CHESAPEAKE ENERGY CORP - 10-Q Quarterly Report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2003

¨ 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

incorporation or organization)

(I.R.S. Employer

Identification No.)

6100 North Western Avenue

Oklahoma City, Oklahoma

73118

(Address of principal executive offices)

(Zip Code)

(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 ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). YES x NO ¨

At May 13, 2003, there were 214,039,915 shares of our $.01 par value common stock outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2003

		Page

PART I. Financial Information

Item 1.	Consolidated Financial Statements (Unaudited):

	Consolidated Balance Sheets at March 31, 2003 and December 31, 2002	3

	Consolidated Statements of Operations for the Three Months Ended March 31, 2003 and 2002	4

	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2003 and 2002	5

	Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2003 and 2002	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	27

Item 4.	Controls and Procedures	31

PART II. Other Information

Item 1.	Legal Proceedings	32

Item 2.	Changes in Securities and Use of Proceeds	32

Item 3.	Defaults Upon Senior Securities	32

Item 4.	Submission of Matters to a Vote of Security Holders	32

Item 5.	Other Information	32

Item 6.	Exhibits and Reports on Form 8-K	32

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2003			December 31, 2002
	($ in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	38,004		$	247,637
Restricted cash		333			82
Accounts receivable:
Oil and gas sales		228,797			109,246
Joint interest, net of allowance of $1,432,000 and $1,433,000, respectively		20,943			22,760
Short-term derivatives		622			16,498
Related parties		2,544			2,155
Other		16,064			13,471
Deferred income tax asset		12,304			8,109
Short-term derivative instruments		8,620			—
Inventory and other		14,096			15,359

Total Current Assets		342,327			435,317

PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties		5,282,363			4,334,833
Unevaluated properties		148,282			72,506
Less: accumulated depreciation, depletion and amortization		(2,189,502	)		(2,123,773	)

		3,241,143			2,283,566
Other property and equipment		163,015			154,092
Less: accumulated depreciation and amortization		(50,116	)		(47,774	)

Total Property and Equipment		3,354,042			2,389,884

OTHER ASSETS:
Deferred income tax asset		—			2,071
Long-term derivative instruments		17,319			2,666
Long-term investments		29,075			9,075
Other assets		26,819			36,595

Total Other Assets		73,213			50,407

TOTAL ASSETS	$	3,769,582		$	2,875,608


LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Notes payable and current maturities of long-term debt	$	—		$	—
Accounts payable		97,389			86,001
Accrued interest		50,128			35,025
Derivative payable		7,181			—
Short-term derivative instruments		31,574			33,697
Other accrued liabilities		65,882			56,465
Revenues and royalties due others		88,380			54,364

Total Current Liabilities		340,534			265,552

OTHER LIABILITIES:
Long-term debt, net		1,948,725			1,651,198
Revenues and royalties due others		14,646			13,797
Long-term derivative instruments		—			30,174
Asset retirement obligation		46,438			—
Other liabilities		6,328			7,012
Deferred income taxes payable		40,368			—

Total Other Liabilities		2,056,505			1,702,181

CONTINGENCIES AND COMMITMENTS (Note 3)
STOCKHOLDERS’ EQUITY:
Preferred Stock, $.01 par value, 10,000,000 shares authorized,
6.75% cumulative convertible preferred stock, 2,998,000 issued and outstanding at March 31, 2003 and December 31, 2002, entitled in liquidation to $149.9 million		149,900			149,900
6.00% cumulative convertible preferred stock, 4,600,000 and 0 shares issued and outstanding at March 31, 2003 and December 31, 2002, entitled in liquidation to $230.0 million		230,000			—
Common Stock, $.01 par value, 350,000,000 shares authorized, 218,820,805 and 194,936,912 shares issued at March 31, 2003 and December 31, 2002, respectively		2,188			1,949
Paid-in capital		1,379,051			1,205,554
Accumulated deficit		(365,350	)		(426,085	)
Accumulated other comprehensive loss, net of tax of $708,000 and $2,307,000, respectively		(1,155	)		(3,461	)
Less: treasury stock, at cost; 5,071,571 and 4,792,529 common shares at March 31, 2003 and December 31, 2002, respectively		(22,091	)		(19,982	)

Total Stockholders’ Equity		1,372,543			907,875

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,769,582		$	2,875,608

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	2003			2002
	(in thousands, except per share amounts)
REVENUES:
Oil and gas sales	$	256,332		$	141,971
Risk management income (loss)		27,710			(79,468	)
Oil and gas marketing sales		90,308			27,333

Total Revenues		374,350			89,836

OPERATING COSTS:
Production expenses		31,457			22,060
Production taxes		18,597			5,216
General and administrative		5,665			4,294
Oil and gas marketing expenses		89,358			26,507
Oil and gas depreciation, depletion and amortization		76,614			48,619
Depreciation and amortization of other assets		3,684			3,110

Total Operating Costs		225,375			109,806

INCOME (LOSS) FROM OPERATIONS		148,975			(19,970	)

OTHER INCOME (EXPENSE):
Interest and other income		763			1,545
Interest expense		(35,027	)		(26,960	)
Loss on repurchases of Chesapeake debt		—			(591	)

Total Other Income (Expense)		(34,264	)		(26,006	)

INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		114,711			(45,976	)
Provision (benefit) for income taxes		43,591			(18,390	)

INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		71,120			(27,586	)
Cumulative effect of accounting change, net of applicable income taxes of $1,464,000		2,389			—

NET INCOME (LOSS)		73,509			(27,586	)
Preferred stock dividends		(3,526	)		(2,532	)

NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS	$	69,983		$	(30,118	)


EARNINGS (LOSS) PER COMMON SHARE — BASIC:
Income (loss) before cumulative effect of accounting change	$	0.34		$	(0.18	)
Cumulative effect of accounting change		0.01			—

Net income (loss)	$	0.35		$	(0.18	)


EARNINGS (LOSS) PER COMMON SHARE — ASSUMING DILUTION:
Income (loss) before cumulative effect of accounting change	$	0.31		$	(0.18	)
Cumulative effect of accounting change		0.01			—

Net income (loss)	$	0.32		$	(0.18	)


WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING:
Basic		197,608			165,372

Assuming dilution		230,672			165,372

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2003			2002
	($ in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$	73,509		$	(27,586	)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO NET CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization		78,680			50,526
Risk management (income) loss		(27,710	)		79,468
Deferred income taxes		43,591			(18,390	)
Amortization of loan costs		1,618			1,203
Amortization of bond discount		318			244
Cumulative effect of SFAS 143 implementation		(2,389	)		—
Other		96			447

Cash provided by operating activities before changes in assets and liabilities		167,713			85,912
Changes in assets and liabilities		(68,661	)		31,385

Cash provided by operating activities		99,052			117,297


CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and gas properties		(136,271	)		(75,894	)
Acquisition of unproved oil and gas properties		(95,792	)		(7,387	)
Acquisition of proved oil and gas properties		(741,642	)		(894	)
Sales of oil and gas properties		667			—
Investment in Pioneer Drilling Company		(20,000	)		—
Additions to long-term investments		—			(2,408	)
Proceeds from sale of RAM Energy notes		—			4,215
Other		(9,251	)		(7,591	)

Cash used in investing activities		(1,002,289	)		(89,959	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings		139,000			—
Payments on long-term borrowings		(139,000	)		—
Cash received from issuance of senior notes		297,306			—
Cash paid for issuance costs of senior notes		(6,386	)		—
Proceeds from issuance of preferred stock, net of issuance costs		222,907			—
Proceeds from issuance of common stock, net of issuance costs		177,526			—
Net increase in outstanding payments in excess of cash balances		11,676			—
Cash paid for common stock dividend		(5,705	)		—
Cash paid for preferred stock dividend		(2,530	)		(2,587	)
Cash paid to repurchase senior notes		—			(21,440	)
Cash paid for treasury stock		(2,109	)		—
Cash received from exercise of stock options and warrants		1,514			1,181
Other		(595	)		(134	)

Cash provided by (used in) financing activities		693,604			(22,980	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(209,633	)		4,358
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		247,637			117,594

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	38,004		$	121,952

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended March 31,
	2003			2002
	($ in thousands)
Net income (loss)	$	73,509		$	(27,586	)
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments		(48,555	)		(10,730	)
Reclassification of (gain) loss on settled contracts		50,891			(14,086	)
Ineffective portion of derivatives qualifying for cash flow hedge accounting		(30	)		494

Comprehensive income (loss)	$	75,815		$	(51,908	)

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation and Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying unaudited consolidated financial statements of Chesapeake Energy Corporation and Subsidiaries have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods have been reflected. The results for the three months ended March 31, 2003 are not necessarily indicative of the results to be expected for the full year. This Form 10-Q relates to the three months ended March 31, 2003 (the “Current Quarter”) and the three months ended March 31, 2002 (the “Prior Quarter”).

Stock Options

Chesapeake has elected to follow APB No. 25, Accounting for Stock Issued to Employees and related interpretations in accounting for its employee stock options. Under APB No. 25, compensation expense is recognized for the difference between the option price and market value on the measurement date. In March 2000, the Financial Accounting Standards Board issued FASB Interpretation No. 44 which provided clarification regarding the application of APB No. 25. FIN 44 specifically addressed the accounting consequences of various modifications to the terms of a previously granted fixed–price stock option. Pursuant to FIN 44, we recognized compensation income of $22,600 and compensation expense of $162,500 in the Current Quarter and the Prior Quarter, respectively, as a result of modifications to fixed-price stock options that were made during the years ended December 31, 2001 and 2000. No compensation income or expense has been recognized for stock options issued in 2003 or 2002 because the exercise price of the stock options granted under the plans equaled the market price of the underlying stock on the date of grant and there have been no modification to these options.

