CHESAPEAKE ENERGY CORP - 10-Q Quarterly Report

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, 2004

¨	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 ¨

As of May 5, 2004, there were 242,196,292 shares of our $0.01 par value common stock outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2004


		Page
PART I.	Financial Information

Item 1.	Condensed Consolidated Financial Statements (Unaudited):

	Condensed Consolidated Balance Sheets as of March 31, 2004 and December 31, 2003	3

	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2004 and 2003	4

	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2004 and 2003	5

	Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2004 and 2003	6

	Notes to Condensed 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	30

Item 4.	Controls and Procedures	34

PART II.	Other Information

Item 1.	Legal Proceedings	35

Item 2.	Changes in Securities and Use of Proceeds	35

Item 3.	Defaults Upon Senior Securities	36

Item 4.	Submission of Matters to a Vote of Security Holders	36

Item 5.	Other Information	36

Item 6.	Exhibits and Reports on Form 8-K	36

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2004			December 31, 2003
	($ in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	189,425		$	40,581
Accounts receivable:
Oil and gas sales		205,826			173,792
Joint interest, net of allowances of $3,523,000 and $2,669,000, respectively		40,408			37,789
Short-term derivatives		—			1,777
Related parties		5,310			2,983
Other		32,618			26,830
Deferred income tax asset		76,671			36,705
Short-term derivative instruments		—			2,690
Inventory and other		21,210			19,257

Total Current Assets		571,468			342,404

PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties		7,012,420			6,221,576
Unevaluated properties		301,657			227,331
Less: accumulated depreciation, depletion and amortization		(2,599,185	)		(2,480,261	)

		4,714,892			3,968,646
Other property and equipment		240,378			225,891
Less: accumulated depreciation and amortization		(66,347	)		(61,420	)

Total Property and Equipment		4,888,923			4,133,117

OTHER ASSETS:
Long-term derivative instruments		15,385			17,493
Long-term investments		33,357			31,544
Other assets		48,329			47,733

Total Other Assets		97,071			96,770

TOTAL ASSETS	$	5,557,462		$	4,572,291

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	246,892		$	164,264
Accrued interest		42,677			46,648
Short-term derivative instruments		202,606			92,651
Other accrued liabilities		117,851			108,020
Revenues and royalties due others		132,546			101,573

Total Current Liabilities		742,572			513,156

LONG-TERM LIABILITIES:
Long-term debt, net		2,012,147			2,057,713
Revenues and royalties due others		14,829			13,921
Asset retirement obligation		57,476			48,812
Long-term derivative instruments		19,623			4,736
Deferred income tax liability		368,808			191,026
Other liabilities		11,828			10,117

Total Long-term Liabilities		2,484,711			2,326,325

CONTINGENCIES AND COMMITMENTS (Note 3)
STOCKHOLDERS’ EQUITY:
Preferred Stock, $.01 par value, 10,000,000 shares authorized: 6.75% cumulative convertible preferred stock, 2,997,800 and 2,998,000 shares issued and outstanding as of March 31, 2004 and December 31, 2003, respectively, entitled in liquidation to $149,890,000 and $149,900,000		149,890			149,900
6.00% cumulative convertible preferred stock, 4,600,000 shares issued and outstanding as of March 31, 2004 and December 31, 2003, respectively, entitled in liquidation to $230,000,000		230,000			230,000
5.00% cumulative convertible preferred stock, 1,725,000 shares issued and outstanding as of March 31, 2004 and December 31, 2003, entitled in liquidation to $172,500,000		172,500			172,500
4.125% cumulative convertible preferred stock, 275,000 and 0 shares issued and outstanding as of March 31, 2004 and December 31, 2003, respectively, entitled in liquidation to $275,000,000		275,000			—
Common Stock, $.01 par value, 350,000,000 shares authorized, 247,005,377 and 221,855,894 shares issued as of March 31, 2004 and December 31, 2003, respectively		2,470			2,218
Paid-in capital		1,687,844			1,389,212
Accumulated deficit		(72,600	)		(168,617	)
Accumulated other comprehensive income (loss), net of tax of $52,219,000 and $12,449,000, respectively		(92,834	)		(20,312	)
Less: treasury stock, at cost; 5,071,571 common shares as of March 31, 2004 and December 31, 2003		(22,091	)		(22,091	)

Total Stockholders’ Equity		2,330,179			1,732,810

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	5,557,462		$	4,572,291

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended March 31,
	2004			2003
	($ in thousands, except per share data)
REVENUES:
Oil and gas sales	$	419,793		$	286,019
Oil and gas marketing sales		143,336			90,308

Total Revenues		563,129			376,327

OPERATING COSTS:
Production expenses		44,803			31,457
Production taxes		14,936			18,597
General and Administrative Expenses:
General and administrative (excluding stock based compensation)		8,166			5,379
Stock based compensation		1,869			—
Oil and gas marketing expenses		139,664			89,358
Oil and gas depreciation, depletion and amortization		119,908			76,614
Depreciation and amortization of other assets		5,739			3,684
Provisions for legal settlements		—			286

Total Operating Costs		335,085			225,375

INCOME FROM OPERATIONS		228,044			150,952

OTHER INCOME (EXPENSE):
Interest and other income		1,343			763
Interest expense		(46,545	)		(37,004	)
Loss on repurchases or exchanges of Chesapeake debt		(6,925	)		—

Total Other Income (Expense)		(52,127	)		(36,241	)

INCOME BEFORE INCOME TAX AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		175,917			114,711
INCOME TAX EXPENSE:
Current		—			—
Deferred		63,327			43,591

Total Income Tax Expense		63,327			43,591

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		112,590			71,120
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF INCOME TAXES OF $1,464,000		—			2,389

NET INCOME		112,590			73,509
PREFERRED STOCK DIVIDENDS		(8,168	)		(3,526	)

NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$	104,422		$	69,983

EARNINGS PER COMMON SHARE — BASIC:
Income before cumulative effect of accounting change	$	0.44		$	0.34
Cumulative effect of accounting change		—			0.01

	$	0.44		$	0.35

EARNINGS PER COMMON SHARE — ASSUMING DILUTION:
Income before cumulative effect of accounting change	$	0.38		$	0.31
Cumulative effect of accounting change		—			0.01

	$	0.38		$	0.32

CASH DIVIDEND DECLARED PER COMMON SHARE	$	0.035		$	0.03

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in thousands):
Basic		236,884			197,608

Assuming dilution		299,241			230,672

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
	2004			2003
	($ in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$	112,590		$	73,509
ADJUSTMENTS TO RECONCILE NET INCOME TO NET
CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization		124,599			78,680
Deferred income taxes		63,156			45,055
Unrealized (gains) losses on derivatives		22,739			(27,710	)
Amortization of loan costs and bond discount		2,022			1,936
Cumulative effect of accounting change		—			(3,853	)
Loss on repurchases or exchanges of Chesapeake debt		6,925			—
Income from equity investment		(422	)		—
Stock-based compensation		1,869			—
Other		76			96

Cash provided by operating activities before changes in assets and liabilities		333,554			167,713
Changes in assets and liabilities		8,216			(68,661	)

Cash provided by operating activities		341,770			99,052

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil and gas companies, proved properties and unproved properties, net of cash acquired		(482,153	)		(819,142	)
Exploration and development of oil and gas properties		(235,888	)		(154,563	)
Additions to buildings and other fixed assets		(11,434	)		(9,379	)
Divestitures of oil and gas properties		249			667
Deposit on pending acquisition of Permian Resources		(3,750	)		—
Investment in Pioneer Drilling Company		—			(20,000	)
Additions to drilling rig equipment		(2,466	)		(36	)
Other		8			164

