45.0 million under the facility and
were using $11.1 million of the facility to secure various letters of credit. As
of August 2, 2002, borrowings under the credit facility had increased to $65.0
million, largely as a result of borrowings to fund an acquisition in late July
2002. The use of facility borrowings and long-term indebtedness to fund recent
and pending acquisitions is discussed below under Investing and Financing
Transactions. We believe we will have adequate resources, including 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 the remainder of 2002, which is currently estimated to be $160
- - $180 million. Further, our drilling program is largely discretionary and can
be adjusted to match changing circumstances. Based on our current cash flow
assumptions we expect operating cash flow to reach $380 - $400 million during
2002. Any operating cash flow not needed to fund our drilling program will be
available for acquisitions, debt repayments 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. 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 concentration of
these assets in the oil and gas industry 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 do not issue commercial
paper.

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 June 30,
2002, we had borrowed $45.0 million under this facility and were using $11.1
million of the facility to secure 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 credit facility contains various covenants and restrictive provisions
which restrict our ability to incur additional indebtedness, sell properties,
pay dividends, purchase or redeem our capital stock, make investments or loans,
purchase certain of our senior notes, create liens, and make acquisitions. The
credit facility requires us to maintain a current ratio of at least 1 to 1 (as
defined in the credit facility) 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. If such an acceleration involved principal in excess of $10 million,
the acceleration 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 also has cross default provisions that apply
to other indebtedness we may have with an outstanding principal balance in
excess of $5.0 million.

28

As of June 30, 2002, 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, $107.8 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 $107.8 million is due, giving effect to the repurchase and retirement
of $42.2 million of our 7.875% senior notes in the Current Period. 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. 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. We
can acquire outstanding senior notes at either make-whole or redemption prices
set forth in the respective indentures, and from time to time we acquire senior
notes through market purchases. If we repurchase at least an additional $32.8
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 June 30, 2002, we
estimate that secured commercial bank indebtedness of approximately $385 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.

Some of our commodity price and interest rate risk management arrangements
require us to deliver cash collateral or other assurances of performance to the
counterparties in the event that our payment obligations with respect to our
commodity price and interest rate risk management transactions exceed certain
levels. At June 30, 2002, we posted $10.0 million of collateral with one of our
counterparties through a letter of credit issued under our bank credit
facility. Future collateral requirements are uncertain and will depend on
arrangements with our counterparties and the level of volatility in natural gas
and oil prices and interest rates.

Investing and Financing Transactions

On June 28, 2002, we acquired Canaan Energy Corporation in a cash merger
through a Chesapeake subsidiary. Under the agreement, all outstanding common
shares of Canaan, other than the Canaan shares already owned by Chesapeake, were
purchased at $18.00 per share in cash, and the outstanding options to acquire
Canaan common stock were converted into the right to receive, for each share of
Canaan common stock to be received upon exercise, the merger consideration less
the per share exercise price and withholding taxes. The aggregate net cash
consideration for the merger was $120 million, including the retirement of
Canaan's outstanding indebtedness of approximately $43 million.

In the Current Period, we purchased and subsequently retired $42.2 million
of our 7.875% senior notes due 2004 for total consideration of $44.0 million,
including accrued interest of $0.8 million and $1.0 million of redemption
premium.

See Note 2 of the notes to consolidated financial statements included in
this report for a discussion of our hedging activities and financial
instruments.

In late July 2002, we completed an acquisition of oil and gas properties
using bank facility borrowings to fund the cash purchase price of $38 million.
We have entered into three definitive purchase agreements to acquire additional
oil and gas properties for an aggregate cash purchase price of approximately
$132 million. We expect to close these acquisitions during the third quarter of
2002. It is our intent to fund these acquisitions by issuing long-

29

term unsecured notes through a private offering. If for any reason this market
is not available, we intend to use the bank facility to fund the acquisitions.

RECENTLY ISSUED ACCOUNTING STANDARDS

See Note 8 of the notes to the consolidated financial statements included in
this report for a summary of recently issued accounting standards.

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 of our Form 10-K for the year ended December 31, 2001. These
factors 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
federal and state income tax net operating loss (NOL) carryforwards
before their 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.

