CHESAPEAKE ENERGY CORP - 10-Q Quarterly Report

Back to GetFilings.com

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 September 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 November 4, 2002, there were 166,253,078 shares of our $.01 par value
common stock outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 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
SEPTEMBER 30, 2002
(UNAUDITED)

1. BASIS OF PRESENTATION

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 nine months ended September 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 nine months ended September 30, 2001 (the
"Prior Quarter" and "Prior Period", respectively) and the three and nine months
ended September 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 September 30, 2002, our oil and gas 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

7

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
September 30, 2002 are provided below. The associated carrying values of these
instruments are equal to the estimated fair values.

(a) After adjusting for the $31.1 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 September 30, 2002 was $10.1 million.

Based upon the market prices at September 30, 2002, we expect to transfer
approximately $6.4 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 September 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 ...................... (48,559)
Contracts realized or otherwise settled during the period ............ (84,150)
Fair value of new contracts when entered into during the period ...... (45,603)
---------
Fair value of contracts outstanding at September 30, 2002 ............ $ (21,003)
=========

8

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

Interest Rate Hedging

We also utilize hedging strategies to manage interest rate exposure.
Results from interest rate hedging transactions are reflected as adjustments to
interest expense in the corresponding months covered by the derivative
agreement.

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:

At the inception of the interest rate swap agreement, a portion of the
interest rate swap was 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 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. During the Current
Quarter and Current Period, $21.3 million and $63.5 million face value,
respectively, of the 7.875% senior notes were purchased and subsequently
retired. In connection with the repurchase of the 7.875% senior notes, interest
rate swap hedging gains of $0.4 million and $0.9 million were recognized in the
Current Quarter and Current Period, respectively, and reduced the loss on
repurchases of debt.

In July 2002, we closed the above interest rate swap for a gain of $7.5
million. As of September 30, 2002, the remaining balance to be amortized as a
reduction to interest expense was $4.1 million. During the Current Period, $2.5
million was recognized as a reduction to interest expense.

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

In July 2002, we closed this interest rate swap for a gain of $1.1 million.
During the Current Period, $0.1 million was recognized as a reduction to
interest expense.

9

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.

Under SFAS 133, a fair value hedge relationship exists between the embedded
call option in the debt and the 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 $20.3
million during the Current Period related to the swaption as of September 30,
2002. Of this amount, $21.4 million represents a decline in the fair value of
the swaption, offset by a loss of $1.1 million from estimated ineffectiveness of
the swaption as determined under SFAS 133. See Note 5 for the adjustments made
to the carrying value of the debt at September 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):

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 September 30, 2002 was $1,330.1 million and $1,512.7 million,
respectively, compared to approximate fair values of $1,343.0 and $1,529.4
million, respectively. The carrying amount for our 6.75% convertible preferred
stock at September 30, 2002 was $149.9 million, compared to the approximate fair
value of $156.5 million.

10

Concentration of Credit Risk

A significant portion of our liquidity is concentrated in cash and cash
equivalents, 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 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 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

11

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 five class action suits filed against Chesapeake
and others. No class has been certified in any of the cases in which Chesapeake
is a named defendant. We believe the claims asserted 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 when we can reasonably estimate
a liability.

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 No. 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 3.8 million, 7.8 million,
0.3 million and 0.5 million shares of common stock at a weighted average
exercise price of $6.97, $6.56, $17.25 and $12.77, respectively, were
antidilutive because the exercise prices of the options were greater than
the average market price of the common stock.

o Diluted shares in the Current Quarter and Current Period do not include the
assumed conversion of the outstanding 6.75% preferred stock (convertible
into 19.5 million common shares) and the Current Period does not include
the common stock equivalent of preferred stock outstanding prior to
conversion of 7,611 shares, as the effects were antidilutive.

12

A reconciliation for the periods presented is as follows:

5. SENIOR NOTES AND REVOLVING CREDIT FACILITY

At September 30, 2002, our long-term debt consisted of the following ($ in
thousands):

7.875% senior notes, due 2004 .................... $ 86,459
8.375% senior notes, due 2008 .................... 250,000
8.125% senior notes, due 2011 .................... 800,000
8.5% senior notes, due 2012 ...................... 142,665
9.0% senior notes, due 2012 ...................... 250,000
Revolving bank credit facility ................... --
Discount on senior notes ......................... (16,439)
Discount for interest rate swaps and swaption .... (18,505)
-----------
Total .......................................... $ 1,494,180
===========

13

During the Current Period, we purchased and subsequently retired $63.5
million of the 7.875% senior notes for total consideration of $66.3 million,
including $0.9 million of accrued interest and $1.9 million of redemption
premium. Subsequent to September 30, 2002, we purchased $25.6 million of the
7.875% senior notes for total consideration of $26.8 million, including $0.2
million in accrued interest and $1.0 million in redemption premium.