Cash used in investing activities		(735,434	)		(1,002,289	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings		381,000			139,000
Payments on long-term borrowings		(381,000	)		(139,000	)
Cash received from issuance of senior notes, net of offering costs		—			290,920
Proceeds from issuance of preferred stock, net of offering costs		267,737			222,907
Proceeds from issuance of common stock, net of offering costs		298,107			177,526
Cash paid to purchase or exchange senior notes, including redemption premium		(57,271	)		—
Cash paid for common stock dividend		(7,588	)		(5,705	)
Cash paid for preferred stock dividend		(8,063	)		(2,530	)
Cash paid for treasury stock		—			(2,109	)
Net increase in outstanding payments in excess of cash balance		47,059			11,676
Other financing costs		(179	)		(595	)
Cash received from exercise of stock options		2,706			1,514

Cash provided by financing activities		542,508			693,604

Net increase (decrease) in cash and cash equivalents		148,844			(209,633	)
Cash and cash equivalents, beginning of period		40,581			247,637

Cash and cash equivalents, end of period	$	189,425		$	38,004

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,
	2004			2003
	($ in thousands)
Net Income	$	112,590		$	73,509
Other comprehensive income, net of income tax:
Change in fair value of derivative instruments, net of income taxes of ($36,804,000) and ($29,760,000)		(65,430	)		(48,555	)
Reclassification of (gain) or loss on settled contracts, net of income taxes of ($6,581,000) and $31,191,000		(11,699	)		50,891
Ineffective portion of derivatives qualifying for cash flow hedge accounting, net of income taxes of $2,591,000 and ($18,000)		4,607			(30	)

Comprehensive income	$	40,068		$	75,815

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED 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, 2004 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, 2004 (the “Current Quarter”) and the three months ended March 31, 2003 (the “Prior Quarter”).

Stock Options and Restricted Stock

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 (FIN 44), which provided clarification regarding the application of APB No. 25. FIN 44 specifically addressed the accounting consequence of various modifications to the terms of a previously granted fixed-price stock option. Pursuant to FIN 44, we recognized a reduction of compensation expense of $36,900 and $22,600 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, 2003, 2001 and 2000. No compensation expense has been recognized for stock options upon original issuance in 2004 or 2003 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.

Presented below is pro forma financial information assuming Chesapeake has applied the fair value method under SFAS No. 123:


	Three Months Ended March 31,
	2004			2003
	($ in thousands, except per share amounts)
Net Income
As reported	$	112,590		$	73,509
Less compensation expense, net of tax⁽¹⁾		(3,044	)		(2,475	)

Pro forma	$	109,546		$	71,034

Basic earnings per common share
As reported	$	0.44		$	0.35
Less compensation expense, net of tax⁽¹⁾		(0.01	)		(0.01	)

Pro forma	$	0.43		$	0.34

Diluted earnings per common share
As reported	$	0.38		$	0.32
Less compensation expense, net of tax⁽¹⁾		(0.01	)		(0.01	)

Pro forma	$	0.37		$	0.31

(1)	Adjustments are net of reductions to compensation expense related to FIN 44 of $36,900 and $22,600 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.

During the Current Quarter, Chesapeake issued 1.1 million shares of restricted common stock to employees as a result of Chesapeake’s normal compensation review process. The shares of restricted stock vest over a period of four years from the date of grant. Chesapeake recognized

amortization of compensation cost related to the restricted stock totaling $1.9 million in the Current Quarter. This amount is reflected in the condensed consolidated statements of operations as a charge in the Current Quarter. No such cost was recognized in the Prior Quarter.

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, 2003, except for our accounting policy related to stock options which is summarized in Note 1 of the notes to the consolidated financial statements included in our annual report on Form 10-K.

Emerging Issues Task Force (EITF) Issue No. 03-S, Application of SFAS No. 142, Goodwill and Other Intangible Assets to Oil and Gas Companies, considers whether oil and gas drilling rights represent intangible assets subject to the classification and disclosure provisions of SFAS 142. Chesapeake classifies the cost of oil and gas mineral rights as property and equipment and believes that this is consistent with oil and gas accounting and industry practice. If the EITF determines that oil and gas mineral rights are intangible assets and are subject to the applicable classification and disclosure provisions of SFAS 142, we estimate that $283.1 million and $227.3 million would be classified on our condensed consolidated balance sheets as “intangible undeveloped leasehold” and $1.9 billion and $1.4 billion would be classified as “intangible developed leasehold” as of March 31, 2004 and December 31, 2003, respectively. These amounts are net of accumulated depreciation, depletion and amortization. There would be no effect on the condensed consolidated statements of operations or cash flows as the intangible assets related to oil and gas mineral rights would continue to be amortized under the full cost method of accounting.

We will continue to classify our oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.

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, 2004, our oil and gas derivative instruments were comprised of swaps, cap-swaps, basis protection swaps, call options and collars. 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, Chesapeake receives a fixed price for the hedged commodity and pays 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, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a “cap” limiting the counterparty’s exposure. In other words, there is no limit to Chesapeake’s exposure but there is a limit to the downside exposure of the counterparty. Because this derivative includes a written put option (i.e., the cap), cap-swaps do not qualify for designation as cash flow hedges (in accordance with SFAS 133) since the combination of the hedged item and the written put option does not provide as much potential for favorable cash flows as exposure to unfavorable cash flows.

•

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.

•

For call options, Chesapeake receives a cash premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, then Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.

•

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

Chesapeake enters into counter-swaps from time to time for the purpose of locking in the value of a swap. Under the counter-swap, Chesapeake receives a floating price for the hedged commodity and pays a fixed price to the counterparty. The counter-swap is 100% effective in locking in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap. We refer to this locked-in value as a locked swap. At the time Chesapeake enters into a counter-swap, Chesapeake removes the original swap’s designation as a cash flow hedge and classifies the original swap as a non-qualifying hedge under SFAS 133. The reason for this new designation is that collectively the swap and the counter-swap no longer hedge the exposure to variability in expected future cash flows. Instead, the swap and counter-swap effectively lock in a specific gain (or loss) that will be unaffected by subsequent variability in oil and gas prices. Any locked-in gain or loss is recorded in accumulated other comprehensive income and reclassified to oil and gas sales in the month of related production.

In accordance with FASB Interpretation No. 39, Chesapeake nets the value of its derivative arrangements with the same counterparty in the accompanying condensed consolidated balance sheets, to the extent that a legal right of setoff exists.

Gains or losses from derivative transactions are reflected as adjustments to oil and gas sales on the condensed consolidated statements of operations. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the condensed consolidated statements of operations as unrealized gains (losses) within oil and gas sales. Unrealized gains (losses) included in oil and gas sales in the Current Quarter and the Prior Quarter were ($14.0) million and $29.7 million, respectively.

Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and gas sales. We recorded a gain (loss) on ineffectiveness of ($7.2) million and $0.1 million in the Current Quarter and the Prior Quarter, respectively.

The estimated fair values of our oil and gas derivative instruments as of March 31, 2004 and December 31, 2003 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.


	March 31, 2004			December 31, 2003
	($ in thousands)
Derivative assets (liabilities):
Fixed-price gas swaps	$	(153,111	)	$	(44,794	)
Fixed-price gas cap-swaps		(41,057	)		(18,608	)
Gas basis protection swaps		72,276			46,205
Gas call options (a)		(19,206	)		(17,876	)
Fixed-price gas collars		(6,374	)		—
Fixed-price gas locked swaps		(3,929	)		1,777
Fixed-price crude oil cap-swaps		(17,711	)		(11,692	)

Estimated fair value	$	(169,112	)	$	(44,988	)

(a)	After adjusting for the remaining $14.6 million and $16.8 million premium paid to Chesapeake by the counterparty, the net value of the call options as of March 31, 2004 and December 31, 2003 was ($4.6) million and ($1.1) million, respectively.

Based upon the market prices as of March 31, 2004, we expect to transfer a loss of approximately $72.0 million from accumulated other comprehensive income (loss) to earnings during the next 12 months when the hedged transactions actually close. All hedged transactions as of March 31, 2004 are expected to mature by December 31, 2007, with the exception of the basis protection swaps which extend through 2009.

Interest Rate Derivatives

We also utilize hedging strategies to manage our exposure to changes in interest rates. By entering into interest rate swaps, we convert a portion of our fixed rate debt to floating rate debt. To the extent the interest rate swaps have been designated as fair value hedges, changes in the fair value of the derivative instrument and the corresponding debt are reflected as adjustments to interest expense in the corresponding months covered by the derivative agreement.