Pro forma information applying the fair value method follows:

	Three Months Ended March 31,
	2003			2002
	($ in thousands, except per share amounts)
Net Income (Loss)
As reported ⁽¹⁾	$	73,509		$	(27,586	)
Compensation expense, net of tax		(2,475	)		(2,067	)

Pro forma	$	71,034		$	(29,653	)

Basic earnings (loss) per common share
As reported	$	0.35		$	(0.18	)
Compensation expense, net of tax		(0.01	)		(0.01	)

Pro forma	$	0.34		$	(0.19	)

Diluted earnings (loss) per common share
As reported	$	0.32		$	(0.18	)
Compensation expense, net of tax		(0.01	)		(0.01	)

Pro forma	$	0.31		$	(0.19	)

(1)

Net income includes adjustments related to FIN 44 of $22,600 of income and $162,500 of expense in the Current Quarter and the Prior Quarter, respectively.

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

Critical Accounting Policies

We consider accounting policies related to stock options, hedging, oil and gas properties, income taxes, and business combinations to be critical policies. These policies are summarized in Management’s Discussion and

Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the year ended December 31, 2002, except for our accounting policy related to stock options which is summarized in Note 1 of our annual report on Form 10-K.

2. Financial Instruments and Hedging Activities

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 March 31, 2003, our oil and gas derivative instruments were comprised of swaps, cap-swaps 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, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended.

•

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.

•

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.

•

Basis protection swaps are arrangements that guarantee a price differential of oil or 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 and cap-swap transactions designed to hedge a portion of our oil or natural gas production by entering into a counter-swap instrument. Under the counter-swap we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. To the extent the counter-swap, which does not qualify for hedge accounting under SFAS 133, is designed to lock the value of an existing SFAS 133 cash flow hedge, the net value is frozen and shown as a derivative asset or liability. To the extent the counter-swap is designed to lock the value of an existing SFAS 133 cash flow hedge and both the counter-swap and existing swap are with the same counterparty, 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. The net receivable or payable is frozen until the related month of production and is then recognized as an increase or decrease to oil and gas sales. Changes in fair value occurring after the original swap has been designated as a non-qualifying cash flow hedge under SFAS 133 are included in results of operations. To the extent the counter-swap is designed to lock the value of a non-qualifying cash flow hedge under SFAS 133, the value of the counter-swap is shown as a derivative asset or liability in the consolidated balance sheets and referred to below as a fixed-price counter-swap. Any changes in the fair value of the counter-swap are included in results of operations.

Pursuant to SFAS 133, our cap-swaps, 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 the fair value of qualifying 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 March 31, 2003 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.

	March 31,
	2003			2002
	($ in thousands)

Derivative assets (liabilities):
Fixed-price gas swaps	$	2,701		$	(18,504	)
Fixed-price gas collars		—			7,046
Fixed-price gas cap-swaps		(61,752	)		25,949
Fixed-price gas counter-swaps		55,813			2,239
Fixed-price gas locked swaps		(5,935	)		43,716
Gas basis protection swaps		30,882			(6,222	)
Gas straddles		—			(25,825	)
Gas strangles		—			(31,004	)
Fixed-price crude oil cap-swaps		(2,329	)		(2,286	)
Fixed-price crude oil locked swaps		—			1,404

Estimated fair value	$	19,380		$	(3,487	)(a)

(a)

After adjusting for the $40.9 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 March 31, 2002 was $37.4 million.

Based upon the market prices at March 31, 2003, we expect to transfer approximately $1.2 million of the loss included in the balance in accumulated other comprehensive loss to earnings during the next 12 months when the transactions actually occur. All transactions hedged as of March 31, 2003 are expected to mature by February 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:

	2003			2002
	($ in thousands)
Fair value of contracts outstanding at January 1	$	(14,533	)	$	157,309
Change in fair value of contracts during the quarter		126,771			(69,712	)
Contracts realized or otherwise settled during the quarter		(92,858	)		(48,554	)
Fair value of new contracts when entered into during the quarter		—			(42,530	)

Fair value of contracts outstanding at March 31	$	19,380		$	(3,487	)

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

	Three Months Ended March 31,
	2003		2002
	($ in thousands)
Risk management income (loss):
Change in fair value of derivatives not qualifying for cash flow hedge accounting	$	18,864	$	(53,414	)
Reclassification of (gain) loss on settled contracts		10,775		(25,077	)
Ineffective portion of derivatives qualifying for cash flow hedge accounting		48		(824	)

Total	$	29,687	$	(79,315	)

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 July 2002, we closed an interest rate swap for a gain of $7.5 million. As of March 31, 2003, the remaining balance to be amortized as a reduction to interest expense was $2.1 million. During the Current Quarter, $0.5 million was recognized as a reduction to interest expense.

In July 2002, we closed an additional interest rate swap for a gain of $1.1 million. As of March 31, 2003, the remaining balance to amortize as a reduction to interest expense was $0.7 million. During the Current Quarter, $0.2 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 our 8.50% 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:

Term		Notional Amount		Fixed Rate		Floating Rate
March 2004 – March 2012		$142,665,000		8.500%		U.S. six-month LIBOR plus 75 basis points

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 8.50% 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 8.50% senior notes 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 $18.8 million since the inception of the swaption as of March 31, 2003. Of this amount, $23.8 million represents a decline in the fair value of the swaption, offset by a loss of $5.0 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 March 31, 2003. Results of the interest rate swap, if initiated, will be reflected as adjustments to interest expense in the corresponding months covered by the swaption agreement.

Risk management income (loss) related to our fair value interest rate hedges is comprised of the following:

	Three Months Ended March 31,
	2003			2002
	($ in thousands)
Risk management income (loss):
Change in fair value of derivatives not qualifying for fair value hedge accounting	$	—		$	(153	)
Reclassification of (gain) loss on settled contracts		(527	)		—
Ineffective portion of derivatives qualifying for fair value hedge accounting		(1,450	)		—

Total	$	(1,977	)	$	(153	)

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, fixed-rate debt using primarily quoted market prices. Our carrying amount for such debt at March 31, 2003 and December 31, 2002 was $1,966.9 million and $1,669.3 million, respectively, compared to approximate fair values of $2,067.5 million and $1,744.7 million, respectively. The carrying amount for our 6.75% convertible preferred stock at March 31, 2003 and December 31, 2002 was $149.9 million, with a fair value of $190.7 million and $181.5 million, respectively. The carrying amount of our 6.00% convertible preferred stock was $230.0 million which approximated its fair value as of March 31, 2003.

Concentration of Credit Risk

A significant portion of our liquidity is concentrated in cash and cash equivalents, including restricted cash, and derivative instruments that enable us to hedge a portion of our exposure to price volatility from producing oil

and natural gas. These arrangements expose us to credit risk from our counterparties. Other financial instruments which potentially subject us to concentrations of credit risk consist principally of investments in debt instruments and accounts receivables. Our accounts receivable are primarily from purchasers of oil and natural gas products and exploration and production companies which own interests in properties we operate. The industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. Cash and cash equivalents are deposited with major banks or institutions and may at times exceed the federally insured limits.

3. Contingencies and Commitments

Royalty Owner Litigation. Royalty owners have commenced litigation against a number of oil and gas producers claiming that amounts paid for production attributable to the royalty owners’ interest violated the terms of applicable leases and state law, that deductions from the proceeds of oil and gas production were unauthorized under the leases, and that amounts received by upstream sellers should be used to compute the amounts paid to the royalty owners. Typically this litigation has taken the form of class action suits. There are presently four such suits filed against Chesapeake, two in Texas and two in Oklahoma. No class has been certified in any of them. In one of the Oklahoma cases, we determined that a portion of the marketing fee we had charged royalty owners should be refunded. We have deposited with the court the aggregate amount of the fees we estimated should be refunded, $3.6 million, in an interest-bearing account for distribution to affected royalty owners. This amount was charged to general and administrative expenses, of which $0.3 million was charged in the Current Quarter. We do not believe any other claims made by royalty owners in the cases pending against us are valid. Even if the claims were upheld, we believe any damages awarded would not be material. This is a developing area of the law, however, and as new cases are decided our potential liability relating to the marketing of oil and gas may increase or decrease. We will continue to monitor 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 our consolidated financial position or results of operations.

Chesapeake has employment agreements with its chief executive officer, chief operating officer, chief financial officer and various other senior management personnel, which provide for annual base salaries, bonus compensation and various benefits. The agreements provide for the continuation of salary and benefits for varying terms in the event of termination of employment without cause. The agreements with the chief executive officer and chief operating officer have terms of five years commencing July 1, 2002. The term of each agreement is automatically extended for one additional year on each June 30 unless one of the parties provides 30 days notice of non-extension. The agreements with the chief financial officer and other senior managers expire on June 30, 2006. The employment agreements with the chief executive officer and chief operating officer provide that in the event of a change in control, under some circumstances, each is entitled to receive a payment in the amount of five times his base compensation and the prior year’s benefits, plus a tax gross-up payment.

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

4. Net Income (Loss) Per Share

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

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

•

For the quarters ended March 31, 2003 and 2002, outstanding warrants to purchase 0.4 million and 1.1 million shares of common stock at a weighted-average exercise price of $14.55 and $12.61 were

antidilutive because the exercise prices of the warrants were greater than the average market price of the common stock.

•

For the quarters ended March 31, 2003 and 2002, outstanding options to purchase 0.4 million and 0.8 million shares of common stock at a weighted-average exercise price of $14.84 and $10.05, respectively, were antidilutive because the exercise prices of the options were greater than the average market price of the common stock.

•

As a result of the Prior Quarter’s net loss to common shareholders, the diluted shares do not include the effect of outstanding stock options to purchase 5.2 million shares of common stock at a weighted-average exercise price of $3.81, the assumed conversion of the outstanding 6.75% preferred stock (convertible into 19.5 million common shares), or warrants to purchase 6,567 shares of common stock at a weighted-average exercise price of $0.05 as the effects were antidilutive.