In August 2002, we issued $250 million principal amount of 9% senior notes
due 2012, which were subsequently exchanged on October 24, 2002 for
substantially identical notes registered under the Securities Act of 1933.

On September 30, 2002, we had a $225 million revolving bank credit facility
(with a committed borrowing base of $225 million) which matures in September
2003. As of September 30, 2002, we had no outstanding borrowings under this
facility and were using $25.5 million of the facility to secure various letters
of credit. During November 2002, we increased the credit facility to $250
million (with a committed borrowing base of $225 million). We expect to increase
the borrowing base to $250 million and to extend the term of the credit facility
to June 2005 during the fourth quarter of 2002. 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 $10.0 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 our 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
all our 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 CONSOLIDATING BALANCE SHEET
AS OF SEPTEMBER 30, 2002
($ IN THOUSANDS)

15

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

16

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)

17

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)

18

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)

19

CONDENSED CONSOLIDATING 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 is related
to our exploration and production activities, and the other segment is related
to oil and gas marketing activities. The reportable segment information can be
derived from the condensed consolidating financial statements included in Note
5. The separate results and financial condition of Chesapeake Energy Marketing,
Inc., our wholly owned subsidiary which conducts all our marketing activities,
are reflected in the column captioned "Non-Guarantor Subsidiary."

7. 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 years 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 143 on 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. Our 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 early adopted this standard and it did not have a significant
effect on our results of operations or our financial position.

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 no such activities, thus
we do not believe the impact of the adoption of SFAS No. 146 will be material.

8. SUBSEQUENT EVENT

On November 6, 2002, Chesapeake priced a private offering of $50 million
principal amount of 9.0% senior notes due 2012. The net proceeds are expected to
be approximately $51.3 million. The 9.0% senior notes will be issued as
additional securities under the August 12, 2002 indenture pursuant to which our
outstanding 9.0% senior notes were issued. Closing of the offering is expected
to occur on November 13, 2002, and is subject to satisfaction of customary
closing conditions. The net proceeds from this offering are expected to be used
for repurchase of amounts currently outstanding under our 7.875% senior notes
and under our revolving bank credit facility. The 9.0% senior notes to be issued
will not be registered under the Securities Act of 1933 and may not be offered
or sold in the United States absent registration or an applicable exemption from
registration requirements.

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 SEPTEMBER 30, 2002 ("CURRENT
QUARTER") VS. SEPTEMBER 30, 2001 ("PRIOR QUARTER")

General. For the Current Quarter, Chesapeake had net income available to
common shareholders of $14.1 million, or $0.08 per diluted common share, on
total revenues of $198.2 million. This compares to net income available to
common shareholders of $65.0 million, or $0.38 per diluted common share, on
total revenues of $238.9 million during the Prior Quarter. The Current Quarter's
results included, on a pre-tax basis, a non-cash $7.0 million risk management
loss, a non-cash impairment of $4.8 million representing 100% of the cost we
allocated to common stock warrants of Seven Seas Petroleum Inc. and a $0.5
million loss from repurchases of debt. The Prior Quarter's results included, on
a pre-tax basis, non-cash risk management income of $32.3 million.

Oil and Gas Sales. During the Current Quarter, oil and gas sales decreased
8% to $163.0 million from $177.7 million in the Prior Quarter. For the Current
Quarter, we produced 46.7 billion cubic feet equivalent (bcfe), consisting of
0.9 million barrels of oil (mmbbl) and 41.4 billion cubic feet of gas (bcf),
compared to 0.7 mmbbl and 36.5 bcf, or 40.8 bcfe, in the Prior Quarter. The
production increase is the result of successful drilling results and production
from various acquisitions completed during the Current Quarter partially offset
by the sale of our Canadian reserves effective October 1, 2001. Average oil
prices realized were $25.67 per bbl in the Current Quarter compared to $27.37
per bbl in the Prior Quarter, a decrease of 6%. Average gas prices realized were
$3.39 per thousand cubic feet in the Current Quarter compared to $4.34 per mcf
in the Prior Quarter, a decrease of 22%.