In January 2004, Chesapeake acquired a $50 million interest rate swap as part of the purchase of Concho Resources Inc. Under the terms of the interest rate swap, the counterparty pays a floating three month LIBOR rate and Chesapeake pays a fixed rate of 2.875%. Payments are made quarterly and the interest rate swap extends through September 2005. An initial liability of $0.6 million was recorded based on the fair value of the interest rate swap at the time of acquisition. As of March 31, 2004, the interest rate swap had a fair value of ($1.0) million. Because this instrument is not designated as a fair value hedge, an unrealized loss of $0.4 million was recognized in the Current Quarter as part of interest expense.

In April 2002, Chesapeake entered into a “swaption” with an unrelated counterparty with respect to its 8.5% senior notes due 2012. The notional amount of the swaption was $142.7 million. Under the swaption, the counterparty received the option to elect whether or not to enter into an interest rate swap with Chesapeake in March 2004, and Chesapeake received a $7.8 million cash payment. The interest rate swap, if executed by the counterparty, required Chesapeake to pay a fixed rate of 8.5% while the counterparty would pay Chesapeake a floating rate of 6 month LIBOR plus 0.75%. Additionally, if the counterparty were to elect to enter into the interest rate swap, it could also elect to force Chesapeake to settle the transaction at the then current estimated fair value of the interest rate swap.

On March 10, 2004, the counterparty exercised its option to enter into the interest rate swap effective March 15, 2004 and immediately cash settle at the estimated fair value of the interest rate swap. On March 16, 2004, Chesapeake and the counterparty agreed to increase the fixed rate payable by Chesapeake to 8.68% in exchange for the counterparty agreeing to not force settle the swap prior to March 15, 2005. The counterparty may elect to terminate the swap and cause it to be settled at the then current estimated fair value of the interest rate swap on March 15, 2005 and annually thereafter through March 15, 2011. The interest rate swap expires on March 15, 2012. Chesapeake may elect to terminate the swap and cause it to be settled at the then current estimated fair value of the interest rate swap at any time during the term of the swap. Changes in the value of the interest rate swap will be recorded as adjustments to interest expense.

As of March 31, 2004, the fair value of the interest rate swap which resulted from the exercise of the swaption was a liability of $40.7 million. Because the interest rate swap is not designated as a fair value hedge, changes in the fair value of the swap are recorded as adjustments to interest expense. The Current Quarter includes $7.7 million of unrealized interest expense and $0.2 million of realized interest expense.

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, excluding discounts for interest rate swaps and

the swaption, as of March 31, 2004 and December 31, 2003 was $2,012.1 million and $2,058.1 million, respectively, compared to approximate fair values of $2,236.8 million and $2,279.5 million, respectively. The carrying amounts for our 6.75% convertible preferred stock, 6.00% convertible preferred stock and 5.00% convertible preferred stock as of March 31, 2004 were $149.9 million, $230.0 million and $172.5 million, respectively, with a fair value of $265.3 million, $347.9 million and $189.8 million, respectively. The carrying amount and fair value for our 4.125% convertible preferred stock as of March 31, 2004 was $275.0 million.

Concentration of Credit Risk

A significant portion of our liquidity is concentrated in cash and cash equivalents and derivative instruments that enable us to hedge a portion of our exposure to price volatility from producing oil and natural gas. 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 equity instruments and accounts receivable. 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 generally exceed the federally insured limits.

3. Contingencies and Commitments

Litigation. Chesapeake is currently involved in various 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.

Employment Agreements with Officers. 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 January 1, 2004. The term of each agreement is automatically extended for one additional year on each January 31 unless the company provides 30 days prior notice of non-extension or the parties otherwise terminate the agreement. The agreements with the chief financial officer and other senior managers expire on September 30, 2006. The company’s employment agreements with the executive officers provide for payments in the event of a change in control. The chief executive officer and chief operating officer are each 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, and the chief financial officer and other officers are each entitled to receive a payment in the amount of two times the sum of his or her base compensation and bonuses paid during the prior year.

Environmental Risk. 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 conducts periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Depending on the extent of an identified environmental problem, Chesapeake may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property. Chesapeake has historically not experienced any significant environmental liability, and is not aware of any potential material environmental issues or claims as of March 31, 2004.

4. Net Income Per Share

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

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

•

For the Current Quarter and the Prior Quarter, outstanding warrants to purchase 0.4 million shares of common stock at a weighted-average exercise price of $14.55, were antidilutive because the exercise prices of the warrants were greater than the average market price of the common stock.

•

For the Current Quarter and the Prior Quarter, outstanding options to purchase 0.2 million and 0.4 million shares of common stock at a weighted-average exercise price of $21.05 and $14.84, respectively, were antidilutive because the exercise prices of the options were greater than the average market price of the common stock.

For the Current Quarter, the outstanding 275,000 shares of 4.125% cumulative convertible preferred stock were not considered to be convertible because the holders did not have the right to convert. A holder’s right to convert will only arise when the closing sales price of our common stock reaches, or the trading price of the preferred stock falls below, specified thresholds or upon the occurrence of specified corporate transactions.

Reconciliations for the quarters ended March 31, 2004 and 2003 are as follows:


	Income (Numerator)			Shares (Denominator)	Per Share Amount
	(in thousands, except per share data)
For the Quarter Ended March 31, 2004:
Basic EPS
Income available to common shareholders	$	104,422		236,884	$	0.44

Effect of Dilutive Securities
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 5.00% convertible preferred stock		—		10,516
Common shares assumed issued for 6.00% convertible preferred stock		—		22,358
Common shares assumed issued for 6.75% convertible preferred stock		—		19,467
Preferred stock dividends		8,168		—
Preferred stock dividend on 4.125% convertible preferred stock		(32	)	—
Restricted stock		—		153
Employee stock options		—		9,863

Diluted EPS Income available to common shareholders and assumed conversions	$	112,558		299,241	$	0.38

For the Quarter Ended March 31, 2003:
Income before cumulative effect of accounting change, net of tax	$	71,120
Preferred stock dividends		(3,526	)

Basic EPS Income available to common shareholders before cumulative effect of accounting change, net of tax	$	67,594		197,608	$	0.34

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

Diluted EPS Income available to common shareholders before cumulative effect of accounting change, net of tax	$	71,120		230,672	$	0.31

5. Notes Payable and Revolving Credit Facility

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


	March 31, 2004			December 31, 2003
	($ in thousands)
8.375% Senior Notes due 2008	$	209,815		$	209,815
8.125% Senior Notes due 2011		245,407			728,255
9.0% Senior Notes due 2012		300,000			300,000
7.5% Senior Notes due 2013		363,823			363,823
7.75% Senior Notes due 2015		300,408			236,691
6.875% Senior Notes due 2016		670,487			200,000
7.875% Senior Notes due 2004		—			42,137
8.5% Senior Notes due 2012		—			4,290
Discount on senior notes		(77,793	)		(26,959	)
Discount for interest rate swap and swaption		—			(339	)

Total notes payable and long-term debt	$	2,012,147		$	2,057,713

On January 14, 2004, we completed a public exchange offer in which we retired $458.5 million of our 8.125% Senior Notes due 2011 and $10.8 million of accrued interest and issued $72.8 million of our 7.75% Senior Notes due 2015 and $2.8 million of accrued interest and $433.5 million of our 6.875% Senior Notes due 2016 and $4.1 million of accrued interest. In connection with this exchange, we recorded a pre-tax charge of $6.0 million, consisting of a $5.7 million underwriters fee and $0.3 million in other transaction costs.

In January and February of 2004, we issued an additional $37.0 million of our 6.875% Senior Notes due 2016 and $0.5 million of accrued interest in exchange for $24.3 million of our 8.125% Senior Notes due 2011 and $0.7 million of accrued interest and $9.1 million of our 7.75% Senior Notes due 2015 and $0.1 million of accrued interest in four private exchange transactions.