30

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

OIL AND GAS 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 the exposure to
adverse market changes, we have entered into various derivative instruments. As
of June 30, 2002, our derivative instruments were comprised of swaps, collars,
cap-swaps, straddles, strangles and basis protection swaps. These instruments
allow us to predict with greater certainty the effective oil and gas prices to
be received for our hedged production. 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.

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" limiting the counterparty's exposure.

o For straddles, Chesapeake receives a premium from the counterparty in
exchange for the sale of a call and a put option at an established fixed
price. To the extent that the floating market price differs from the
established fixed price, Chesapeake pays the counterparty.

o For strangles, Chesapeake receives a premium from the counterparty in
exchange for the sale of a call and a put option. If the market price
exceeds the fixed price of the call option or falls below the fixed
price of the put option, then Chesapeake pays the counterparty. If the
market price settles between the fixed price of the call and put option,
no payment is due from Chesapeake.

o Basis protection swaps are arrangements that guarantee a price
differential of oil and gas from a specified delivery point. Chesapeake
receives a payment from the counterparty if the price differential is
greater than the stated terms of the contract and pays the counterparty
if the price differential is less than the stated terms of the contract.

From time to time, we close certain swap transactions designed to hedge a
portion of our oil and natural gas production by entering into a counter-swap
instrument. Under the counter-swap we receive a floating price for the hedged
commodity and pay a fixed price to the counterparty. To the extent the
counter-swap, which does not qualify for hedge accounting under SFAS 133, is
designed to lock the value of an existing SFAS 133 cash flow hedge, the net
value of the swap and the counter-swap is frozen and shown as a derivative
receivable or payable in the consolidated balance sheets. At the same time, the
original swap is designated as a non-qualifying cash flow hedge under SFAS 133.

Pursuant to SFAS 133, our cap-swaps, straddles, strangles, counter-swaps and
basis protection 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 statements 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 SFAS 133 cash flow hedge accounting treatment. All amounts
initially recorded in this caption related to commodity derivatives are
ultimately reversed within this same caption and included in oil and gas sales
over the respective contract terms.

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As of June 30, 2002, we had the following open oil and gas derivative
instruments designed to hedge a portion of our gas production for periods after
June 2002:

- ----------

(a) After adjusting for the $34.5 million premium paid to Chesapeake by the
counterparty at the inception of the straddle and strangle contracts (which
is recorded in cash provided by operating activities on the accompanying
consolidated statements of cash flows), the net value of the combined
hedging portfolio at June 30, 2002 was $31.2 million.

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
June 30, 2002.

32

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

Fair value of contracts outstanding at January 1, 2002 ............. $ 157,309
Change in fair value of contracts during period .................... (55,623)
Contracts realized or otherwise settled during the period .......... (61,989)
Fair value of new contracts when entered into during the period .... (42,991)
------------
Fair value of contracts outstanding at June 30, 2002 ............... $ (3,294)
============

Risk management income (loss) related to our oil and gas derivatives is
comprised of the following ($ in thousands):

The change in the fair value of our derivative instruments since January 1,
2002 resulted from an increase in market prices for natural gas and crude oil.
Derivative instruments 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 consolidated balance sheet dates. The
derivative settlement amounts are not due and payable until the month in which
the related underlying hedged transaction occurs.

Based upon the market prices at June 30, 2002, we would expect to transfer
approximately $11.3 million of the balance in accumulated other comprehensive
income to earnings during the next 12 months when the transactions actually
occur. All transactions hedged as of June 30, 2002 are expected to mature by
December 31, 2004, with the exception of the basis protection swaps which extend
to 2009.

INTEREST RATE RISK

We also utilize hedging strategies to manage interest rate exposure. In
March 2002, we entered into an interest rate swap to convert a portion of our
fixed rate debt to floating rate debt. The terms of this swap agreement are as
follows:

If the floating rate is less than the fixed rate, the counterparty will pay
us accordingly. If the floating rate exceeds the fixed rate, we will pay the
counterparty. Payments under this interest rate swap coincide with the
semi-annual interest payments on our 7.875% senior notes which are due on
September 15 and March 15 of each year beginning September 15, 2002.