22

For the Current Quarter, we realized an average price of $3.49 per mcfe,
compared to $4.36 per mcfe in the Prior Quarter, including in each case the
effects of hedging. Our hedging activities resulted in increased oil and gas
revenues of $22.2 million, or $0.47 per mcfe, in the Current Quarter, compared
to an increase in oil and gas revenues of $64.4 million, or $1.58 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 $7.0 million
non-cash risk management loss in the Current Quarter, compared to a $32.3
million non-cash gain in the Prior Quarter. The risk management loss for the
Current Quarter consisted of a $10.3 million non-cash gain related to changes in
fair value of derivatives not designated as cash flow hedges and $17.3 million
of reclassifications of gains on the settlement of such contracts. Risk
management income in the Prior Quarter included a $37.7 million non-cash gain
attributable to the change in fair value of derivatives not designated as cash
flow hedges, $6.4 million of reclassifications of gains on the settlement of
such contracts, 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 was also a portion of our interest rate swaps that did 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 $42.2 million in oil and gas
marketing sales for third parties in the Current Quarter, with corresponding oil
and gas marketing expenses of $41.1 million, for a net margin of $1.1 million.
This compares to sales of $28.9 million, expenses of $27.9 million, and a net
margin of $1.0 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 and
sales prices in the Current Quarter compared to the Prior Quarter.

Production Expenses. Production expenses, which include lifting costs and
ad valorem taxes, increased to $25.0 million in the Current Quarter, a $5.7
million increase from the $19.3 million of production expenses incurred in the
Prior Quarter. On a unit of production basis, production expenses were $0.53 and
$0.47 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 2002 and an increase in ad valorem taxes and insurance costs. 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 $6.8 million and $7.1 million in
the Current and Prior Quarters, respectively. On a per unit basis, production
taxes were $0.15 per mcfe in the Current Quarter compared to $0.17 per mcfe in
the Prior Quarter. The decrease in the Current Quarter was the result of the
reinstatement of statutory exemptions on certain wells in Oklahoma, partially
offset by an increase in oil and gas prices. In general,

23

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 $3.8 million in the Current Quarter
compared to $3.2 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 $2.5 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
$58.3 million, compared to $46.8 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 $1.15 in
the Prior Quarter to $1.25 per mcfe in the Current Quarter. We expect the DD&A
rate for the remainder of 2002 to be between $1.25 and $1.30 per mcfe.

Depreciation and Amortization of Other Assets. Depreciation and
amortization of other assets was $3.7 million in the Current Quarter, compared
to $2.2 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 $1.8 million compared to $0.1 million in the Prior Quarter. The
increase was primarily the result of the recognition of a $1.0 million loss in
the Prior Quarter which represented our share of the net loss of RAM Energy,
Inc., and interest income recorded in the Current Quarter on our investment in
senior secured notes issued by Seven Seas Petroleum Inc.

Interest Expense. Interest expense increased to $28.3 million in the
Current Quarter from $24.1 million in the Prior Quarter. The increase in the
Current Quarter was due primarily to a $327 million increase in average
long-term borrowings in the Current Quarter compared to the Prior Quarter,
partially offset by income of $1.1 million earned on our interest rate swaps
during the Current Quarter. In addition to the interest expense reported, we
capitalized $1.3 million of interest during the Current Quarter, compared to
$1.2 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 $1.0 million and $1.5 million.

Other. Chesapeake recorded a non-cash impairment of $4.8 million
representing 100% of the cost allocated to our Seven Seas common stock warrants
and also recorded a $0.5 million loss from the repurchase of debt.

Provision (Benefit) for Income Taxes. Chesapeake recorded income tax
expense of $11.1 million in the Current Quarter, compared to income tax expense
of $43.4 million in the Prior Quarter. We anticipate that all 2002 income tax
expense will be deferred.

24

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

General. For the Current Period, Chesapeake had net income available to
common shareholders of $6.5 million, or $0.04 per diluted common share, on total
revenues of $482.3 million. This compares to net income available to common
shareholders of $174.1 million, or $1.02 per diluted common share, on total
revenues of $792.0 million during the Prior Period. The Current Period's net
income included, on a pre-tax basis, a non-cash $87.0 million risk management
loss, while the Prior Period's results included, on a pre-tax basis, non-cash
risk management income of $94.7 million.

Oil and Gas Sales. During the Current Period, oil and gas sales decreased
20% to $457.0 million from $574.2 million in the Prior Period. For the Current
Period, we produced 132.0 bcfe, consisting of 2.5 mmbbl and 116.8 bcf of gas,
compared to 2.1 mmbbl and 107.6 bcf, or 120.1 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 and 2002 partially offset by the sale of our Canadian reserves effective
October 1, 2001. Average oil prices realized were $25.42 per bbl in the Current
Period compared to $28.03 per bbl in the Prior Period, a decrease of 9%. Average
gas prices realized were $3.36 per mcf in the Current Period compared to $4.79
per mcf in the Prior Period, a decrease of 30%.