A reconciliation for the quarter ended March 31, 2003 is as follows:

	Income (Numerator)		Shares (Denominator)	Per Share Amount
	(in thousands, except per share data)
For the Quarter Ended March 31, 2003:
Basic EPS
Income available to common shareholders	$	69,983	197,608	$	0.35

Effect of Dilutive Securities
Assumed conversion at the beginning of the period of preferred shares outstanding during the period:
Preferred dividends		3,526	—
Common shares assumed issued for 6.00% preferred stock		—	6,707
Common shares assumed issued for 6.75% preferred stock		—	19,468
Employee stock options		—	6,889

Diluted EPS
Income available to common shareholders and assumed conversions	$	73,509	230,672	$	0.32

5. Senior Notes and Revolving Credit Facility

At March 31, 2003, our long-term debt consisted of the following ($ in thousands):

7.875% senior notes, due 2004	$	42,137	⁽¹⁾
8.375% senior notes, due 2008		250,000
8.125% senior notes, due 2011		800,000
8.500% senior notes, due 2012		142,665
9.000% senior notes, due 2012		300,000
7.500% senior notes, due 2013		300,000
7.750% senior notes, due 2015		150,000
Revolving bank credit facility		—
Discount on senior notes		(17,858	)
Discount for interest rate swaps and swaption		(18,219	)

Total	$	1,948,725

⁽¹⁾This amount has been classified as long-term debt based on our ability to satisfy this obligation with funding from our credit facility.

On March 5, 2003, we issued $300.0 million principal amount of 7.50% senior notes due 2013, which have not been registered under the Securities Act of 1933.

On December 20, 2002, we issued $150.0 million principal amount of 7.75% senior notes due 2015, which were exchanged on February 20, 2003 for substantially identical notes registered under the Securities Act of 1933.

On August 12, 2002, we issued $250.0 million principal amount of 9.00% senior notes due 2012, which were exchanged on October 24, 2002 for substantially identical notes registered under the Securities Act of 1933. In a private offering on November 14, 2002 we issued an additional $50.0 million principal amount of 9.00% senior notes due 2012 which were exchanged on February 20, 2003 for substantially identical notes registered under the Securities Act of 1933.

On March 31, 2003, we had a $250 million revolving bank credit facility (with a committed borrowing base of $250 million) which matures in June 2005. As of March 31, 2003, we had no outstanding borrowings under this facility and were using $15.4 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 agreement contains various covenants and restrictive provisions which limit 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 agreement 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 for the trailing twelve month period of at least 2.5 to 1. At March 31, 2003, our current ratio was 1.7 to 1 and our fixed charge coverage ratio was 2.8 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 agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $5.0 million.

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; 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. We may redeem the senior notes at any time at specified make-whole or redemption prices as provided in the indentures.

Chesapeake is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding 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 parent, guarantor subsidiaries and Chesapeake Energy Marketing, Inc., a wholly owned subsidiary 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.

CONDENSED CONSOLIDATED BALANCE SHEET

AS OF MARCH 31, 2003

($ in thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiary			Parent			Eliminations			Consolidated

ASSETS

CURRENT ASSETS:
Cash and cash equivalents, including restricted cash	$	1,079		$	36,908		$	350		$	—		$	38,337
Accounts receivable		224,226			142,469			3,525			(101,872	)		268,348
Short-term derivative receivable		622			—			—			—			622
Short-term derivative instruments		8,620			—			—			—			8,620
Deferred income tax asset		—			—			12,304			—			12,304
Inventory and other		12,984			1,097			15			—			14,096

Total Current Assets		247,531			180,474			16,194			(101,872	)		342,327

PROPERTY AND EQUIPMENT:
Oil and gas properties		5,282,363			—			—			—			5,282,363
Unevaluated leasehold		148,282			—			—			—			148,282
Other property and equipment		65,779			32,156			65,080			—			163,015
Less: accumulated depreciation, depletion and Amortization		(2,213,754	)		(21,314	)		(4,550	)		—			(2,239,618	)

Net Property and Equipment		3,282,670			10,842			60,530			—			3,354,042

OTHER ASSETS:
Investments in subsidiaries and intercompany advances		—			—			469,204			(469,204	)		—
Long-term notes receivable		—			12			—			(12	)		—
Long-term derivative instruments		17,319			—			—			—			17,319
Long-term investments		—			—			29,075			—			29,075
Other assets		4,525			—			22,294			—			26,819

Total Other Assets		21,844			12			520,573			(469,216	)		73,213

TOTAL ASSETS	$	3,552,045		$	191,328		$	597,297		$	(571,088	)	$	3,769,582


LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Notes payable and current maturity of long-term debt	$	—		$	—		$	—		$	—		$	—
Accounts payable		93,172			150,291			—			(146,074	)		97,389
Accrued interest		—			—			50,128			—			50,128
Accrued liabilities		50,492			2,532			12,870			(12	)		65,882
Short-term derivative instruments		—			—			31,574			—			31,574
Derivative payable		7,181			—			—			—			7,181
Revenues and royalties due others		44,178			—			—			44,202			88,380

Total Current Liabilities		195,023			152,823			94,572			(101,884	)		340,534

OTHER LIABILITIES:
Long-term debt		—			—			1,948,725			—			1,948,725
Revenues and royalties due others		14,646			—			—			—			14,646
Asset retirement obligation		46,438			—			—			—			46,438
Deferred income tax liability (asset)		132,193			1,917			(93,742	)		—			40,368
Other liabilities		5,002			1,326			—			—			6,328
Intercompany payables (receivables)		2,726,213			(1,412	)		(2,724,801	)		—			—

Total Other Liabilities		2,924,492			1,831			(869,818	)		—			2,056,505

STOCKHOLDERS’ EQUITY:
Common stock		56			1			2,188			(57	)		2,188
Preferred stock		—			—			379,900			—			379,900
Other		432,474			36,673			990,455			(469,147	)		990,455

Total Stockholders’ Equity		432,530			36,674			1,372,543			(469,204	)		1,372,543

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,552,045		$	191,328		$	597,297		$	(571,088	)	$	3,769,582

CONDENSED CONSOLIDATED BALANCE SHEET

AS OF DECEMBER 31, 2002

($ in thousands)

	Guarantor Subsidiary			Non- Guarantor Subsidiary			Parent			Eliminations			Consolidated

ASSETS

CURRENT ASSETS:
Cash and cash equivalents, including restricted cash	$	(31,893	)	$	24,448		$	255,164		$	—		$	247,719
Accounts receivable		122,074			69,362			3,006			(46,810	)		147,632
Short-term derivative instruments		16,498			—			—			—			16,498
Deferred income tax asset		—			—			8,109			—			8,109
Inventory and other		14,202			1,157			—			—			15,359

Total Current Assets		120,881			94,967			266,279			(46,810	)		435,317

PROPERTY AND EQUIPMENT:
Oil and gas properties		4,334,833			—			—			—			4,334,833
Unevaluated leasehold		72,506			—			—			—			72,506
Other property and equipment		64,475			30,818			58,799			—			154,092
Less: accumulated depreciation, depletion and amortization		(2,146,538	)		(20,789	)		(4,220	)		—			(2,171,547	)

Net Property and Equipment		2,325,276			10,029			54,579			—			2,389,884

OTHER ASSETS:
Investments in subsidiaries and intercompany advances		—			—			357,698			(357,698	)		—
Deferred income tax asset (liability)		(124,455	)		(1,941	)		128,467			—			2,071
Long-term derivative instruments		2,666			—			—			—			2,666
Long-term investments		—			—			9,075			—			9,075
Other assets		20,246			57			16,349			(57	)		36,595

Total Other Assets		(101,543	)		(1,884	)		511,589			(357,755	)		50,407

TOTAL ASSETS	$	2,344,614		$	103,112		$	832,447		$	(404,565	)	$	2,875,608


LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	82,083		$	71,316		$	—		$	(67,398	)	$	86,001
Accrued interest		—			—			35,025			—			35,025
Accrued liabilities		46,231			1,960			8,326			(52	)		56,465
Short-term derivative instruments		33,697			—			—			—			33,697
Revenues and royalties due others		33,776			—			—			20,588			54,364

Total Current Liabilities		195,787			73,276			43,351			(46,862	)		265,552

OTHER LIABILITIES:
Long-term debt		—			—			1,651,198			—			1,651,198
Revenues and royalties due others		13,797			—			—			—			13,797
Long-term derivative instruments		—			—			30,174			—			30,174
Other liabilities		5,687			1,325			—			—			7,012
Intercompany payables (receivable)		1,801,833			(1,677	)		(1,800,151	)		(5	)		—

Total Other Liabilities		1,821,317			(352	)		(118,779	)		(5	)		1,702,181

STOCKHOLDERS’ EQUITY:
Common stock		56			1			1,949			(57	)		1,949
Preferred stock		—			—			149,900			—			149,900
Other		327,454			30,187			756,026			(357,641	)		756,026

Total Stockholders’ Equity		327,510			30,188			907,875			(357,698	)		907,875

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,344,614		$	103,112		$	832,447		$	(404,565	)	$	2,875,608

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

($ in thousands)

	Guarantor Subsidiaries			Non- Guarantor Subsidiary			Parent			Eliminations			Consolidated
For the Three Months Ended March 31, 2003:
REVENUES:
Oil and gas sales	$	256,332		$	—		$	—		$	—		$	256,332
Risk management income (loss)		29,687			—			(1,977	)		—			27,710
Oil and gas marketing sales		—			294,151			—			(203,843	)		90,308

Total Revenues		286,019			294,151			(1,977	)		(203,843	)		374,350

OPERATING COSTS:
Production expenses		31,457			—			—			—			31,457
Production taxes		18,597			—			—			—			18,597
General and administrative		4,947			583			135			—			5,665
Oil and gas marketing expenses		—			293,201			—			(203,843	)		89,358
Oil and gas depreciation, depletion and amortization		76,614			—			—			—			76,614
Depreciation and amortization of other assets		2,298			525			861			—			3,684

Total Operating Costs		133,913			294,309			996			(203,843	)		225,375

INCOME (LOSS) FROM OPERATIONS		152,106			(158	)		(2,973	)		—			148,975

OTHER INCOME (EXPENSE):
Interest and other income		18			94			35,665			(35,014	)		763
Interest expense		(33,834	)		—			(36,207	)		35,014			(35,027	)
Equity in net earnings of subsidiaries		—			—			75,688			(75,688	)		—

Total Other Income (Expense)		(33,816	)		94			75,146			(75,688	)		(34,264	)

INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		118,290			(64	)		72,173			(75,688	)		114,711
Income tax expense (benefit)		44,951			(24	)		(1,336	)		—			43,591

INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		73,339			(40	)		73,509			(75,688	)		71,120
Cumulative effect of accounting change, net of tax		2,389			—			—			—			2,389