On November 12, 2003, we commenced a tender offer to purchase for cash our $110.7 million aggregate principal amount of 8.5% Senior Notes due 2012 and concurrently conducted a consent solicitation to amend the indenture governing the 8.5% Senior Notes. On December 10, 2003, we purchased $106.4 million principal amount of 8.5% Senior Notes tendered, which represented approximately 96% of the outstanding aggregate principal amount of the 8.5% Senior Notes, and we amended the indentures eliminating substantially all of the restrictive covenants. We redeemed the remaining $4.3 million of 8.5% Senior Notes on March 15, 2004. In connection with the redemption, we recorded a pre-tax loss of $0.9 million, consisting of $0.2 million of redemption premium, $0.1 million of unamortized debt issue costs and discount on senior notes and $0.6 million carried as a discount on the 8.5% Senior Notes based on the hedging relationship between the notes and the swaption.

We paid $42.1 million representing the balance outstanding on our 7.875% Senior Notes that matured on March 15, 2004.

As of March 31, 2004, we had a $350 million revolving bank credit facility (with a committed borrowing base of $350 million) which was scheduled to mature in May 2007. As of March 31, 2004, we had no outstanding borrowings under this facility and utilized $76.9 million of the facility for various letters of credit. On May 7, 2004, we amended and restated our bank credit facility, increasing the borrowing base to $600 million, with commitments of $500 million, and extending the maturity to June 30, 2008. Borrowings under the facility are collateralized by certain producing oil and gas properties and bear interest at either (i) the greater of the reference rate of Union Bank of California, N.A. or the federal funds effective rate plus 0.50% or (ii) London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are redetermined periodically. The unused portion of the facility is subject to an annual commitment fee that also varies according to our senior unsecured long-term debt ratings. Currently the annual commitment fee rate is 0.375%. Interest is payable quarterly or, if LIBOR applies, it maybe payable at more frequent intervals.

The amended and restated credit facility agreement contains various covenants and restrictive provisions which govern our ability to incur additional indebtedness, sell properties, pay dividends, purchase or redeem our capital stock, make investments or loans, and create liens. The credit facility agreement requires us to maintain a current ratio (as defined) of at least 1 to 1 and a fixed charge coverage ratio (as defined) of at least 2.5 to 1. As of March 31, 2004, our current ratio was 1.56 to 1 and our fixed charge coverage ratio was 5.03 to 1. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million or more, would constitute an event of default under our

senior note indentures, which could in turn result in the acceleration of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $35.0 million.

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.

The senior note indentures permit us to redeem the senior notes at any time at specified make-whole or redemption prices. The indentures contain covenants limiting us and the 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; mergers or consolidations; and transactions with affiliates.

Set forth below are condensed consolidating financial statements of the parent, guarantor subsidiaries and the non-guarantors. Chesapeake Energy Marketing, Inc., Mayfield Processing, L.L.C. and MidCon Compression, L.P. are wholly owned subsidiaries which are not guarantors of the senior notes. Chesapeake Energy Marketing, Inc. was a non-guarantor subsidiary for all quarters presented. Mayfield Processing, L.L.C. and MidCon Compression, L.P. were established as non-guarantor subsidiaries during the third quarter of 2003. All of our other wholly-owned subsidiaries were guarantor subsidiaries during all periods presented.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF MARCH 31, 2004

($ in thousands)

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Parent			Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	404		$	46,323		$	142,698		$	—		$	189,425
Accounts receivable		225,088			149,282			3,413			(93,621	)		284,162
Deferred income tax asset		—			—			76,671			—			76,671
Inventory and other		19,978			1,217			15			—			21,210

Total Current Assets		245,470			196,822			222,797			(93,621	)		571,468

PROPERTY AND EQUIPMENT:
Evaluated oil and gas properties		7,012,420			—			—			—			7,012,420
Unevaluated leasehold		301,657			—			—			—			301,657
Other property and equipment		88,075			61,375			90,928			—			240,378
Less: accumulated depreciation, depletion and amortization		(2,632,872	)		(25,467	)		(7,193	)		—			(2,665,532	)

Net Property and Equipment		4,769,280			35,908			83,735			—			4,888,923

OTHER ASSETS:
Investments in subsidiaries and intercompany advances		—			—			1,539,977			(1,539,977	)		—
Long-term derivative instruments		15,385			—			—			—			15,385
Other assets		21,025			10			60,661			(10	)		81,686

Total Other Assets		36,410			10			1,600,638			(1,539,987	)		97,071

TOTAL ASSETS	$	5,051,160		$	232,740		$	1,907,170		$	(1,633,608	)	$	5,557,462

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	243,626		$	144,095		$	—		$	(140,829	)	$	246,892
Accrued interest		—			—			42,677			—			42,677
Short-term derivative instruments		161,948			—			40,658			—			202,606
Other accrued liabilities		93,736			7,247			16,646			222			117,851
Revenues and royalties due others		85,338			—			—			47,208			132,546

Total Current Liabilities		584,648			151,342			99,981			(93,399	)		742,572

OTHER LIABILITIES:
Long-term debt, net		—			—			2,012,147			—			2,012,147
Revenues and royalties due others		14,829			—			—			—			14,829
Asset retirement obligation		57,476			—			—			—			57,476
Long-term derivative instruments		19,623			—			—			—			19,623
Deferred income tax liability		223,084			4,122			141,602			—			368,808
Other liabilities		11,828			—			—			—			11,828
Intercompany payables (receivables)		2,678,136			(1,165	)		(2,676,739	)		(232	)		—

Total Other Liabilities		3,004,976			2,957			(522,990	)		(232	)		2,484,711

STOCKHOLDERS’ EQUITY:
Common stock		56			1			2,470			(57	)		2,470
Preferred stock		—			—			827,390			—			827,390
Other		1,461,480			78,440			1,500,319			(1,539,920	)		1,500,319

Total Stockholders’ Equity		1,461,536			78,441			2,330,179			(1,539,977	)		2,330,179

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	5,051,160		$	232,740		$	1,907,170		$	(1,633,608	)	$	5,557,462

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2003

($ in thousands)

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Parent			Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	248		$	32,131		$	8,202		$	—		$	40,581
Accounts receivable		181,538			127,717			11,000			(78,861	)		241,394
Short-term derivative receivable		1,777			—			—			—			1,777
Short-term derivative instruments		—			—			2,690			—			2,690
Deferred income tax asset		—			—			36,705			—			36,705
Inventory and other		17,368			1,770			119			—			19,257

Total Current Assets		200,931			161,618			58,716			(78,861	)		342,404

PROPERTY AND EQUIPMENT:
Evaluated oil and gas properties		6,221,576			—			—			—			6,221,576
Unevaluated leasehold		227,331			—			—			—			227,331
Other property and equipment		82,230			58,083			85,578			—			225,891
Less: accumulated depreciation, depletion and Amortization		(2,511,382	)		(23,982	)		(6,317	)		—			(2,541,681	)

Net Property and Equipment		4,019,755			34,101			79,261			—			4,133,117

OTHER ASSETS:
Investments in subsidiaries and intercompany advances		—			—			853,184			(853,184	)		—
Long-term derivative instruments		17,493			—			—			—			17,493
Long-term investments		5,000			—			26,544			—			31,544
Other assets		23,641			14			24,092			(14	)		47,733

Total Other Assets		46,134			14			903,820			(853,198	)		96,770

TOTAL ASSETS	$	4,266,820		$	195,733		$	1,041,797		$	(932,059	)	$	4,572,291

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	160,422		$	120,369		$	—		$	(116,527	)	$	164,264
Accrued interest		—			—			46,648			—			46,648
Short-term derivative instruments		60,050			—			32,601			—			92,651
Other accrued liabilities		86,759			5,553			15,751			(43	)		108,020
Revenues and royalties due others		63,907			—			—			37,666			101,573