For the Current Period, we realized an average price of $3.46 per mcfe,
compared to $4.78 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 $84.1 million, or $0.64 per mcfe, in the Current Period, compared to
increases in oil and gas revenues of $41.1 million, or $0.34 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 89% 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 an $87.0 million
non-cash risk management loss in the Current Period, compared to a $94.7 million
non-cash gain in the Prior Period. The risk management loss for the Current
Period consisted of a $29.9 million non-cash loss related to changes in fair
value of derivatives not designated as cash flow hedges, $53.8 million of
reclassifications of gain on 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, 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 $102.8 million non-cash gain attributable to the change in
fair value of derivatives not designated as cash flow hedges, $10.0 million of
reclassifications of gain on the settlement of such contracts, and a non-cash
gain of $1.9 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 was also a portion of our interest rate swaps that did 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 $112.3 million in oil and gas
marketing sales for third parties in the Current Period, with corresponding oil
and gas marketing expenses of $108.8 million, for a net margin of $3.5 million.
This compares to sales of $123.1 million, expenses of $119.3 million, and a net
margin of $3.8 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 $71.3 million in the Current Period, a $15.4
million increase from the $55.9 million of production expenses incurred in the
Prior Period. On a unit of production basis, production expenses were $0.54 and
$0.47 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 2002 and an increase in ad valorem taxes and insurance costs. 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 $19.9 million and $31.3 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 $0.26 per mcfe in
the Prior Period. The decrease in the Current Period was the result of decreased
prices and the reinstatement of statutory exemptions on certain wells in
Oklahoma. 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 $11.9 million in the Current Period
compared to $10.1 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 $7.8 million and $6.0 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
$157.7 million, compared to $124.9 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 $1.04
in the Prior Period to $1.20 per mcfe in the Current Period. We expect the DD&A
rate for the remainder of 2002 to be between $1.25 and $1.30 per mcfe.

Depreciation and Amortization of Other Assets. Depreciation and
amortization of other assets was $10.5 million in the Current Period, compared
to $6.0 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 $7.3 million compared to $1.4 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 and an increase in interest income
recorded on our investment

26

in senior secured notes issued by Seven Seas Petroleum Inc. The Prior Quarter
included the recognition of a $1.3 million loss, representing our share of the
net loss of RAM Energy, Inc.

Interest Expense. Interest expense increased to $80.0 million in the
Current Period from $73.0 million in the Prior Period. The increase in the
Current Period was due to a $301 million increase in average long-term
borrowings in the Current Period compared to the Prior Period, partially offset
by income of $2.7 million earned on our interest rate swaps during the Current
Period. In addition to the interest expense reported, we capitalized $3.6
million and $3.3 million of interest during the Current Period and Prior Period,
respectively, 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 $1.0 million and $1.5
million.

Gothic Standby Credit Facility Costs. We recognized $3.4 million of costs
incurred for a standby credit facility in the Prior Period in connection with
our acquisition of Gothic Energy Corporation. We did not use the facility which
was obtained and the commitment terminated in February 2001.

Other. Chesapeake recorded a non-cash impairment of $4.8 million
representing 100% of the cost allocated to our Seven Seas common stock warrants
and also recorded a $0.5 million loss from the repurchase of debt.

Provision (Benefit) for Income Taxes. Chesapeake recorded an income tax
expense of $9.4 million in the Current Period, compared to income tax expense of
$148.6 million in the Prior Period. Income tax expense for the Prior Period was
comprised of $141.5 million related to our domestic operations and $7.1 million
related to our Canadian operations which were sold on October 1, 2001. We
anticipate that all 2002 income tax expense will be deferred.

Extraordinary Item. The $46.0 million extraordinary loss in the Prior
Period includes the payment of aggregate make-whole and redemption premiums
related to debt repurchases and redemptions and the write-off of related
unamortized debt issue costs and unamortized debt issue premium.

CASH FLOWS FROM OPERATING, INVESTING, AND FINANCING ACTIVITIES

Cash Flows from Operating Activities. Cash provided by operating activities
decreased 19.8% to $353.7 million during the Current Period compared to $441.0
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 $617.2 million during the Current Period from $454.2 million in the
Prior Period. During the Current Period, we expended approximately $252.8
million to initiate drilling on 517 (204 net) wells and invested approximately
$46.8 million in unproved properties. This compares to $263.7 million to
initiate drilling on 409 (208 net) wells and $51.6 million to purchase unproved
properties in the Prior Period. During the Current Period, we completed
acquisitions of oil and gas companies and properties of $291.4 million and
completed $1.2 million of divestitures of oil and gas properties. This compares
to cash used in acquisitions of oil and gas companies and properties of $75.2
million and proceeds from divestitures of $1.4 million in the Prior Period.
During the Current Period, we had additional investments in drilling rig
equipment and other fixed assets of $29.3 million compared to $28.4 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 $171.3 million of cash
provided by financing activities in the Current Period, compared to cash
provided by financing activities of $30.8 million in the Prior Period. During
the Current Period, we borrowed $95.8 million under our bank credit facility and
made repayments under this facility of $95.8 million. The activity in the
Current Period includes the repurchase of $63.5 million of our 7.875% senior
notes. We received $246.0 million from the issuance of $250 million of 9% senior
notes, $2.1 million in cash from the exercise of stock options, $3.7 million was
used to pay financing cost, and $7.6 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 $164.0 million, $786.7 million received
from the issuance of $800.0 million of 8.125% senior

27

notes, $830.4 million used to redeem various senior notes, $12.3 million was
used for financing cost, and $2.9 million received from the exercise of stock
options.