A portion of the interest rate swap was originally entered into to convert
$129.0 million of the 7.875% senior notes from fixed rate debt to variable rate
debt. Under SFAS 133, a hedge of the interest rate risk in a recognized fixed
rate liability can be designated as a fair value hedge under which the
mark-to-market value of the swap is recorded on the consolidated balance sheets
as an asset or liability with a corresponding increase or decrease in carrying
value of the debt. See Note 5 of the notes to consolidated financial statements
included in this report for the adjustments made to the carrying value of debt
at June 30, 2002. During the Current Quarter, $21.2 million of the 7.875% senior
notes were purchased and subsequently retired resulting in a $0.4 million gain
on the repurchase of debt related to the interest rate swap. As a result of
these repurchases, $107.8 million of the interest rate swap was designated as a
fair value hedge under SFAS 133 at June 30, 2002.

33

Results from interest rate hedging transactions are reflected as adjustments
to interest expense in the corresponding months covered by the swap agreement.

The remaining $92.2 million of the interest rate swap has not been
designated as a fair value hedge. The mark-to-market value of this portion of
the instrument is recorded as a derivative asset or liability on the
consolidated balance sheets with the offsetting amount reflected in risk
management income (loss) on the consolidated statements of operations. The
amount recorded in risk management income (loss) will be reversed and reflected
in interest expense over the term of the swap.

The estimated fair value of the interest rate swap at June 30, 2002 was an
asset of approximately $5.0 million comprised of $1.6 million reflected as risk
management income, $1.4 million reflected as an increase in the carrying value
of our long-term debt, $1.6 million reflected as a reduction in interest
expense, and $0.4 million reflected as other income related to the gain on the
repurchase of debt.

In June 2002, we entered into an additional interest rate swap. The terms of
this swap agreement are as follows:

If the floating rate is less than the fixed rate, the counterparty will pay
us accordingly. If the floating rate exceeds the fixed rate, we will pay the
counterparty. Payments under this interest rate swap are made on July 2 and
January 2 of each year beginning January 2, 2003. The estimated fair value of
the interest rate swap at June 30, 2002 was negligible.

In July 2002, we closed both interest rate swaps for a combined gain of $8.6
million. Gains totaling $6.6 million, in addition to the $2.0 million gain
already realized in the Current Quarter, will be recognized as reductions to
interest expense over the remaining terms of the swaps.

In April 2002, we entered into a swaption agreement in order to monetize the
embedded call option in the remaining $142.7 million of our 8.5% senior notes.
We received $7.8 million from the counterparty at the time we entered into this
agreement. The terms of the swaption are as follows:

Under the terms of the swaption agreement, the counterparty will have the
option to initiate an interest rate swap on March 11, 2004 pursuant to the terms
shown above. If the counterparty chooses to initiate the interest rate swap, the
payments under the swap will coincide with the semi-annual interest payments on
our 8.5% senior notes which are paid on September 15 and March 15 of each year.
On each payment date, if the fixed rate exceeds the floating rate, we will pay
the counterparty, and if the floating rate exceeds the fixed rate, the
counterparty will pay us accordingly. If the counterparty does not choose to
initiate the interest rate swap, the swaption agreement will expire and no
future obligations will exist for either party.

According to SFAS 133, a fair value hedge relationship exists between the
embedded call option in the 8.5% senior notes and our swaption agreement.
Accordingly, the mark-to-market value of the swaption is recorded on the
consolidated balance sheets as an asset or liability with a corresponding
increase or decrease to the debt's carrying value. Any change in the fair value
of the swaption resulting from ineffectiveness is recorded currently in the
consolidated statements of operations as risk management income (loss).

We have recorded a decrease in the carrying value of the debt of $7.8
million related to the swaption as of June 30, 2002. Of this amount, $8.9
million represents the mark-to-market valuation of the swaption, offset by $1.1
million estimated ineffectiveness of the swaption as determined under SFAS 133.
See Note 5 of the notes to consolidated financial statements included in this
report for the adjustments made to the carrying value of the debt at

34

June 30, 2002. Results of the swaption will be reflected as adjustments to
interest expense in the corresponding months covered by the swaption agreement.

Risk management income related to our fair value hedges is comprised of the
following ($ in thousands):

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.

- ----------

(a) This amount does not include the discount included in long-term debt of
($12.7) million, the value of the interest rate swaps of $1.4 million and
the value of the swaption of ($7.8) million.