Total Current Liabilities		371,138			125,922			95,000			(78,904	)		513,156

OTHER LIABILITIES:
Long-term debt, net		—			—			2,057,713			—			2,057,713
Revenues and royalties due others		13,921			—			—			—			13,921
Asset retirement obligation		48,812			—			—			—			48,812
Long-term derivative instruments		4,209			—			527			—			4,736
Deferred income tax liability (asset)		278,914			3,772			(91,660	)		—			191,026
Other liabilities		10,117			—			—			—			10,117
Intercompany payables (receivables)		2,753,590			(1,026	)		(2,752,593	)		29			—

Total Other Liabilities		3,109,563			2,746			(786,013	)		29			2,326,325

STOCKHOLDERS’ EQUITY:
Common stock		56			1			2,218			(57	)		2,218
Preferred stock		—			—			552,400			—			552,400
Other		786,063			67,064			1,178,192			(853,127	)		1,178,192

Total Stockholders’ Equity		786,119			67,065			1,732,810			(853,184	)		1,732,810

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	4,266,820		$	195,733		$	1,041,797		$	(932,059	)	$	4,572,291

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

($ in thousands)

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Parent			Eliminations			Consolidated
For the Three Months Ended March 31, 2004:
REVENUES:
Oil and gas sales	$	419,793		$	—		$	—		$	—		$	419,793
Oil and gas marketing sales		—			415,391			—			(272,055	)		143,336

Total Revenues		419,793			415,391			—			(272,055	)		563,129

OPERATING COSTS:
Production expenses		44,803			—			—			—			44,803
Production taxes		14,936			—			—			—			14,936
General and administrative expenses:
General and administrative (excluding stock-based compensation)		6,656			1,434			76			—			8,166
Stock based compensation		—			—			1,869			—			1,869
Oil and gas marketing expenses		—			411,719			—			(272,055	)		139,664
Oil and gas depreciation, depletion and amortization		119,908			—			—			—			119,908
Depreciation and amortization of other assets		2,658			1,468			1,613			—			5,739

Total Operating Costs		188,961			414,621			3,558			(272,055	)		335,085

INCOME (LOSS) FROM OPERATIONS		230,832			770			(3,558	)		—			228,044

OTHER INCOME (EXPENSE):
Interest and other income		548			200			42,015			(41,420	)		1,343
Interest expense		(38,234	)		—			(49,731	)		41,420			(46,545	)
Loss on repurchase or exchanges of Chesapeake debt		—			—			(6,925	)		—			(6,925	)
Equity in net earnings of subsidiaries		—			—			124,237			(124,237	)		—

Total Other Income (Expense)		(37,686	)		200			109,596			(124,237	)		(52,127	)

INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		193,146			970			106,038			(124,237	)		175,917
Income tax expense (benefit)		69,530			349			(6,552	)		—			63,327

NET INCOME	$	123,616		$	621		$	112,590		$	(124,237	)	$	112,590


	Guarantor Subsidiaries			Non-Guarantor Subsidiary			Parent			Eliminations			Consolidated
For the Three Months Ended March 31, 2003:
REVENUES:
Oil and gas sales	$	286,019		$	—		$	—		$	—		$	286,019
Oil and gas marketing sales		—			294,151			—			(203,843	)		90,308

Total Revenues		286,019			294,151			—			(203,843	)		376,327

OPERATING COSTS:
Production expenses		31,457			—			—			—			31,457
Production taxes		18,597			—			—			—			18,597
General and administrative		4,661			583			135			—			5,379
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
Provision for legal settlements		286			—			—			—			286

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

INCOME (LOSS) FROM OPERATIONS		152,106			(158	)		(996	)		—			150,952

OTHER INCOME (EXPENSE):
Interest and other income		18			94			35,665			(35,014	)		763
Interest expense		(33,834	)		—			(38,184	)		35,014			(37,004	)
Equity in net earnings of subsidiaries		—			—			75,688			(75,688	)		—

Total Other Income (Expense)		(33,816	)		94			73,169			(75,688	)		(36,241	)

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

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

($ in thousands)

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Parent			Eliminations			Consolidated
For the Three Months Ended March 31, 2004:
CASH FLOWS FROM OPERATING ACTIVITIES	$	365,221		$	(19,984	)	$	120,770		$	(124,237	)	$	341,770

CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net		(302,000	)		—			(415,784	)		—			(717,784	)
Additions to buildings and other fixed assets		(6,554	)		(3,184	)		(4,162	)		—			(13,900	)
Deposit on pending acquisition of Permian Resources		(3,750	)		—			—			—			(3,750	)

Cash (used in) provided by investing activities		(312,304	)		(3,184	)		(419,946	)		—			(735,434	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings		381,000			—			—			—			381,000
Payments on long-term borrowings		(381,000	)		—			—			—			(381,000	)
Proceeds from issuance of preferred stock, net of issuance costs		—			—			267,737			—			267,737
Proceeds from issuance of common stock, net of issuance costs		—			—			298,107			—			298,107
Cash paid to repurchase senior notes, including redemption premium		—			—			(57,271	)		—			(57,271	)
Cash paid for common and preferred stock dividends		—			—			(15,651	)		—			(15,651	)
Other financing costs		(41	)		—			(138	)		—			(179	)
Net increase in outstanding payments in excess of cash balances		46,809			—			250			—			47,059
Cash received from exercise of stock options		—			—			2,706			—			2,706
Intercompany advances, net		(99,529	)		37,360			(62,068	)		124,237			—

Cash provided by (used in) financing activities		(52,761	)		37,360			433,672			124,237			542,508

NET INCREASE IN CASH AND CASH EQUIVALENTS		156			14,192			134,496			—			148,844
CASH, BEGINNING OF PERIOD		248			32,131			8,202			—			40,581

CASH, END OF PERIOD	$	404		$	46,323		$	142,698		$	—		$	189,425


	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	)
Additions to buildings and other fixed assets and 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, net of costs		—			—			290,920			—			290,920
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 paid for treasury stock		—			—			(2,109	)		—			(2,109	)
Cash dividends paid on preferred stock and common stock		—			—			(8,235	)		—			(8,235	)
Exercise of stock options		—			—			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

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

($ in thousands)

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Parent			Eliminations			Consolidated
For the Three Months Ended March 31, 2004:
Net Income	$	123,616		$	621		$	112,590		$	(124,237	)	$	112,590
Other comprehensive income (loss) - net of income tax:
Change in fair value of derivative instruments		(65,430	)		—			—			—			(65,430	)
Reclassification of gain on settled contracts		(11,699	)		—			—			—			(11,699	)
Ineffective portion of derivatives qualifying for cash flow hedge accounting		4,607			—			—			—			4,607
Equity in net other comprehensive income (loss) of subsidiaries		—			—			(72,522	)		72,522			—

Comprehensive income	$	51,094		$	621		$	40,068		$	(51,715	)	$	40,068


	Guarantor Subsidiaries			Non-Guarantor Subsidiary			Parent			Eliminations			Consolidated
For the Three Months Ended March 31, 2003:
Net Income	$	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
Ineffective 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

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., Mayfield Processing, L.L.C. and MidCon Compression, L.P., which are our marketing subsidiaries, are the only non-guarantor subsidiaries. Chesapeake Energy Marketing, Inc. was a non-guarantor subsidiary for all quarters presented. Mayfield Processing, L.L.C. and MidCon Compression, L.P. were established as non-guarantor subsidiaries during the third quarter of 2003.

7. Acquisitions and Related Financing

We completed the acquisition of Concho Resources Inc. in January 2004 to acquire oil and gas interests primarily in the Permian Basin and the Mid-Continent. We paid $420 million in cash for these assets, $10 million of which was paid in 2003. We also paid $12 million in employee severance and other transaction costs at closing. We recorded a $117 million deferred tax liability to reflect the cost in excess of tax basis acquired. We also completed an acquisition of Texas Gulf Coast properties in January 2004. We paid $65 million for these assets, $3.3 million of which was paid in 2003.

On January 14, 2004, we issued 23,000,000 shares of common stock at a price to the public of $13.51 per share. We used the net proceeds of this offering of approximately $298.1 million to finance a portion of the acquisitions completed in January 2004.