LIQUIDITY AND CAPITAL RESOURCES

Sources of Liquidity

Chesapeake had a working capital deficit of $70.5 million at September 30,
2002, including $25.4 million in cash. On September 30, 2002, we had a $225
million revolving bank credit facility (with a committed borrowing base of $225
million) which was increased to $250 million (with a committed borrowing base of
$225 million) in November 2002. As of September 30, 2002, we had no outstanding
borrowings under the facility and were using $25.5 million of the facility to
secure various letters of credit. As of November 5, 2002, borrowings under the
credit facility had increased to $62.5 million, largely as a result of
borrowings to fund acquisitions and note purchases which occurred subsequent to
September 30, 2002.

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 fourth quarter of 2002, which is currently estimated to be $90 to $100
million. Based on our current cash flow assumptions, we expect operating cash
flow to be approximately $400 million during 2002. The 2003 budget includes $350
million for exploration and developmental activities and $50 million for
acreage and seismic. Our drilling program is largely discretionary and can be
adjusted to match changing circumstances.

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

On September 30, 2002, we had a $225 million revolving bank credit facility
(with a committed borrowing base of $225 million) which was increased to $250
million (with a committed borrowing base of $225 million) in November 2002. We
expect to increase the borrowing base to $250.0 million and to extend the term
of the credit facility to June 2005 during the fourth quarter of 2002. As of
September 30, 2002, we had no outstanding borrowings under this facility and
were using $25.5 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

28

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.

As of September 30, 2002, senior notes represented $1.5 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 9.0% senior
notes due 2012, $250.0 million principal amount of 8.375% senior notes due 2008,
$86.5 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
$60.8 million is due, giving effect to the repurchase and retirement of $89.2
million of our 7.875% senior notes to date. 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.

The indentures for the 8.125%, 8.375% and 9% 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 September 30, 2002, we
estimate that secured commercial bank indebtedness of approximately $381 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 under the arrangements
exceed certain levels. At September 30, 2002, we posted $24.5 million of
collateral with two of our counterparties through letters of credit secured
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

In the Current Period, we purchased and subsequently retired $63.5 million
of our 7.875% senior notes due 2004 for total consideration of $66.3 million,
including accrued interest of $0.9 million and $1.9 million of redemption
premium. Subsequent to September 30, 2002, we purchased an additional $25.6
million of the 7.875% senior notes for total consideration of $26.8 million,
including $0.2 million in accrued interest and $1.0 million in redemption
premium.

On June 28, 2002, we acquired Canaan Energy Corporation in a cash merger,
adding an estimated 100 bcfe to our proved reserves. The aggregate net cash
consideration for the merger was $120 million, including the retirement of
Canaan's outstanding indebtedness of approximately $43 million.

In July 2002, we filed a shelf registration statement with the Securities
and Exchange Commission that permits us, over time, to sell up to $500 million
of debt securities and common stock, in any combination. Net proceeds, terms and
pricing of the offerings of securities issued under the shelf registration
statement will be determined at the time of the offerings.

29

In July and August 2002, we completed four separate acquisitions of
Mid-Continent oil and gas properties for an aggregate cash purchase price of
$165 million. We estimate these acquisitions added approximately 125 bcfe of
proved reserves. The acquisitions included privately-held Focus Energy, Inc. and
related partnerships, the Mid-Continent assets of publicly-traded EnCana
Corporation, the Mid-Continent assets of OGE Energy Corp. and the Anadarko Basin
assets of The Williams Company.

In August 2002, we issued $250 million principal amount of 9.0% senior
notes due 2012. The net proceeds of this issuance were used to fund the
acquisitions we completed in August 2002, to repay bank debt incurred to pay
the purchase price of acquisitions earlier in the Current Quarter and to
purchase outstanding senior notes.

On September 20, 2002, our board of directors declared a $0.03 per share
dividend on the company's common stock which was paid in October 2002.
Chesapeake has not paid a dividend on its common stock since 1998. The
annualized cost of the common stock dividend will be about $20 million.

In September 2002, we announced our intention to dispose of our Permian
Basin assets, preferably in a transaction involving the exchange of oil and gas
assets in the Mid-Continent for ours in the Permian Basin. The Permian Basin
accounted for approximately 5% of our proved reserves at September 30, 2002 and
2.4 bcfe, or 4%, of our production for the nine months ended September 30, 2002.