NET INCOME (LOSS)	$	75,728		$	(40	)	$	73,509		$	(75,688	)	$	73,509


	Guarantor Subsidiaries			Non- Guarantor Subsidiary			Parent			Eliminations			Consolidated
For the Three Months Ended March 31, 2002:
REVENUES:
Oil and gas sales	$	141,971		$	—		$	—		$	—		$	141,971
Risk management loss		(79,315	)		—			(153	)		—			(79,468	)
Oil and gas marketing sales		—			89,465			—			(62,132	)		27,333

Total Revenues		62,656			89,465			(153	)		(62,132	)		89,836

OPERATING COSTS:
Production expenses		22,060			—			—			—			22,060
Production taxes		5,216			—			—			—			5,216
General and administrative		3,630			451			213			—			4,294
Oil and gas marketing expenses		—			88,639			—			(62,132	)		26,507
Oil and gas depreciation, depletion and amortization		48,619			—			—			—			48,619
Other depreciation and amortization		2,171			277			662			—			3,110

Total Operating Costs		81,696			89,367			875			(62,132	)		109,806

INCOME (LOSS) FROM OPERATIONS		(19,040	)		98			(1,028	)		—			(19,970	)

OTHER INCOME (EXPENSE):
Interest and other income		209			99			28,115			(27,469	)		954
Interest expense		(26,569	)		—			(27,860	)		27,469			(26,960	)
Equity in net earnings of subsidiaries		—			—			(27,122	)		27,122			—

Total Other Income (Expense)		(26,360	)		99			(26,867	)		27,122			(26,006	)

INCOME (LOSS) BEFORE INCOME TAXES		(45,400	)		197			(27,895	)		27,122			(45,976	)
Income tax expense (benefit)		(18,160	)		79			(309	)		—			(18,390	)

NET INCOME (LOSS)	$	(27,240	)	$	118		$	(27,586	)	$	27,122		$	(27,586	)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

($ in thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiary			Parent			Eliminations			Consolidated
For the Three Months Ended March 31, 2003:
CASH FLOWS FROM OPERATING ACTIVITIES	$	236,904		$	(150,974	)	$	88,810		$	(75,688	)	$	99,052


CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net		(192,369	)		—			(780,669	)		—			(973,038	)
Investment in Pioneer Drilling Company		—			—			(20,000	)		—			(20,000	)
Other		(1,633	)		(1,338	)		(6,280	)		—			(9,251	)

Cash (used in) provided by investing activities		(194,002	)		(1,338	)		(806,949	)		—			(1,002,289	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving bank credit facility		139,000			—			—			—			139,000
Payments on revolving bank credit facility		(139,000	)		—			—			—			(139,000	)
Net increase in outstanding payments in excess of cash balances		11,676			—			—			—			11,676
Cash received from issuance of senior notes		—			—			297,306			—			297,306
Cash paid for issuance costs of senior notes		—			—			(6,386	)		—			(6,386	)
Cash paid for treasury stocks		—			—			(2,109	)		—			(2,109	)
Proceeds from issuance of common stock, net of issuance costs		—			—			177,526			—			177,526
Proceeds from issuance of preferred stock, net of issuance costs		—			—			222,907			—			222,907
Cash dividends paid on preferred stock and common stock		—			—			(8,235	)		—			(8,235	)
Exercise of stock options and warrants		—			—			1,514			—			1,514
Other		(373	)		—			(222	)		—			(595	)
Intercompany advances, net		(21,233	)		164,772			(219,227	)		75,688			—

Cash provided by (used in) financing activities		(9,930	)		164,772			463,074			75,688			693,604

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		32,972			12,460			(255,065	)		—			(209,633	)
CASH, BEGINNING OF PERIOD		(31,975	)		24,448			255,164			—			247,637

CASH, END OF PERIOD	$	997		$	36,908		$	99		$	—		$	38,004


	Guarantor Subsidiaries			Non-Guarantor Subsidiary			Parent			Eliminations			Consolidated
For the Three Months Ended March 31, 2002:
CASH FLOWS FROM OPERATING ACTIVITIES	$	107,118		$	(7,847	)	$	(9,096	)	$	27,122		$	117,297


CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net		(84,175	)		—			—			—			(84,175	)
Additions to other property, plant and equipment and other		(2,020	)		(268	)		(5,303	)		—			(7,591	)
Other investments, net		—			—			1,807			—			1,807

Cash (used in) provided by investing activities		(86,195	)		(268	)		(3,496	)		—			(89,959	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid for repurchase of senior notes		—			—			(21,440	)		—			(21,440	)
Cash dividends paid on preferred stock		—			—			(2,587	)		—			(2,587	)
Exercise of stock options		—			—			1,181			—			1,181
Other		—			—			(134	)		—			(134	)
Intercompany advances, net		(38,654	)		(1,463	)		67,239			(27,122	)		—

Cash (used in) provided by financing activities		(38,654	)		(1,463	)		44,259			(27,122	)		(22,980	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(17,731	)		(9,578	)		31,667			—			4,358
CASH, BEGINNING OF PERIOD		(11,313	)		19,714			109,193			—			117,594

CASH, END OF PERIOD	$	(29,044	)	$	10,136		$	140,860		$	—		$	121,952

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

($ in thousands)

	Guarantor Subsidiaries			Non-Guarantor Subsidiary			Parent			Eliminations			Consolidated
For the Three Months Ended March 31, 2003:
Net income (loss)	$	75,728		$	(40	)	$	73,509		$	(75,688	)	$	73,509
Other comprehensive income (loss)—net of income tax:
Change in fair value of derivative instruments		(48,555	)		—			—			—			(48,555	)
Reclassification of loss on settled contracts		50,891			—			—			—			50,891
Ineffectiveness portion of derivatives qualifying for cash flow hedge accounting		(30	)		—			—			—			(30	)
Equity in net other comprehensive income (loss) of subsidiaries		—			—			2,306			(2,306	)		—

Comprehensive income (loss)	$	78,034		$	(40	)	$	75,815		$	(77,994	)	$	75,815


	Guarantor Subsidiaries			Non-Guarantor Subsidiary			Parent			Eliminations			Consolidated
For the Three Months Ended March 31, 2002:
Net income (loss)	$	(27,240	)	$	118		$	(27,586	)	$	27,122		$	(27,586	)
Other comprehensive income (loss)—net of income tax:
Change in fair value of derivative instruments		(10,730	)		—			—			—			(10,730	)
Reclassification of gain on settled contracts		(14,086	)		—			—			—			(14,086	)
Ineffectiveness portion of derivatives qualifying for cash flow hedge accounting		494			—			—			—			494
Equity in net other comprehensive income (loss) of subsidiaries		—			—			(24,322	)		24,322			—

Comprehensive income (loss)	$	(51,562	)	$	118		$	(51,908	)	$	51,444		$	(51,908	)

6. Segment Information

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

7. Recent Accounting Pronouncements

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS 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 depleted wells) in the period in which the liability is incurred (at the time the wells are drilled or acquired). In the Current Quarter, we have recorded a $30.5 million liability and a cumulative effect for the change in accounting principle as an increase to earnings of $2.4 million (net of income taxes) and an increase in net oil and gas properties of $34.3 million. We do not expect this standard to have a material impact on our financial position or results of operations in future periods.

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 145 is effective for fiscal years beginning after May 15, 2002. We adopted this standard in 2002, and it did not have a significant effect on our results of operations or our financial position in 2002 or in the Current Quarter.

In July 2002, the FASB issued SFAS No. 146, Accounting For Costs Associated with Exit or Disposal Activities. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002. We adopted this standard in the Current Quarter and it did not have any impact on our financial position or results of operations.

On December 31, 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure – An Amendment of SFAS 123. The standard provides additional transition guidance for companies that elect to voluntarily adopt the accounting provisions of SFAS 123, Accounting for Stock-Based Compensation. SFAS 148 does not change the provisions of SFAS 123 that permit entities to continue to apply the intrinsic value method of APB 25, Accounting for Stock Issued to Employees. As we continue to follow APB 25, our accounting for stock-based compensation will not change as a result of SFAS 148. SFAS 148 does require certain new disclosures in both annual and interim financial statements. The required disclosures have been included in our 2002 annual report and Current Quarter consolidated financial statements.

In November 2002, the FASB issued FASB Interpretation, or FIN 45 Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantee of Indebtedness of Others. FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. FIN 45’s provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The guarantor’s previous accounting for guarantees that were issued before the date of FIN 45’s initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of the Interpretation. The disclosure requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. Chesapeake is not a guarantor under any significant guarantees and thus this interpretation did not have a significant effect on the company’s financial position or results of operations in 2002 or in the Current Quarter.

On January 17, 2003, the FASB issued FIN 46, Consolidation of Variable Interest Entities, An Interpretation of ARB 51. The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities or VIEs) and how to determine when and which business enterprise should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. We do not expect the adoption of this standard to have any impact on our financial position or results of operations.

In March 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 is effective for contracts entered into or modified after June 30, 2003. This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. We do not expect the adoption of this standard to have any significant impact on our financial position or results of operations.

8. Asset Retirement Obligations

Effective January 1, 2003, Chesapeake adopted SFAS No. 143, Accounting for Asset Retirement Obligations. This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets.

SFAS 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and gas properties, this is the period in which an oil or gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of the asset at its discounted fair value. The liability is then accreted each period until the liability is settled or the asset is sold, at which time the liability is reversed and any gain or loss resulting from the settlement of the obligation is recorded.

We identified and estimated all of our asset retirement obligations for tangible, long-lived assets as of January 1, 2003. These obligations were for plugging and abandonment costs for depleted oil and gas wells. Prior to the adoption of SFAS 143, we included an estimate of our asset retirement obligations related to our oil and gas properties in our calculation of oil and gas depreciation, depletion and amortization expense. Upon adoption of SFAS 143, we recorded the discounted fair value of our expected future obligations. The cumulative effect of the change in accounting standard was a $2.4 million after-tax gain which was recorded in the consolidated statement of operations for the Current Quarter. Had SFAS 143 been adopted as of January 1, 2002, Chesapeake’s Prior Quarter net income would have increased by $0.2 million and there would have been no effect to the reported earnings per share.