On March 30, 2004, we issued 275,000 shares of 4.125% convertible preferred stock having a liquidation preference of $1,000 per share in a private placement. We used the net proceeds of this offering of approximately $267.7 million to pay the outstanding borrowings under our bank credit facility which were incurred to finance acquisitions completed in the Current Quarter. As of March 31, 2004, 16.5 million shares of common stock were reserved for issuance upon conversion of the 4.125% convertible preferred stock. In April 2004, the original purchasers exercised their option to purchase an additional 38,250 shares of 4.125% convertible preferred stock on the same terms and conditions for net proceeds of $37.2 million.

8. Subsequent Events

We completed an acquisition of oil and gas assets located in the Permian Basin from Permian Resources Holdings, Inc. in April 2004. We paid approximately $69 million for these assets.

In April 2004, the original purchasers of our 4.125% convertible preferred stock exercised their option to purchase an additional 38,250 shares at the original purchase price resulting in net proceeds of $37.2 million to Chesapeake.

On May 7, 2004, we entered into an agreement to acquire a privately-held oil and natural gas company for $425 million in cash. The acquisition is expected to close on June 1, 2004, and is subject to customary closing conditions. We intend to finance the transaction using our bank credit facility and using proceeds from a potential issuance of senior unsecured notes.

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,
	2004			2003
Net Production:
Oil (mbbl)		1,465			1,060
Gas (mmcf)		70,098			50,392
Gas equivalent (mmcfe)		78,888			56,752
Oil and Gas Sales ($ in thousands):
Oil sales	$	48,031		$	35,140
Oil derivatives – realized gains (losses)		(8,330	)		(6,238	)
Oil derivatives – unrealized gains (losses)		(6,019	)		(77	)

Total oil sales		33,682			28,825

Gas sales		360,101			314,050
Gas derivatives – realized gains (losses)		33,991			(86,620	)
Gas derivatives – unrealized gains (losses)		(7,981	)		29,764

Total gas sales		386,111			257,194

Total oil and gas sales	$	419,793		$	286,019

Average Sales Price (excluding all gains (losses) on derivatives):
Oil ($ per bbl)	$	32.79		$	33.15
Gas ($ per mcf)	$	5.14		$	6.23
Gas equivalent ($ per mcfe)	$	5.17		$	6.15
Average Sales Price (excluding unrealized gains (losses) on derivatives):
Oil ($ per bbl)	$	27.10		$	27.27
Gas ($ per mcf)	$	5.62		$	4.51
Gas equivalent ($ per mcfe)	$	5.50		$	4.52
Expenses ($ per mcfe):
Production expenses	$	0.57		$	0.55
Production taxes (a)	$	0.19		$	0.33
General and administrative expenses (excluding stock based compensation)	$	0.10		$	0.09
Depreciation, depletion and amortization	$	1.52		$	1.35
Interest expense (b)	$	0.48		$	0.62

Interest Expense ($ in thousands):
Interest expense	$	38,564		$	35,704
Interest derivatives – realized (gains) losses		(758	)		(674	)
Interest derivatives – unrealized (gains) losses		8,739			1,974

Total interest expense	$	46,545		$	37,004

Net Wells Drilled		109			94
Net Producing Wells as of the End of Period		6,661			5,326

(a)	Includes a pre-tax benefit of $6.8 million, or $0.09 per mcfe, from prior period severance tax credits.

(b)	Includes the effects of realized gains or (losses) from hedging, but does not include the effects of unrealized gains or (losses) from hedging.

Chesapeake is the largest producer of natural gas in the Mid-Continent and is among the six largest independent producers of natural gas in the U.S. As of March 31, 2004, we owned interests in approximately 17,000 (6,661 net) producing oil and gas wells. Our primary operating area is the Mid-Continent region of the United States, which includes Oklahoma, western Arkansas, southwestern Kansas and the Texas Panhandle, and we are building secondary operating areas in the Permian Basin of western Texas and eastern New Mexico and in the South Texas and Texas Gulf Coast regions.

Oil and natural gas production for the first quarter of 2004 was 78.9 bcfe, an increase of 22.1 bcfe, or 39%, over the 56.8 bcfe produced in the first quarter of 2003. Half of this year-over-year production growth was a result of organic drillbit growth and half was generated from acquisitions. We estimate our organic growth rate during the 12 months ended March 31, 2004 was 20%.

We have increased our production annually for 14 consecutive years, and the 2004 first quarter was Chesapeake’s eleventh consecutive quarter of sequential production growth. During these eleven quarters, Chesapeake’s production has increased 102%, for an average sequential quarterly growth rate of 6.6% and an average annualized growth rate of 29%.

In addition to increased oil and natural gas production, the prices we received were higher in the 2004 first quarter than in the 2003 first quarter. On a natural gas equivalent basis, weighted average prices (excluding the effect of unrealized gains or losses on derivatives) were $5.50 per mcfe in 2004 compared to $4.52 per mcfe in 2003. The increase in prices resulted in an increase in revenue of $77.4 million and increased production resulted in an increase in revenue of $100.1 million, for a total increase in revenue of $177.5 million (excluding the effect of unrealized gains or losses on derivatives).

During the 2004 first quarter, the company replaced its 78.9 bcfe of production by 473%, or 372.8 bcfe, at a drilling and acquisition cost of $1.66 per mcfe. Drillbit replacement was 146% and acquisition replacement was 327%. As of March 31, 2004, our estimated proved reserves were 3.5 tcfe.

Chesapeake drilled 118 (88 net) operated wells and participated in another 137 (21 net) wells operated by other companies during the 2004 first quarter. Chesapeake’s drilling costs were $129 million for operated wells and $47 million for non-operated wells. The company’s success rate was 92% for operated wells and 99% for non-operated wells. Our acquisition expenditures totaled $482 million during the quarter (primarily in two transactions involving payments of $410 million and $62 million).

Our revenues, operating results, profitability and future growth depend on our ability to find, develop and acquire oil and gas reserves that are economically recoverable based on prevailing prices for natural gas and oil. The company favors gas over oil, strives to establish regional dominance in our operating areas, has grown through a combination of drilling and acquisitions and manages price risk through opportunistic commodities hedging.

To date in 2004, we have raised $298 million of common equity and $305 million of preferred equity (4.125% convertible preferred stock). As of March 31, 2004, the company’s total debt as a percentage of total capitalization (total capitalization is the sum of total debt and stockholders’ equity) was 46%, compared to 65% as of January 1, 2003. Additionally, through debt repurchases and exchanges completed in the second half of 2003 and the first quarter of 2004, we have extended the average maturity of our long-term debt to over nine years and have lowered our average interest rate to 7.7%.

We intend to continue to focus on improving the strength of our balance sheet. The company’s secured credit facility is currently rated as investment grade by at least two rating agencies. We believe our business strategy and operational performance will lead to an investment grade credit rating for our unsecured debt in the future.

Recent Developments

Liquidity and Capital Resources

Sources of Liquidity

Our primary source of liquidity to meet operating expenses and fund capital expenditures (other than for large acquisitions) is cash flow from operations. Based on our current production, price and expense assumptions, we expect cash flow from operations will exceed our drilling capital expenditures in 2004. Our budget for drilling, land and seismic activities for 2004 is currently between $850 million and $900 million. While we believe this level of exploration and development will be sufficient to increase our reserves in 2004 and achieve our target of a 20% increase in production over 2003 production (inclusive of acquisitions completed through April 2004), higher drilling and field operating costs, drilling results that alter planned development schedules, acquisitions or other factors could cause us to revise our drilling program, which is largely discretionary. Any cash flow from operations not needed to fund our drilling program will be available for acquisitions, debt repayment or other general corporate purposes in 2004.