On November 6 2002, Chesapeake priced a private offering of $50 million
principal amount of 9.0% senior notes due 2012. The net proceeds are expected to
be approximately $51.3 million. The 9.0% senior notes will be issued as
additional securities under the August 12, 2002 indenture pursuant to which our
outstanding 9.0% senior notes were issued. Closing of the offering is expected
to occur on November 13, 2002, and is subject to satisfaction of customary
closing conditions. The net proceeds from this offering are expected to be used
for repurchase of amounts currently outstanding under our 7.875% senior notes
and under our revolving bank credit facility. The 9.0% senior notes to be issued
will not be registered under the Securities Act of 1933 and may not be offered
or sold in the United States absent registration or an applicable exemption from
registration requirements.

CRITICAL ACCOUNTING POLICIES

We consider certain accounting policies related to hedging, oil and gas
properties, and income taxes to be critical policies. These policies and other
significant accounting policies are summarized in our annual report on Form 10-K
for the year ended December 31, 2001.

RECENTLY ISSUED ACCOUNTING STANDARDS

See Note 7 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 assessments of pending
litigation. 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

30

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.

31

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 September 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, 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.

32

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

- ----------

(a) After adjusting for the $31.1 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 September 30, 2002 was $10.1 million.

33

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
September 30, 2002.

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 ...................... (48,559)
Contracts realized or otherwise settled during the period ............ (84,150)
Fair value of new contracts when entered into during the period ...... (45,603)
---------
Fair value of contracts outstanding at September 30, 2002 ............ $ (21,003)
=========

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 September 30, 2002, we expect to transfer
approximately $6.4 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 September 30, 2002 are expected to mature
by December 31, 2004, with the exception of the basis protection swaps which
extend to 2009.

INTEREST RATE HEDGING

We also utilize hedging strategies to manage interest rate exposure.
Results from interest rate hedging transactions are reflected as adjustments to
interest expense in the corresponding months covered by the derivative
agreement.

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:

At the inception of the interest rate swap agreement, a portion of the
interest rate swap was 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 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. During the Current
Quarter and Current Period, $21.3 million and $63.5 million, respectively, of
the 7.875% senior notes were purchased and subsequently retired. In connection
with the repurchase of the 7.875% senior notes, interest rate swap hedging gains
of $0.4

34

million and $0.9 million were recognized in the Current Quarter and Current
Period, respectively, and reduce the loss on repurchases of debt.

In July 2002, we closed the above interest rate swap for a gain of $7.5
million. As of September 30, 2002, the remaining balance to be amortized as a
reduction to interest expense was $4.1 million. During the Current Period, $2.5
million was recognized as a reduction to interest expense.

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

In July 2002, we closed this interest rate swap for a gain of $1.1 million.
During the Current Quarter, $0.1 million was recognized as a reduction to
interest expense.

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 $20.3
million during the Current Period related to the swaption as of September 30,
2002. Of this amount, $21.4 million represents a decline in the fair value of
the swaption, offset by a loss of $1.1 million from 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 September 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):

35

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
($16.4) million, the value of the interest rate swaps of $1.8 million and
the value of the swaption of ($20.3) million.

36

ITEM 4. CONTROLS AND PROCEDURES

Within the 90-day period prior to the filing of this report, the company
carried out an evaluation, under the supervision and with the participation of
the company's management, including the Chief Executive Officer and Chief
Financial Officer, of the effectiveness of the design and operation of the
company's disclosure controls and procedures (as defined in Rule 13a-14(c) under
the Securities Exchange Act of 1934). Based upon that evaluation, the Chief
Executive Officer and Chief Financial Officer concluded that the company's
disclosure controls and procedures are effective in timely alerting them to
material information relating to the company (including its consolidated
subsidiaries) required to be included in the company's periodic SEC filings.
There have been no significant changes in our internal controls or in other
factors that could significantly affect these controls subsequent to the date of
their evaluation.

37

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

Not applicable

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

4.1.2 Tenth Supplemental Indenture dated as of June 28, 2002
to Indenture dated as of March 15, 1997 among
Chesapeake, as issuer, its subsidiaries signatory
thereto as Subsidiary Guarantors, and The Bank of New
York (formerly United States Trust Company of New York),
as Trustee, with respect to 7.875% Senior Notes due
2004. Incorporated herein by reference to Exhibit 4.1.2
to Chesapeake's registration statement on Form S-4
(No.333-99289).

4.1.3 Eleventh Supplemental Indenture dated as of July 8, 2002
to Indenture dated as of March 15, 1997 among
Chesapeake, as issuer, its subsidiaries signatory
thereto as Subsidiary Guarantors, and The Bank of New
York (formerly United States Trust Company of New York),
as Trustee, with respect to 7.875% Senior Notes due
2004. Incorporated herein by reference to Exhibit 4.1.3
to Chesapeake's registration statement on Form S-4
(No.333-99289).