The components of the change in our asset retirement obligations are shown below. Information for the Prior Quarter is shown on a pro forma basis.

	Three Months Ended March 31,
	2003		2002
	($ in thousands)
Asset retirement obligations, beginning of the quarter	$	30,479	$	23,051
Additions and revisions		15,297		405
Settlements and disposals		—		—
Accretion expense		662		435

Asset retirement obligations, end of the quarter	$	46,438	$	23,891

9. Acquisitions and Related Financing

We completed an acquisition of Mid-Continent gas assets from a wholly-owned subsidiary of ONEOK, Inc. in January 2003 for $296 million, $15 million of which was paid in 2002. In March 2003, we acquired El Paso Corporation’s Anadarko Basin assets in western Oklahoma and the Texas Panhandle for $500 million and Vintage Petroleum, Inc.’s assets in the Bray Field in southern Oklahoma for $29 million.

On March 5, 2003, we issued 23 million shares of common stock pursuant to a shelf registration statement for net proceeds of $177.5 million. We also issued 4.6 million shares of 6.00% cumulative convertible preferred stock with a liquidation value of $230 million. The net proceeds from the preferred stock were $222.9 million. These proceeds, along with the net proceeds of $290.9 million from the issuance of the $300 million in aggregate principal amount of 7.50% senior notes issued at the same time, were used to fund acquisitions completed in March 2003 and to repay credit facility indebtedness. Each share of the 6% preferred stock is convertible at any time at the option of the holder into 4.8605 shares of our common stock, subject to adjustment. At March 31, 2003, 41,825,848 shares of our common stock were reserved for issuance upon conversion of the 6.00% and 6.75% cumulative convertible preferred stock.

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:

	Three Months Ended March 31,
	2003		2002
Net Production:
Oil (mbbl)		1,060		830
Gas (mmcf)		50,392		36,933
Gas equivalent (mmcfe)		56,752		41,913
Oil and Gas Sales ($ in thousands):
Oil	$	28,902	$	19,958
Gas		227,430		122,013

Total oil and gas sales	$	256,332	$	141,971


Average Sales Price:
Oil ($ per bbl)	$	27.27	$	24.05
Gas ($ per mcf)	$	4.51	$	3.30
Gas equivalent ($ per mcfe)	$	4.52	$	3.39
Expenses ($ per mcfe):
Production expenses and taxes	$	0.88	$	0.65
General and administrative	$	0.10	$	0.10
Depreciation, depletion and amortization	$	1.35	$	1.16

Net Wells Drilled		94		57

Net Producing Wells at End of Period		5,326		3,620

Significant Developments During Current Quarter

We completed an acquisition of Mid-Continent gas assets from a wholly-owned subsidiary of ONEOK, Inc. in January 2003. We paid $296 million in cash for these assets, $15 million of which was paid in late 2002.

Also on March 5, 2003, we closed a private offering of $300 million in aggregate principal amount of 7.50% senior notes due 2013. The net proceeds were $290.9 million. These proceeds, along with the net proceeds from the common stock and preferred stock offerings, were used to fund acquisitions completed in March 2003 and to repay credit facility indebtedness.

On March 13, 2003, we acquired El Paso Corporation’s Anadarko Basin assets in western Oklahoma and the Texas Panhandle for $500 million.

On March 31, 2003, we acquired Vintage Petroleum Inc.’s assets in the Bray Field in southern Oklahoma for $29 million.

Results of Operations — Three Months Ended March 31, 2003 (“Current Quarter”) vs. March 31, 2002 (“Prior Quarter”)

General. For the Current Quarter, Chesapeake had net income of $73.5 million, or $0.32 per diluted common share, on total revenues of $374.4 million. This compares to a net loss of $27.6 million, or $0.18 per diluted common share, on total revenues of $89.8 million during the Prior Quarter. The Current Quarter net income includes, on a pre-tax basis, $27.7 million in risk management income. The Prior Quarter net loss included, on a pre-tax basis, $79.5 million in risk management loss. The Current Quarter also includes a $2.4 million after tax gain relate to a change in accounting standard.

Oil and Gas Sales. During the Current Quarter, oil and gas sales were $256.3 million versus $142.0 million in the Prior Quarter. Chesapeake produced 56.8 bcfe during the Current Quarter and 41.9 bcfe in the Prior Quarter. The weighted-average prices, inclusive of

hedging effects were $4.52 per mcfe in the Current Quarter and $3.39 per mcfe in the Prior Quarter. Before hedging effects, Chesapeake received a weighted-average price of $6.16 per mcfe in the Current Quarter, compared to $2.23 per mcfe in the Prior Quarter. The increase in prices in the Current Quarter resulted in an increase in revenue of $64 million along with an increase of $50 million due to increased production, for a net increase in revenues of $114 million. The change in oil and gas prices has a significant impact on our oil and gas revenues and cash flows. Assuming the Current Quarter production levels, a change of $.10 per mcf of natural gas would result in a quarterly increase/decrease in revenues and cash flow of approximately $5.0 million and $4.7 million, respectively, and a change of $1.00 per barrel of oil would result in a quarterly increase/decrease in revenues and cash flows of approximately $1.1 million and $1.0 million, respectively, without considering the effect of hedging activities.

For the Current Quarter, we realized an average price per barrel of oil of $27.27, compared to $24.05 in the Prior Quarter. Natural gas prices realized per mcf were $4.51 and $3.30 in the Current Quarter and Prior Quarter, respectively. Our hedging activities resulted in a decrease in oil and gas revenues of $92.9 million, or $1.64 per mcfe, in the Current Quarter compared to an increase of $48.6 million, or $1.16 per mcfe, in the Prior Quarter.

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

	For the Three Months Ended March 31,
	2003			2002
Operating Areas	(Mmcfe)	Percent		(Mmcfe)	Percent
Mid-Continent	48,781	86	%	31,793	76	%
Gulf Coast	5,348	9		7,261	17
Permian Basin	1,849	3		2,064	5
Williston Basin and Other	774	2		795	2

Total Production	56,752	100	%	41,913	100	%

Natural gas production represented approximately 89% of our total production volume on an equivalent basis in the Current Quarter, compared to 88% in the Prior Quarter.

Risk Management Income (Loss). Chesapeake recognized $27.7 million of risk management income in the Current Quarter compared to $79.5 million of risk management loss in the Prior Quarter. Risk management income for the Current Quarter consisted of gains of $18.9 million related to changes in the fair value of derivatives not qualifying as cash flow hedges, $10.7 million of reclassifications of losses on the settlement of such contracts and a $0.1 million gain associated with the ineffective portion of derivatives qualifying for cash flow hedge accounting. It also included $0.5 million related to reclassifications of gains realized on the settlement of interest rate swaps to interest expense and a $1.5 million loss associated with the ineffective portion of our swaption. Risk management loss for the Prior Quarter consisted of a loss of $53.4 million related to changes in the fair value of derivatives not designated as cash flow hedges, $25.1 million of reclassifications of gains related to the settlement of such contracts, $0.8 million associated with the ineffective portion of derivatives qualifying for cash flow hedge accounting and $0.2 million loss associated with the portion of our interest rate swap that did not qualify for fair value hedge accounting.

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

Oil and Gas Marketing Sales. Chesapeake realized $90.3 million in oil and gas marketing sales for third parties in the Current Quarter, with corresponding oil and gas marketing expenses of $89.4 million, for a net margin of $0.9 million. This compares to sales of $27.3 million, expenses of $26.5 million, and a net margin of $0.8 million in the Prior Quarter. The increased activity in the Current Quarter is primarily the result of higher prices received in the Current Quarter combined with an increase in volumes resulting from acquisitions that occurred in 2002 and the Current Quarter.

Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $31.5 million in the Current Quarter, a $9.4 million increase from the $22.1 million of production expenses incurred in the Prior Quarter. On a unit of production basis, production expenses were $0.55 and $0.53 per mcfe in the Current and Prior Quarters, respectively. The increase in costs on a per unit basis in 2003 compared to 2002 is due primarily to increased field service costs and higher production costs associated with properties acquired in 2002. We expect that production expenses per mcfe produced for the remainder of 2003 will range from $0.53 to $0.57.

Production Taxes. Production taxes were $18.6 million and $5.2 million in the Current and Prior Quarters, respectively. On a unit of production basis, production taxes were $0.33 per mcfe in the Current Quarter compared to $0.12 per mcfe in the Prior Quarter. The increase in the Current Quarter of $13.4 million was due to an increase in production volumes of 35% as well as an increase in the average wellhead prices received for natural gas. 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 2003 will range from $0.31 to $0.33 per mcfe based on our assumption that oil and natural gas wellhead prices will range from $4.50 to $5.00 per mcfe produced.

General and Administrative Expense. General and administrative expenses, which are net of internal payroll and non-payroll costs capitalized in our oil and gas properties, were $5.7 million in the Current Quarter compared to $4.3 million in the Prior Quarter. The increase in the Current Quarter is the result of the company’s growth related to acquisitions completed during the Current Quarter and in 2002. On a per unit of production basis, general and administrative expenses were $0.10 in both the Current and Prior Quarters. We expect general and administrative expenses for the remainder of 2003 to be between $0.09 and $0.10 per mcfe produced.

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 $7.3 million and $5.6 million of internal costs in the Current Quarter and Prior Quarter, respectively, directly related to our oil and gas exploration and development efforts.

Oil and Gas Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of oil and gas properties for the Current Quarter was $76.6 million, compared to $48.6 million in the Prior Quarter. The average DD&A rate per mcfe, which is a function of capitalized costs, estimated salvage value, future development costs, and the related underlying reserves in the periods presented, increased from $1.16 in the Prior Quarter to $1.35 in the Current Quarter. The increase in the average rate in the Current Quarter is primarily the result of higher drilling costs and higher costs associated with acquisitions. We expect the DD&A rate for the remainder of 2003 to be between $1.32 and $1.37 per mcfe produced.