MARKETING ACTIVITIES

In addition to marketing our own oil and gas production, our marketing
activities include marketing oil and gas production for working interest owners
and royalty owners in the wells that we operate. Such activities include the
operation of gathering systems and the sale of oil and natural gas under various
arrangements. Recently royalty owners have commenced litigation against a number
of companies in the oil and gas production business claiming that amounts paid
for production attributable to the royalty owners' interest violated the terms
of the applicable leases and state law, that deductions from the proceeds of oil
and gas production were unauthorized under the applicable leases and that
amounts received by upstream sellers should be used to compute the amounts paid
to the royalty owners. A portion of the foregoing litigation has been commenced
as class action suits including four class action suits filed against Chesapeake
and others which we believe do not represent valid claims or, if valid, are not
material. As new cases are decided and the law in this area continues to
develop, our liability relating to the marketing of oil and gas may increase or
decrease. We will continue to monitor the court decisions to ensure that our
operations and practices minimize any exposure and to recognize any charges that
may be appropriate.

35

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are subject to ordinary routine litigation incidental to our business,
none of which is expected to have a material adverse effect on Chesapeake. In
addition, Chesapeake is a defendant in other pending actions which are described
in Note 3 of the notes to the consolidated financial statements included in this
report and Item 3 of our Annual Report on Form 10-K for the year ended December
31, 2001.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

Not applicable

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable

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

Three matters were submitted to a vote of the shareholders at Chesapeake's
annual meeting of shareholders held on June 7, 2002: the election of directors,
the adoption of a stock option plan for employees and consultants and the
adoption of a stock option plan for non-employee directors. In the election of
directors, Aubrey K. McClendon received 153,808,677 votes for election and
4,670,442 shares were withheld from voting for Mr. McClendon; and Shannon T.
Self received 153,868,588 votes for election and 4,610,531 share were withheld
from voting for Mr. Self. The other directors whose terms continued after the
meeting are Edgar F. Heizer, Jr., Breene M. Kerr, Tom L. Ward and Frederick B.
Whittemore. In the adoption of our 2002 Stock Option Plan, 121,950,327 votes
were received for the adoption of the plan, 36,092,764 votes were received
against adoption of the plan and 436,025 shares were withheld from voting on
this proposal. In the adoption of our 2002 Non-Employee Director Stock Option
Plan, 120,983,754 votes were received for the adoption of the plan, 36,993,462
votes were received against adoption of the plan and 501,899 shares were
withheld from voting on this proposal. There were no broker non-votes.

ITEM 5. OTHER INFORMATION

Not applicable

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

The following exhibits are filed as a part of this report:

EXHIBIT
NUMBER DESCRIPTION

3.1 Chesapeake's Restated Certificate of Incorporation
together with the Certificate of Designation for the
6.75% Cumulative Convertible Preferred Stock of
Chesapeake and the Certificate of Designation for the
Series A Junior Participating Preferred Stock of
Chesapeake. Incorporated herein by reference to Exhibit
3.1 to Chesapeake's registration statement on Form S-3
(No. 333-96863) filed July 22, 2002.

4.6.1 Second Amendment dated June 4, 2002 with respect to
Second Amended and Restated Credit Agreement, dated as
of June 11, 2001, among Chesapeake Energy Corporation,
Chesapeake Exploration Limited Partnership, as Borrower,
Bear Stearns Corporate Lending Inc., as Syndication
Agent, Union Bank of California, N.A., as Administrative
Agent and Collateral Agent, and other lenders party
thereto.

36

12.1 Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.

(b) Reports on Form 8-K

During the quarter ended June 30, 2002, we filed the following current
reports on Form 8-K:

On April 4, 2002, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing first quarter 2002 earnings
release and conference call dates.

On April 16, 2002, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing that our Board of Directors
had declared a regular quarterly dividend on our preferred stock.

On April 23, 2002, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing an agreement to acquire
Canaan Energy Corporation.

On April 30, 2002, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing first quarter 2002
financial and operating results. We furnished under Item 9 updates to our
operational and financial guidance for 2002 included in the press release.

On June 5, 2002, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing that our 2002 Annual
Meeting of Shareholders would be webcast live.

37

SIGNATURES

Pursuant to the requirements 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
(Registrant)

By: /s/ AUBREY K. MCCLENDON
----------------------------
Aubrey K. McClendon
Chairman and Chief Executive Officer

By: /s/ MARCUS C. ROWLAND
---------------------------
Marcus C. Rowland
Executive Vice President and
Chief Financial Officer

Date: August 5, 2002

38

INDEX TO EXHIBITS