4.2.2 Tenth Supplemental Indenture dated as of June 28, 2002
to Indenture dated as of March 15, 1997 among
Chesapeake, as issuer, its subsidiaries signatory
thereto as Subsidiary Guarantors, and The Bank of New
York (formerly United States Trust Company of New York),
as Trustee, with respect to 8.5% Senior Notes due 2012.
Incorporated herein by reference to Exhibit 4.2.2 to
Chesapeake's registration statement on Form S-4
(No.333-99289).

38

4.2.3 Eleventh Supplemental Indenture dated as of July 8, 2002
to Indenture dated as of March 15, 1997 among
Chesapeake, as issuer, its subsidiaries signatory
thereto as Subsidiary Guarantors, and The Bank of New
York (formerly United States Trust Company of New York),
as Trustee, with respect to 8.5% Senior Notes due 2012.
Incorporated herein by reference to Exhibit 4.2.3 to
Chesapeake's registration statement on Form S-4
(No.333-99289).

4.3.2 Fifth Supplemental Indenture dated as of June 28, 2002
to Indenture dated as of April 6, 2001 among Chesapeake,
as issuer, its subsidiaries signatory thereto as
Subsidiary Guarantors, and The Bank of New York
(formerly United States Trust Company of New York), as
Trustee, with respect to 8.125% Senior Notes due 2011.
Incorporated herein by reference to Exhibit 4.3.2 to
Chesapeake's registration statement on Form S-4
(No.333-99289).

4.3.3 Sixth Supplemental Indenture dated July 8, 2002 to
Indenture dated as of April 6, 2001 among Chesapeake, as
issuer, its subsidiaries signatory thereto as Subsidiary
Guarantors, and The Bank of New York (formerly United
States Trust Company of New York), as Trustee, with
respect to 8.125% Senior Notes due 2011. Incorporated
herein by reference to Exhibit 4.3.3 to Chesapeake's
registration statement on Form S-4 (No.333-99289).

4.4.2 Second Supplemental Indenture dated as of June 28, 2002
to Indenture dated as of November 5, 2001 among
Chesapeake, as issuer, its subsidiaries signatory
thereto as Subsidiary Guarantors, and The Bank of New
York (formerly United States Trust Company of New York),
as Trustee, with respect to 8.375% Senior Notes due
2008. Incorporated herein by reference to Exhibit 4.4.2
to Chesapeake's registration statement on Form S-4
(No.333-99289).

4.4.3 Third Supplemental Indenture dated as of July 8, 2002 to
Indenture dated as of November 5, 2001 among Chesapeake,
as issuer, its subsidiaries signatory thereto as
Subsidiary Guarantors, and The Bank of New York
(formerly United States Trust Company of New York), as
Trustee, with respect to 8.375% Senior Notes due 2008.
Incorporated herein by reference to Exhibit 4.4.3 to
Chesapeake's registration statement on Form S-4
(No.333-99289).

4.6.2 Consent and waiver letter dated August 2, 2002 with
respect to $225,000,000 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, BNP Parabas and Toronto Dominion (Texas), Inc.,
as Co-Documentation Agents and other lenders party
thereto. Incorporated herein by reference to Exhibit
4.6.2 to Chesapeake's registration statement on Form S-4
(No. 333-99289).

4.6.3 Third Amendment dated September 20, 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.

4.6.4 Fourth Amendment dated November 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.

39

4.14 Indenture dated as of August 12, 2002 among Chesapeake,
as issuer, its subsidiaries signatory thereto, as
Subsidiary Guarantors and The Bank of New York, with
respect to 9% Senior Notes due 2012. Incorporated herein
by reference to Exhibit 4.14 to Chesapeake's
registration statement on Form S-4 (No. 333-99289).

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

21 Subsidiaries of Chesapeake. Incorporated herein by
reference to Exhibit 21 to Chesapeake's registration
statement of Form S-4 (No. 333-99389).

99.1 Aubrey K. McClendon, Chairman and Chief Executive
Officer, Certification Pursuant to 18 U.S.C. Section
1350, As Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.

99.2 Marcus C. Rowland, Executive Vice President and Chief
Financial Officer, Certification Pursuant to 18 U.S.C
Section 1350, As Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K

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

On July 1, 2002, we filed a current report on Form 8-K reporting under Item
5 that we had issued a press release on June 28, 2002 announcing the completion
of our acquisition of Canaan Energy Corporation and the declaration of a
quarterly cash dividend on our preferred stock. Under Item 9, we furnished
Comments of our Chairman and Chief Executive officer regarding the Canaan
acquisition.