Cash flows from operating activities (exclusive of changes in assets and liabilities) were $333.6 million in the Current Quarter, compared to $167.7 million in the Prior Quarter. The $165.9 million increase in the Current Quarter was primarily due to higher realized prices and higher volumes of oil and gas production. We expect that

2004 production volumes will be higher than in 2003 and that cash flows from operating activities in 2004 will exceed 2003 levels. While a precipitous decline in gas prices in 2004 would significantly affect the amount of cash flow that would be generated from operations, we have 97% of our expected oil production remaining in 2004 hedged at an average NYMEX price of $30.14 per barrel of oil and 63% of our expected natural gas production remaining in 2004 hedged at an average NYMEX price of $5.09 per mcf. This level of hedging provides certainty of the cash flow we will receive for a substantial portion of our remaining 2004 production. Depending on changes in oil and gas futures markets and management’s view of underlying oil and natural gas supply and demand trends, however, we may increase or decrease our current hedging positions.

Another source of liquidity is our $350 million revolving bank credit facility (with a committed borrowing base of $350 million) which matures in May 2007. As of March 31, 2004, we had no indebtedness under the bank credit facility. We use the facility to fund daily operating activities and acquisitions as needed. We borrowed and repaid $381.0 million in the Current Quarter and $139.0 million in Prior Quarter under the facility.

We believe that our available cash, cash flows from operating activities and funds available under our bank credit facility will be sufficient to fund our operating, interest and general and administrative expenses, our capital expenditure budget, our short-term contractual obligations and dividend payments at current levels for the foreseeable future.

The public markets have been our principal source of capital to finance large acquisitions. We have sold debt and equity in both public and private offerings in the past, and we expect that these sources of capital will continue to be available to us in the future for acquisitions. Nevertheless, we caution you that ready access to capital on reasonable terms and the availability of desirable acquisition targets at attractive prices are subject to many uncertainties, as explained under “Risk Factors” in Item 1—Business of our Form 10-K for the year ended December 31, 2003. The following table reflects the proceeds from sales of securities we issued in the Current Quarter and the Prior Quarter ($ in millions):


	For the Three Months Ended March 31,
	2004				2003
	Total Proceeds		Net Proceeds		Total Proceeds		Net Proceeds
Convertible preferred stock	$	275.0	$	267.7	$	230.0	$	222.9
Common stock		310.7		298.1		186.3		177.5
Unsecured senior notes guaranteed by subsidiaries		—		—		300.0		290.9

Total	$	585.7	$	565.8	$	716.3	$	691.3

We filed a $600 million “universal shelf” registration statement with the Securities and Exchange Commission on April 27, 2004. Securities issued under this shelf may be in the form of common stock, preferred stock, depository shares representing fractional shares of preferred stock or debt securities of Chesapeake, which will be guaranteed by certain Chesapeake subsidiaries. The net proceeds from a sale of securities from this shelf, which is expected to occur from time to time over the next two years, would be used for future business acquisitions and other general corporate purposes, including the retirement of existing debt. A prospectus supplement will be prepared at the time of a debt or equity offering and will contain specific information about the security issued and the use of proceeds.

We paid common stock dividends of $7.6 million and $5.7 million in the Current Quarter and in the Prior Quarter, respectively, and we paid dividends of $8.1 million and $2.5 million on our preferred stock in the Current Quarter and in the Prior Quarter, respectively. We received $2.7 million and $1.5 million from the exercise of employee and director stock options in the Current Quarter and in the Prior Quarter, respectively. We used $2.1 million to purchase treasury stock in the Prior Quarter to fund our matching contributions to the 401(k) Make-Up Plan.

Historically, we have used significant amounts of funds to purchase and retire our obligations under outstanding Senior Notes. In March 2004, we retired $42.1 million of our 7.875% Senior Notes at maturity and we redeemed the remaining $4.3 million of our 8.5% Senior Notes for $4.5 million, including redemption premium of $0.2 million. We paid $4.6 million for cash in lieu of issuing fractional notes on our exchange of $458.5 million of 8.125% Senior Notes for $72.8 million of 7.75% Senior Notes and $433.5 million of 6.875% Senior Notes in January 2004 and paid $6.0 million in transaction costs related to this exchange. In the fourth quarter of 2003, we purchased and subsequently retired $106.4 million of our 8.5% Senior Notes for $113.1 million, including redemption premium of $6.7 million.

Cash used in investing activities decreased to $735.4 million during the Current Quarter, compared to $1,002.3 million during the Prior Quarter. The following table shows our capital expenditures during these quarters ($ in millions):


	Three Months Ended March 31,
	2004			2003
Acquisitions of oil and gas properties and companies	$	482.2		$	819.1
Exploration and development drilling		235.9			154.6
Deposit on pending acquisition of Permian Resources		3.8			—
Investment in securities of other companies		—			20.0
Drilling rigs, plants and gathering systems		3.4			1.2
Office buildings and other administrative		10.5			8.2
Divestitures of oil and gas properties and other		(0.4	)		(0.8	)

Total	$	735.4		$	1,002.3

Our accounts receivable are primarily from purchasers of oil and natural gas ($205.8 million as of March 31, 2004) and exploration and production companies which own interests in properties we operate ($40.4 million as of March 31, 2004). This 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.

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.

Investing and Financing Transactions

The following describes significant investing and financing transactions that we completed in the Current Quarter and through the filing date:

Investing Transactions:

April 2004

•

Acquired Permian Resources Holdings, Inc. - Permian Basin oil and gas assets for cash consideration of approximately $69 million

First Quarter 2004

•

Acquired Concho Resources Inc. - Permian Basin and Mid-Continent oil and gas assets for cash consideration of approximately $420 million, of which $10 million was paid in 2003. We also paid $12 million in employee severance and other transactional costs at closing.

•

Acquired Texas Gulf Coast properties for cash consideration of approximately $65 million, of which $3.3 million was paid in 2003

Financing Transactions:

April 2004

•

Issued an additional 38,250 shares of 4.125% convertible preferred stock upon exercise of an option we granted to the original purchasers in a private placement of such stock completed in March 2004 for net proceeds of $37.2 million

First Quarter 2004

•

Completed a public offering of 23 million shares of common stock at $13.51 per share. We used the net proceeds of this offering of approximately $298.1 million to finance a portion of the acquisitions completed in January 2004

•

Issued 275,000 shares of 4.125% convertible preferred stock at $1,000 per share. We used the net proceeds of this offering of approximately $267.7 million to pay outstanding borrowings under our credit facility which were incurred as a result of acquisitions completed in the Current Quarter

•

Completed a public exchange offer in which we retired $458.5 million of our 8.125% Senior Notes due 2011 and $10.8 million of accrued interest and issued $72.8 million of our 7.75% Senior Notes due 2015 and $2.8 million of accrued interest and $433.5 million of our 6.875% Senior Notes due 2016 and $4.1 million of accrued interest

•

Issued an additional $37.0 million of our 6.875% Senior Notes due 2016 and $0.5 million of accrued interest in exchange for $24.3 million of our 8.125% Senior Notes due 2011 and $0.7 million of accrued interest and $9.1 million of our 7.75% Senior Notes due 2015 and $0.1 million of accrued interest in four private exchange transactions

•

Paid $4.5 million (including a premium of $0.2 million) to redeem $4.3 million of 8.5% Senior Notes due 2012 representing all outstanding notes which were not tendered pursuant to a cash tender offer completed in December 2003

•

Paid $42.1 million representing the balance outstanding on our 7.875% Senior Notes that matured on March 15, 2004

Contractual Obligations

As of March 31, 2004, we had a $350 million revolving bank credit facility (with a committed borrowing base of $350 million) which was scheduled to mature in May 2007. As of March 31, 2004, we had no outstanding borrowings under this facility and had utilized $76.9 million of the facility for various letters of credit. On May 7, 2004, we amended and restated our bank credit facility, increasing the borrowing base to $600 million, with commitments of $500 million, and extending the maturity to June 30, 2008. Borrowings under the facility are collateralized by certain producing oil and gas properties and bear interest at either (i) the greater of the reference rate of Union Bank of California, N.A., or the federal funds effective rate plus 0.50% or (ii) London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are redetermined periodically. The unused portion of the facility is subject to an annual commitment fee that also varies according to our senior unsecured long-term debt ratings. Currently the annual commitment fee rate is 0.375%. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The credit facility agreement contains various covenants and restrictive provisions which govern our ability to incur additional indebtedness, sell properties, pay dividends, purchase or redeem our capital stock, make investments or loans, and create liens. In addition, the agreement requires us to maintain a current ratio (as defined) of at least 1 to 1 and a fixed charge coverage ratio (as defined) of at least 2.5 to 1. As of March 31, 2004, our current ratio was 1.56 to 1 and our fixed charge coverage ratio was 5.03 to 1. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million or more, would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $35.0 million.