Effective January 1, 2003, Chesapeake adopted SFAS 143, Accounting for Asset Retirement Obligations. SFAS 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and gas properties, this is the period in which an oil or gas well is acquired or drilled. The liability is capitalized as part of the carrying amount of our oil and gas properties at its discounted fair value. The asset retirement obligation is then accreted each period until the liability is settled or the well is sold. This accretion expense is included in DD&A expense on oil and gas properties. In addition, SFAS 143 effectively reduces previous DD&A rates prior to accretion expense by including the capitalized retirement obligation at its discounted fair value. During the Current Quarter, accretion expense related to asset retirement obligations was $0.7 million and is included in oil and gas depreciation, depletion and amortization expense.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $3.7 million in the Current Quarter, compared to $3.1 million in the Prior Quarter. The increase in the Current Quarter was primarily the result of higher depreciation costs on recently acquired fixed assets. Other property and equipment costs are depreciated on a straight-line basis. Buildings are depreciated over 31.5 years, drilling rigs are depreciated over 12 years and all other property and equipment are depreciated over the estimated useful lives of the assets, which range from three to seven years. To the extent the drilling rigs are used to drill our wells, a substantial portion of the depreciation is capitalized in oil and gas properties as exploration or development costs. We expect depreciation and amortization of other assets to be between $0.08 and $0.10 per mcfe produced for the remainder of 2003.

Interest and Other Income. Interest and other income was $0.8 million in the Current Quarter compared to $1.5 million in the Prior Quarter. The decrease in the Current Quarter was the result of a decrease in miscellaneous non-oil and gas income and a decrease in interest income.

Interest Expense. Interest expense increased to $35.0 million in the Current Quarter from $27.0 million in the Prior Quarter. The increase in the Current Quarter is due to a $422.4 million increase in average long-term borrowings in the Current Quarter compared to the Prior Quarter. In addition to the interest expense reported, we capitalized $1.9 million of interest during the Current Quarter, compared to $1.1 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 on our outstanding borrowings. We expect interest expense for the remainder of 2003 to be between $0.65 and $0.70 per mcfe produced.

Provision (Benefit) for Income Taxes. Chesapeake recorded income tax expense of $43.6 million in the Current Quarter, compared to income tax benefit of $18.4 million in the Prior Quarter. We anticipate that the effective tax rate for 2003 will be approximately 38% and all 2003 income tax expense will be deferred.

Cash Flows From Operating, Investing and Financing Activities

Cash Flows from Operating Activities. Cash provided by operating activities decreased 16% to $99.1 million during the Current Quarter compared to $117.3 million during the Prior Quarter. The decrease was due primarily to a decrease in working capital in the Current Quarter partially offset by increased cash flows resulting from higher natural gas and oil prices.

Cash Flows from Investing Activities. Cash used in investing activities increased to $1,002.3 million during the Current Quarter from $90.0 million in the Prior Quarter. During the Current Quarter, we expended approximately $136.3 million to initiate drilling on 207 (98 net) wells and invested approximately $95.8 million in unproved properties. This compares to $75.9 million to initiate drilling on 119 (57 net) wells and $7.4 million to purchase unproved properties in the Prior Quarter. During the Current Quarter, we completed acquisitions of proved oil and gas properties of $741.6 million and completed $0.7 million of divestitures of oil and gas properties. This compares to cash used in acquisitions of proved oil and gas properties of $0.9 million and no divestitures in the Prior Quarter. During the Current Quarter, we had additional investments in drilling rig equipment and other fixed assets of $9.3 million compared to $7.6 million in the Prior Quarter. The Current Quarter included an investment of $20.0 million in the common stock of Pioneer Drilling Company (AMEX: PDC). The Prior Quarter 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. Financing activities provided $693.6 million of cash in the Current Quarter, compared to $23.0 million of cash used in financing activities in the Prior Quarter. During the Current Quarter, we borrowed $139.0 million under our bank credit facility and made repayments under this facility of $139.0 million. In the Current Quarter, we received $297.3 million from the issuance of our $300 million principal amount of 7.50% senior notes and paid $6.4 million in costs related to the issuance of these notes. We issued 23 million shares of common stock and received $177.5 of net proceeds. We issued 4.6 million shares of 6.00% cumulative convertible preferred stock, $50 per share liquidation preference, or $230 million in the aggregate, and received $222.9 million of net proceeds. During the Current Quarter, we used $5.7 million to pay common stock dividends, $2.5 million to pay dividends on our 6.75% preferred stock and $2.1 million to purchase treasury stock. We received $1.5 million from the exercise of stock options and warrants, and we had $11.7 million of outstanding payments in excess of our funded cash balances as of March 31, 2003. The activity in the Prior Quarter included $21.4 million to purchase $21.0 million principal amount of our 7.875% senior notes, $18.2 million in cash received from the exercise of stock options, and $2.6 million for the payment of dividends on our 6.75% preferred stock.

Liquidity and Capital Resources

Sources of Liquidity

Chesapeake had net working capital of $1.8 million at March 31, 2003, including $38.0 million in cash. Another source of liquidity is our $250 million revolving bank credit facility (with a committed borrowing base of $250 million) which matures in June 2005. At March 31 and May 13, 2003, we had no indebtedness under the bank credit facility, and utilized $15.4 million and $18.2 million, respectively, of the facility for various letters of credit.

We believe we will have adequate resources, including budgeted cash flows from operating activities before changes in assets and liabilities, working capital and proceeds from our revolving bank credit facility, to fund our capital expenditure budget for drilling, land and seismic activities during the remainder of 2003, which is currently estimated to be between $575 and $600 million. However, higher drilling and field operating costs, unfavorable drilling results or other factors could cause us to reduce our drilling program, which is largely discretionary. Any operating cash flow not needed to fund our drilling program will be available for acquisitions, debt repayment or other general corporate purposes in 2003.

A significant portion of our liquidity at March 31, 2003 is concentrated in cash, cash equivalents and accounts receivable. Financial instruments which potentially subject us to concentrations of credit risk consist principally of investments in debt instruments, equity securities and accounts receivables. Our accounts receivable are primarily

from purchasers of oil and natural gas products and exploration and production companies which own interests in properties we operate. The industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. Cash and cash equivalents are deposited with major banks or institutions with high credit ratings.

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

Contractual Obligations

We have a $250 million revolving bank credit facility (with a committed borrowing base of $250 million) which matures in June 2005. As of March 31, 2003, we had no outstanding borrowings under this facility and utilized $15.4 million of the facility for various letters of credit. Borrowings under the facility are collateralized by certain producing oil and gas properties and bear interest at either the reference rate of Union Bank of California, N.A., or London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies according to total facility usage. The collateral value and borrowing base are redetermined periodically. The unused portion of the facility is subject to an annual commitment fee of 0.50%. Interest is payable quarterly.

The credit agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, sell properties, pay dividends, purchase or redeem our capital stock, make investments or loans or purchase certain of our senior notes, create liens, and make acquisitions. The credit agreement requires us to maintain a current ratio (as defined) of at least 1 to 1 and a fixed charge coverage ratio for the trailing twelve month period (as defined) of at least 2.5 to 1. At March 31, 2003, our current ratio was 1.7 to 1 and our fixed charge coverage ratio was 2.8 to 1. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million or more, would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of our senior note indebtedness. The credit agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $5.0 million.

As of March 31, 2003, senior notes represented approximately $2.0 billion of our long-term debt and consisted of the following ($ in thousands):

7.875% senior notes due 2004	$	42,137
8.375% senior notes due 2008		250,000
8.125% senior notes due 2011		800,000
9.000% senior notes due 2012		300,000
8.500% senior notes due 2012		142,665
7.500% senior notes due 2013		300,000
7.750% senior notes due 2015		150,000

	$	1,984,802

There are no scheduled principal payments required on any of the senior notes until March 2004, when $42.1 million is due. Debt ratings for the senior notes are Ba3 by Moody’s Investor Service, B+ by Standard & Poor’s Ratings Services and BB- by Fitch Ratings as of March 31, 2003. Debt ratings for our secured bank credit facility are Ba2 by Moody’s Investor Service, BB by Standard & Poor’s Ratings Services and BB+ by Fitch Ratings.

Our senior notes are unsecured senior obligations of Chesapeake and rank equally with all of our other unsecured indebtedness. All of our wholly owned subsidiaries except Chesapeake Energy Marketing, Inc. guarantee the notes. The indentures permit us to redeem the senior notes at any time at specified make-whole or redemption prices. The indentures for the 8.125%, 8.375%, 9.000%, 7.750% and 7.500% 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 March 31, 2003, we estimate that secured commercial bank indebtedness of approximately $770 million could have been incurred under the most restrictive indenture covenant. The indenture covenants do not apply to Chesapeake Energy Marketing, Inc., which is our only unrestricted subsidiary.

Some of our commodity price and financial risk management arrangements require us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations with respect to our commodity price and financial risk management transactions exceed certain levels. At March 31, 2003, we were required to post $14.5 million of collateral which was secured by a letter of credit under our credit facility. Future collateral requirements are uncertain and will depend on arrangements with our counterparties, highly volatile natural gas and oil prices, and fluctuations in interest rates.

Investing and Financing Transactions

On March 5, 2003, we closed a private offering of $300 million in aggregate principal amount of senior notes, issued 23 million shares of common stock pursuant to a shelf registration statement and issued $230 million liquidation amount of convertible preferred stock in a private placement. Net proceeds from these transactions were used to finance the acquisition of oil and gas properties from El Paso Corporation and Vintage Petroleum, Inc. as discussed below and to repay indebtedness under our bank credit facility.

On March 13, 2003, we acquired El Paso Corporation’s Anadarko Basin assets in western Oklahoma and the Texas Panhandle for $500 million.

On March 31, 2003, we acquired Vintage Petroleum, Inc.’s assets in the Bray field in southern Oklahoma for $29 million.

On March 31, 2003, Chesapeake bought 5.3 million newly issued common shares of Pioneer Drilling Company, or 24.6% of its outstanding common shares, at $3.75 per share, for a total investment of $20 million.