On July 11, 2002, we filed a current report on Form 8-K furnishing under
Item 9 that we had issued a press release on July 10, 2002 and furnishing the
dates for our second quarter 2002 earnings release and conference call included
in the press release.

On July 22, 2002, we filed a current report on Form 8-K reporting under
Item 5 that we had announced a significant gas discovery in the Greater Mayfield
area of western Oklahoma's Anadarko Basin. We furnished under Item 9 additional
information on the discovery well and area, a management summary and additional
earnings release and conference call information.

On July 25, 2002, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release on July 25, 2002 announcing second
quarter 2002 earnings and including information on earnings, drilling, recent
and pending acquisitions and the earnings conference call. Under Item 9, we
furnished updated operational and financial guidance for 2002.

On July 30, 2002, we filed a current report on Form 8-K/A, amending the
Form 8-K we filed July 25, 2002, to restate certain disclosures reported under
Item 5 as disclosures under Item 9.

On July 31, 2002, we filed a current report on Form 8-K including as
exhibits under Item 7 consents of reserve engineers.

On August 6, 2002, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release on August 5, 2002 announcing the
commencement of a private offering of $250 million senior notes due 2012 and
stating the expected use of proceeds from the issuance.

On August 7, 2002, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release on August 7, 2002 announcing the
pricing of a private offering of $250 million senior notes due 2012 and stating
the expected use of proceeds from the issuance.

40

On August 8, 2002, we filed a current report on Form 8-K/A amending the
Form 8-K we filed August 7, 2002 to restate the use of proceeds from our
offering of senior notes due 2012.

On August 15, 2002, we filed a current report on Form 8-K furnishing under
Item 9 certifications of our chief executive officer and chief financial officer
required by Section 906 of the Sarbanes-Oxley Act of 2002, which certifications
accompanied our Form 10-Q filed August 5, 2002.

On September 3, 2002, we filed a current report on Form 8-K reporting under
Item 9 that we had issued a press release on September 3, 2002 and furnishing
information from the press release about our 2002 and 2003 hedging positions and
increases in our proved reserves and production as a result of the completion of
recent oil and gas acquisitions.

On September 17, 2002, we filed a current report on Form 8-K reporting
under Item 5 that we had issued a press release on September 17, 2002 announcing
the election of Charles T. Maxwell to our board of directors.

On September 20, 2002, we filed a current report on Form 8-K reporting
under Item 5 that we had issued a press release on September 20, 2002 announcing
that our board of directors had declared quarterly cash dividends on our common
stock and preferred stock and the company's intention to dispose of its Permian
Basin assets. The Form 8-K also furnished under Item 9 related comments of our
chairman and chief executive officer.

41

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: November 7, 2002

42

CERTIFICATION

I, Aubrey K. McClendon, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Chesapeake Energy
Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;

(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
the registrant's board of directors (or persons performing the equivalent
function):

(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 7, 2002
/s/ AUBREY K. MCCLENDON
-----------------------------------------
Aubrey K. McClendon
Chairman and Chief Executive Officer

43

CERTIFICATION

I, Marcus C. Rowland certify that:

1. I have reviewed this quarterly report on Form 10-Q of Chesapeake Energy
Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;

(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
the registrant's board of directors (or persons performing the equivalent
function):

(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 7, 2002
/s/ MARCUS C. ROWLAND
-----------------------------------------
Marcus C. Rowland
Executive Vice President and Chief
Financial Officer

44

INDEX TO EXHIBITS

Incorporated herein by reference to Exhibit 4.4.3 to
Chesapeake's registration statement on Form S-4
(No.333-99289).

4.6.2 Consent and waiver letter dated August 2, 2002 with
respect to $225,000,000 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, BNP Parabas and Toronto Dominion (Texas), Inc.,
as Co-Documentation Agents and other lenders party
thereto. Incorporated herein by reference to Exhibit
4.6.2 to Chesapeake's registration statement on Form S-4
(No. 333-99289).

4.6.3 Third Amendment dated September 20, 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.

4.6.4 Fourth Amendment dated November 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.

4.14 Indenture dated as of August 12, 2002 among Chesapeake,
as issuer, its subsidiaries signatory thereto, as
Subsidiary Guarantors and the Bank of New York, with
respect to its 9% Senior Notes due 2012. Incorporated
herein by reference to Exhibit 4.14 to Chesapeake's
registration statement on Form S-4 (No. 333-99289).

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

21 Subsidiaries of Chesapeake. Incorporated herein by
reference to Exhibit 21 to Chesapeake's registration
statement of Form S-4 (No. 333-99389).

99.1 Aubrey K. McClendon, Chairman and Chief Executive
Officer, Certification Pursuant to 18 U.S.C. Section
1350, As Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.

99.2 Marcus C. Rowland, Executive Vice President and Chief
Financial Officer, Certification Pursuant to 18 U.S.C
Section 1350, As Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.