Contingencies

Royalty owners have commenced litigation against a number of oil and gas producers claiming that amounts paid for production attributable to the royalty owners’ interest violated the terms of applicable leases and state law, that deductions from the proceeds of oil and gas production were unauthorized under the leases, and that amounts received by upstream sellers should be used to compute the amounts paid to the royalty owners. Typically this litigation has taken the form of class action suits. There are presently four such suits filed against Chesapeake, two in Texas and two in Oklahoma. No class has been certified in any of them. In one of the Oklahoma cases, we determined that a portion of the marketing fee we had charged royalty owners should be refunded. We have deposited with the court the aggregate amount of the fees we estimated should be refunded, $3.6 million, in an interest-bearing account for distribution to affected royalty owners. This amount was charged to general and administrative expenses of which $0.3 million was charged in the Current Quarter. We do not believe any other claims made by royalty owners in the cases pending against us are valid. Even if the claims were upheld, we believe any damages awarded would not be material. This is a developing area of the law, however, and as new cases are decided, our potential liability relating to the marketing of oil and gas may increase or decrease. We will continue to monitor 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.

Critical Accounting Policies

We consider accounting policies related to stock options, hedging, oil and gas properties, and income taxes and business combinations to be critical policies. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the year ended December 31, 2002, except for our accounting policy related to stock options which is summarized in Note 1 of our annual report on Form 10-K.

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 utilization of net operating loss carryforwards. Statements concerning the fair values of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility.

Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in Item 1 of our Form 10-K for the year ended December 31, 2002. These factors include:

•

the volatility of oil and gas prices,

•

our substantial indebtedness and preferred stock obligations,

•

the strength and financial resources of our competitors,

•

the cost and availability of drilling and production services,

•

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

•

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

•

our ability to replace reserves,

•

the availability of capital,

•

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

•

declines in the values of our oil and gas properties resulting in ceiling test write-downs,

•

drilling and operating risks,

•

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

•

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

•

adverse effects of governmental and environmental regulation,

•

the loss of officers or key employees,

•

our ability to incur additional indebtedness, and

•

losses possible from pending or future litigation.

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 filings with the Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect our business.

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 March 31, 2003, our oil and gas derivative instruments were comprised of swaps, cap-swaps, 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, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended.

•

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 and cap-swap transactions designed to hedge a portion of our oil or natural gas production by entering into a counter-swap instrument which does not qualify for hedge accounting under SFAS 133. 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 is designed to lock the value of an existing SFAS 133 cash flow hedge, the net value is frozen and shown as a derivative asset or liability. To the extent the counter-swap is designed to lock the value of an existing SFAS 133 cash flow hedge and both the counter-swap and existing swap are with the same counterparty, 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. The net receivable or payable is frozen until the related month of production and is then recognized as an increase or decrease to revenues. Changes in fair value occurring after the original swap has been designated as a non-qualifying cash flow hedge under SFAS 133 are included in results of operations. To the extent the counter-swap is designed to lock the value of a non-qualifying cash flow hedge under SFAS 133, the value of the counter-swap is shown as a derivative asset or liability in the consolidated balance sheets and referred to below as a fixed-price counter-swap. Any changes in the fair value of the counter-swap are included in results of operations.

As of March 31, 2003, we had the following open oil and gas derivative instruments designed to hedge a portion of our oil and gas production for periods after March 2003:

	Volume		Weighted- Average Strike Price	Weighted- Average Put Strike Price	Weighted Average Differential to NYMEX		Qualifies As SFAS 133 Hedge	Fair Value at March 31, 2003 ($ in thousands)
Natural Gas (mmbtu):

Swaps:
2003	54,370,000		5.18	—	—		Yes		2,473
2004	600,000		5.69	—	—		Yes		228

Cap-Swaps:
2003	38,500,000		3.54	2.54	—		No		(61,752	)

Counter-Swaps:
2003	(38,500,000	)	3.69	—	—		No		55,813

Basis Protection Swaps:
2003	110,000,000		—	—	(0.19	)	No		11,182
2004	146,400,000		—	—	(0.17	)	No		8,226
2005	98,550,000		—	—	(0.16	)	No		5,547
2006	36,500,000		—	—	(0.16	)	No		1,695
2007	63,875,000		—	—	(0.17	)	No		1,595
2008	64,050,000		—	—	(0.17	)	No		1,526
2009	36,500,000		—	—	(0.16	)	No		1,111

Locked Swaps:
2003	—		—	—	—		No		(6,728	)
2004	—		—	—	—		No		793


Total Gas									21,709


Oil (bbls):

Cap-Swaps:
2003	2,475,000		28.12	—	—		No		(2,329	)


Total Oil									(2,329	)


Total Gas and Oil								$	19,380

We have established the fair value of all derivative instruments using estimates of fair value reported by our counterparties and subsequently evaluated internally using established index prices and other sources. 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 March 31, 2003.

Additional information concerning the fair value of our oil and gas derivative instruments is as follows:

	2003			2002
	($ in thousands)
Fair value of contracts outstanding at January 1	$	(14,533	)	$	157,309
Change in fair value of contracts during the quarter		126,771			(69,712	)
Contracts realized or otherwise settled during the quarter		(92,858	)		(48,554	)
Fair value of new contracts when entered into during the quarter		—			(42,530	)

Fair value of contracts outstanding at March 31	$	19,380		$	(3,487	)

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

	Three Months Ended March 31,
	2003		2002
	($ in thousands)
Risk management income (loss):
Change in fair value of derivatives not qualifying for cash flow hedge accounting	$	18,864	$	(53,414	)
Reclassification of (gain) loss on settled contracts		10,775		(25,077	)
Ineffective portion of derivatives qualifying for cash flow hedge accounting		48		(824	)

Total	$	29,687	$	(79,315	)

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 date. The derivative settlement amounts are not due and payable until the month in which the related underlying hedged transaction occurs.

Interest Rate Hedging

Term		Notional Amount		Fixed Rate		Floating Rate
March 2004 – March 2012		$142,665,000		8.500%		U.S. six-month LIBOR plus 75 basis points

We have recorded a decrease in the carrying value of the debt of $18.8 million since the inception of the swaption as of March 31, 2003. Of this amount, $23.8 million represents a decline in the fair value of the swaption, offset by a loss of $5.0 million from estimated ineffectiveness of the swaption as determined under SFAS 133. See Note 5 of the notes to consolidated financial statements of this report for the adjustments made to the carrying value

of the debt at March 31, 2003. Results of the interest rate swap, if initiated, will be reflected as adjustments to interest expense in the corresponding months covered by the swaption agreement.

Risk management income (loss) related to our fair value interest rate hedges is comprised of the following:

	Three Months Ended March 31,
	2003			2002
	($ in thousands)
Risk management income (loss):
Change in fair value of derivatives not qualifying for fair value hedge accounting	$	—		$	(153	)
Reclassification of (gain) loss on settled contracts		(527	)		—
Ineffective portion of derivatives qualifying for fair value hedge accounting		(1,450	)		—

Total	$	(1,977	)	$	(153	)

Interest Rate Risk

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

	March 31, 2003
	Years of Maturity
	2004			2005		2006		2007		2008			Thereafter			Total			Fair Value
	($ in millions)
Liabilities:
Long-term debt, including current portion — fixed rate	$	42.1		$	—	$	—	$	—	$	250.0		$	1,692.7		$	1,984.8	⁽¹⁾	$	2,067.5
Average interest rate		7.9	%		—		—		—		8.4	%		8.2	%		8.2	%		8.2	%

(1)

This amount does not include the discount of $(17.9) million, the value of the interest rate swap of $0.6 million and the value of the swaption of ($18.8) million which are all included in long-tem debt on the consolidated balance sheet.

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.

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, 2002.

Item 2. Changes in Securities and Use of Proceeds

On March 5, 2003, we completed a private offering of 4,600,000 shares of 6.00% Cumulative Convertible Preferred Stock (liquidation preference $50 per share). The preferred stock was sold by us to Credit Suisse First Boston LLC, Morgan Stanley & Co. Incorporated, Salomon Smith Barney Inc., Bear, Stearns & Co. Inc., Lehman Brothers Inc., CIBC World Markets Corp., Johnson Rice & Company L.L.C., RBC Dain Rauscher Inc., and Simmons & Company International, which companies resold the shares of preferred stock pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”) at the liquidation preference. We were paid $48.50 per share, or an aggregate of $223.1 million. Net proceeds to us, after expenses, were $222.9 million.

The preferred stock was sold in a transaction exempt from registration pursuant to Section 4(2) of the Securities Act. Each of the purchasers represented that it is an accredited investor within the meaning of Regulation D under the Securities Act. No public solicitation was made in connection with the offering of the preferred stock.

Each share of preferred stock is convertible at any time at the option of the holder into 4.8605 shares of common stock (which is calculated using an initial conversion price of $10.287 per share of common stock), subject to adjustment upon the occurrence of certain events related to the common stock.

At any time on or after March 20, 2006, we may, at our option, cause each share of preferred stock to be automatically converted into that number of shares of common stock equal to $50.00 divided by the then prevailing conversion price. We may exercise this right only if the closing price of our common stock equals or exceeds 130% of the then prevailing conversion price for at least 20 trading days in any consecutive 30-day trading period ending on the trading day prior to our issuance of a press release announcing the mandatory conversion. In addition, if there are less than 250,000 share of preferred stock outstanding, we may, at any time on or after March 20, 2008, at our option, cause each share of preferred stock to be automatically converted into that number of shares of common stock equal to $50.00 divided by the lessor of (i) the then prevailing conversion price and (ii) the market value for the five trading day period ending on the second trading day immediately prior to the conversion date.

Upon a change of control (as defined in the certificate of designation), holders of preferred stock shall, if the market value at such time is less than the conversion price, have a one-time option to convert all of their outstanding shares of preferred stock into shares of common stock at an adjusted conversion price equal to the greater of (1) the market value as of the change of control date and (2) $5.47. In lieu of issuing the shares of common stock issuable upon conversion in the event of a change of control, we may, at our option, make a cash payment equal to the market value for each share of such common stock otherwise issuable.

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

3.1		Chesapeake’s Restated Certificate of Incorporation together with Chesapeake’s Certificate of Designation for the 6.75% Cumulative Convertible Preferred Stock, Certificate of Elimination of 2,000 shares of the 6.75% Cumulative Convertible Preferred Stock, Certificate of Designation for the Series A Junior Participating Preferred Stock and Certificate of Designation for the 6.00% Cumulative Convertible Preferred Stock. Incorporated herein by reference to Exhibit 3.1 to Chesapeake’s registration statement on Form S-3 (No. 333-104394) filed April 9, 2003.

4.1.1*		Thirteenth Supplemental Indenture dated as of May 1, 2003 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.

4.2.1*		Thirteenth Supplemental Indenture dated as of May 1, 2003 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 8.50% Senior Notes due 2012.

4.3.1*		Eighth Supplemental Indenture dated as of May 1, 2003 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.

4.4.1*		Fifth Supplemental Indenture dated as of May 1, 2003 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, as Trustee, with respect to 8.375% Senior Notes due 2008.

4.5.1*		Second Supplemental Indenture dated May 1, 2003 to Indenture dated as of August 12, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 9.0% Senior Notes due 2012.

4.6.1*		Second Supplemental Indenture dated as of May 1, 2003 to Indenture dated as of December 20, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.75% Senior Notes due 2015.

4.7		Indenture dated as of March 5, 2003 among Chesapeake, as issuer, the subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.50% Senior Notes due 2013. Incorporated herein by reference to Exhibit 4.7 to Chesapeake’s registration statement on Form S-4 (No. 333-104396) filed April 9, 2003.

4.7.1*		First Supplemental Indenture dated as of May 1, 2003 to Indenture dated as of March 5, 2003 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.50% Senior Notes due 2013.

4.9.1		Fifth Amendment dated March 3, 2003 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, BNP Paribas and Toronto Dominion (Texas), Inc., as Co-Documentation Agents and other lender parties thereto. Incorporated herein by reference to Exhibit 4.9.1 to Chesapeake’s registration statement on Form S-4 (No. 333-104396) filed April 9, 2003.


4.18		Registration Rights Agreement dated March 5, 2003 between Chesapeake and Salomon Smith Barney Inc., Bear Stearns & Co., Inc., Credit Suisse First Boston LLC, Lehman Brothers Inc., Morgan Stanley & Co. Incorporated, BNP Paribas Securities Corp., Credit Lyonnais Securities (USA) Inc., and TD Securities (USA) Inc. Incorporated herein by reference to Exhibit 4.18 to Chesapeake’s registration statement on Form S-4 (No. 333-104396) filed April 9, 2003.

4.19		Registration Rights Agreement dated March 5, 2003 between Chesapeake and Credit Suisse First Boston LLC, Morgan Stanley & Co., Incorporated, Salomon Smith Barney Inc., Bear Stearns & Co., Inc. Lehman Brothers Inc., CIBC World Markets Corp., Johnson Rice & Company L.L.C., RBC Dain Rauscher Inc. and Simmons & Company International. Incorporated herein by reference to Exhibit 4.19 to Chesapeake’s registration statement on Form S-3 (No. 333-104394) filed April 9, 2003.

10.2.3†*		Employment Agreement dated as of April 1, 2003 between Marcus C. Rowland and Chesapeake.

10.2.8†*		Employment Agreement dated as of April 1, 2003 between Michael A. Johnson and Chesapeake.

10.2.9†*		Employment Agreement dated as of April 1, 2003 between Martha A. Burger and Chesapeake.

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

21*		Subsidiaries of Chesapeake.

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.

Filed herewith.

†

Management contract or compensatory plan or arrangement.

(b) Reports on Form 8-K

During the quarter ended March 31, 2003, we filed the following current reports on Form 8-K:

On January 10, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on January 9, 2003 announcing an update on our natural gas hedging program for 2003.

On January 24, 2003, we filed a current report on Form 8-K, furnishing under Item 9 a press release we issued on January 24, 2003 announcing fourth quarter and 2002 full-year earnings release date and conference call.

On February 4, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on February 3, 2003 announcing completion of the acquisition of $300 million of Mid-Continent gas reserves from ONEOK, Inc and furnishing under Item 9 additional statements made in connection with the acquisition.

On February 21, 2003, we filed a current report on Form 8-K, furnishing under Item 9 a press release we issued on February 20, 2003 announcing a change in the timing of our fourth quarter and 2002 full-year earnings conference call.

On February 25, 2003 (as amended on February 27, 2003), we filed a current report on Form 8-K, furnishing under Item 9 (1) a press release we issued on February 24, 2003 announcing financial and operating results for the fourth quarter and full-year 2002, (2) a press release we issued on February 24, 2003 announcing agreements to acquire assets from El Paso Corporation and Vintage Petroleum, Inc., (3) information regarding the posting of an updated outlook on our website, and (4) highlights of investor presentations attached as Exhibit 99.1.

On February 25, 2003, we filed a current report on Form 8-K, furnishing under Item 9 a press release we issued on February 25, 2003 announcing private offerings of senior notes and convertible preferred stock.

On February 25, 2003, we filed a current report on Form 8-K, furnishing under Item 9 a press release we issued on February 25, 2003 announcing a public offering of common stock.

On February 28, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on February 28, 2003 announcing the pricing of our public offering of common stock.

On February 28, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on February 28, 2003 announcing the pricing of our private offering of 6.00% Cumulative Convertible Preferred Stock.

On February 28, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on February 28, 2003 announcing the pricing of $300 million of 7.5% Senior Notes due 2013.

On March 4, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we entered into an underwriting agreement with Credit Suisse First Boston LLC, Morgan Stanley & Co. Incorporated, Salomon Smith Barney Inc., Bear, Stearns & Co. Inc., Lehman Brothers Inc., CIBC World Markets Corp., Johnson Rice & Company L.L.C., RBC Dain Rauscher Inc., and Simmons & Company International in connection with the issuance and sale of 20,000,000 shares of our common stock, plus an additional 3,000,000 shares of common stock pursuant to the underwriters’ over-allotment option. In addition, we filed the underwriting agreement under Item 7.

On March 14, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on March 13, 2003 announcing the completion of an acquisition of $500 million of Mid-Continent gas reserves from El Paso Corporation and furnishing under Item 9 additional statements made in connection with the acquisition.

On March 19, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on March 19, 2003 announcing the declaration of quarterly common and preferred stock dividends.

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 (Principal Executive Officer)

By:

/s/ MARCUS C. ROWLAND

Marcus C. Rowland

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Date: May 15, 2003

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: May 15, 2003

/s/ AUBREY K. MCCLENDON

Aubrey K. McClendon

Chairman and Chief Executive Officer

(Principal Executive Officer)

CERTIFICATION

I, Marcus C. Rowland certify that:

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

(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;

(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

Date: May 15, 2003

/s/ MARCUS C. ROWLAND

Marcus C. Rowland

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

INDEX TO EXHIBITS

Exhibit Number		Description

3.1		Chesapeake’s Restated Certificate of Incorporation together with Chesapeake’s Certificate of Designation for the 6.75% Cumulative Convertible Preferred Stock, Certificate of Elimination of 2,000 shares of the 6.75% Cumulative Convertible Preferred Stock, Certificate of Designation for the Series A Junior Participating Preferred Stock and Certificate of Designation for the 6.00% Cumulative Convertible Preferred Stock. Incorporated herein by reference to Exhibit 3.1 to Chesapeake’s registration statement on Form S-3 (No. 333-104394) filed April 9, 2003.

4.1.1*		Thirteenth Supplemental Indenture dated as of May 1, 2003 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.

4.2.1*		Thirteenth Supplemental Indenture dated as of May 1, 2003 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 8.50% Senior Notes due 2012.

4.3.1*		Eighth Supplemental Indenture dated as of May 1, 2003 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.

4.4.1*		Fifth Supplemental Indenture dated as of May 1, 2003 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, as Trustee, with respect to 8.375% Senior Notes due 2008.

4.5.1*		Second Supplemental Indenture dated May 1, 2003 to Indenture dated as of August 12, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 9.0% Senior Notes due 2012.

4.6.1*		Second Supplemental Indenture dated as of May 1, 2003 to Indenture dated as of December 20, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.75% Senior Notes due 2015.

4.7		Indenture dated as of March 5, 2003 among Chesapeake, as issuer, the subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.50% Senior Notes due 2013. Incorporated herein by reference to Exhibit 4.7 to Chesapeake’s registration statement of Form S-4 (No. 333-104396) filed April 9, 2003.

4.7.1*		First Supplemental Indenture dated as of May 1, 2003 to Indenture dated as of March 5, 2003 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.50% Senior Notes due 2013.

4.9.1		Fifth Amendment dated March 3, 2003 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, BNP Paribas and Toronto Dominion (Texas), Inc., as Co-Documentation Agents and other lender parties thereto. Incorporated herein by reference to Exhibit 4.9.1 to Chesapeake’s registration statement on Form S-4 (No. 333-104396) filed April 9, 2003.


4.18		Registration Rights Agreement dated March 5, 2003 between Chesapeake and Salomon Smith Barney Inc., Bear Stearns & Co., Inc., Credit Suisse First Boston LLC, Lehman Brothers Inc., Morgan Stanley & Co. Incorporated, BNP Paribas Securities Corp., Credit Lyonnais Securities (USA) Inc., and TD Securities (USA) Inc. Incorporated herein by reference to Exhibit 4.18 to Chesapeake’s registration statement on Form S-4 (No. 333-104396) filed April 9, 2003.

4.19		Registration Rights Agreement dated March 5, 2003 between Chesapeake and Credit Suisse First Boston LLC, Morgan Stanley & Co., Incorporated, Salomon Smith Barney Inc., Bear Stearns & Co., Inc. Lehman Brothers Inc., CIBC World Markets Corp., Johnson Rice & Company L.L.C., RBC Dain Rauscher Inc. and Simmons & Company International. Incorporated herein by reference to Exhibit 4.19 to Chesapeake’s registration statement on Form S-3 (No. 333-104394) filed April 9, 2003.

10.2.3†*		Employment Agreement dated as of April 1, 2003 between Marcus C. Rowland and Chesapeake.

10.2.8†*		Employment Agreement dated as of April 1, 2003 between Michael A. Johnson and Chesapeake.

10.2.9†*		Employment Agreement dated as of April 1, 2003 between Martha A. Burger and Chesapeake.

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

21*		Subsidiaries of Chesapeake.

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.

Filed herewith.

†

Management contract or compensatory plan or arrangement.

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