As of March 31, 2004, senior notes of approximately $2.0 billion represented all of our long-term debt and consisted of the following ($ in thousands):


8.375% senior notes due 2008	$	209,815
8.125% senior notes due 2011		245,407
9.0% senior notes due 2012		300,000
7.5% senior notes due 2013		363,823
7.75% senior notes due 2015		300,408
6.875% senior notes due 2016		670,487
Discount on senior notes		(77,793	)

	$	2,012,147

No scheduled principal payments are required on any of the senior notes until 2008, when $209.8 million is due. Debt ratings for the senior notes are Ba3 by Moody’s Investor Service, BB- by Standard & Poor’s Ratings Services and BB by Fitch Ratings. Debt ratings for our secured bank credit facility are Ba2 by Moody’s Investor Service, BBB- by Standard & Poor’s Ratings Services and BBB- 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., Mayfield Processing, L.L.C. and MidCon Compression, L.P. guarantee the notes. The indentures permit us to redeem the senior notes at any time at specified make-whole or redemption prices. The indentures 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, 2004, we estimate that secured commercial bank indebtedness of approximately $1,385.6 million could have been incurred under the most restrictive indenture covenant. The indenture covenants do not apply to our non-guarantor subsidiaries.

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 exceed certain levels. As of March 31, 2004, we were required to post $75.0 million of collateral and as of May 5, 2004 we were required to post $86.0 million of collateral with respect to these commodity price and financial risk management transactions. 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.

Results of Operations — Three Months Ended March 31, 2004 (“Current Quarter”) vs. March 31, 2003 (“Prior Quarter”)

General. For the Current Quarter, Chesapeake had net income of $112.6 million, or $0.38 per diluted common share, on total revenues of $563.1 million. This compares to net income of $73.5 million, or $0.32 per diluted common share, on total revenues of $376.3 million during the Prior Quarter. The Current Quarter net income includes, on a pre-tax basis, a $6.9 million loss on repurchases or exchanges of debt and $22.7 million in net unrealized losses on oil and gas and interest rate derivatives. The Prior Quarter net income included, on a pre-tax basis, $27.7 million in net unrealized gains on oil and gas and interest rate derivatives.

Oil and Gas Sales. During the Current Quarter, oil and gas sales were $419.8 million compared to $286.0 million in the Prior Quarter. In the Current Quarter, Chesapeake produced 78.9 bcfe at a weighted average price of $5.50 per mcfe, compared to 56.8 bcfe produced in the Prior Quarter at a weighted average price of $4.52 per mcfe (weighted average prices for both quarters discussed exclude the effect of unrealized gains or losses on derivatives). The increase in prices in the Current Quarter resulted in an increase in revenue of $77.4 million and increased production resulted in a $100.1 million increase, for a total increase in revenues of $177.5 million (excluding unrealized gains or losses on oil and gas derivatives). The increase in production from the Prior Quarter to the Current Quarter is due to the combination of production growth generated from drilling as well as acquisitions completed in 2003 and the Current Quarter.

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 $0.10 per mcf of gas produced would result in an increase or decrease in revenues and cash flow of approximately $7.0 million and $6.7 million, respectively, and a change of $1.00 per barrel of oil produced would result in an increase or decrease in revenues and cash flows of approximately $1.5 million and $1.4 million, respectively, without considering the effect of derivative activities.

For the Current Quarter, we realized an average price per barrel of oil of $27.10, compared to $27.27 in the Prior Quarter (weighted average prices for both quarters discussed exclude the effect of unrealized gains or losses on derivatives). Natural gas prices realized per mcf (excluding unrealized gains or losses on derivatives) were $5.62 and $4.51 in the Current Quarter and Prior Quarter, respectively. Realized gains or losses from our oil and gas derivatives resulted in a net increase in oil and gas revenues of $25.7 million or $0.33 per mcfe in the Current Quarter and a net decrease of $92.9 million or $1.64 per mcfe in the Prior Quarter.

Oil and gas sales were also affected by unrealized gains or losses on oil and gas derivatives. The unrealized amounts included in oil and gas sales were a loss of $14.0 million in the Current Quarter and a gain of $29.7 million 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,
	2004			2003
	Mmcfe	Percent		Mmcfe	Percent
Mid-Continent	62,704	79	%	48,781	86	%
South Texas and Texas Gulf Coast	10,208	13		5,348	9
Permian Basin	5,298	7		1,849	3
Williston Basin and Other	678	1		774	2

Total Production	78,888	100	%	56,752	100	%

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

Oil and Gas Marketing Sales. Chesapeake realized $143.3 million in oil and gas marketing sales for third parties in the Current Quarter, with corresponding oil and gas marketing expenses of $139.7 million, for a net margin of $3.6 million. Marketing activities are substantially for third parties that are owners in Chesapeake operated wells. This compares to sales of $90.3 million, expenses of $89.4 million and a net margin of $0.9 million in the Prior Quarter. In the Current Quarter, Chesapeake realized an increase in volumes of oil and gas marketing sales which was partially offset by a decrease in oil and gas prices.

Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $44.8 million in the Current Quarter compared to $31.5 million in the Prior Quarter. On a unit-of-production basis, production expenses were $0.57 per mcfe in the Current Quarter compared to $0.55 per mcfe in the Prior Quarter. The increase in the Current Quarter was primarily due to higher field service costs. We expect that production expenses per mcfe during the remainder of 2004 will range from $0.55 to $0.60.

Production Taxes. Production taxes were $14.9 million and $18.6 million in the Current Quarter and the Prior Quarter, respectively. On a unit-of-production basis, production taxes were $0.19 per mcfe in the Current Quarter compared to $0.33 per mcfe in the Prior Quarter. Included in the Current Quarter is a credit of $6.8 million related to certain Oklahoma severance tax abatements for the period July 2003 through December 2003, and a $4.8 million credit for the period January 2004 through March 2004. In April 2004, the Oklahoma Tax Commission concluded that a pre-determined oil and gas price cap for 2003 sales had not been exceeded (on a statewide basis) and notified the company that it was eligible to receive certain severance tax abatements for the period from July 1, 2003 through June 30, 2004. The company had previously estimated that the average oil and gas sales prices in Oklahoma (on a statewide basis) could exceed the price cap, and did not reflect the benefit from these potential severance tax abatements until the Current Quarter. The decrease in production taxes in the Current Quarter is partially offset by an increase of approximately $7.9 million due to increased production. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil and gas prices are higher. We expect production taxes per mcfe to range from $0.28 to $0.32 during the remainder of 2004 based on an assumption that oil and natural gas wellhead prices range from $4.50 to $5.00 per mcfe.

General and Administrative Expenses (excluding stock based compensation). General and administrative expenses, which are net of internal payroll and non-payroll costs capitalized in our oil and gas properties, were $8.2 million in the Current Quarter and $5.4 million in the Prior Quarter. The increase in the Current Quarter of $2.8 is the result of additional costs associated with the company’s growth through various acquisitions in 2003 and the Current Quarter. This growth has resulted in a substantial increase in employees and related costs. We anticipate that general and administrative expenses for 2004 will be between $0.10 and $0.11 per mcfe produced, which is approximately the same level as the Current Quarter.

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 $10.9 million and $7.3 million of internal costs in the Current Quarter and the Prior Quarter, respectively, directly related to our oil and gas exploration and development efforts.

Stock Based Compensation. During the Current Quarter, 1.1 million shares of restricted stock were issued to employees as a result of Chesapeake’s normal compensation review process. The cost of these shares is amortized over a four-year period which resulted in the recognition of $1.9 million of stock based compensation expense in the Current Quarter. There was no such cost in the Prior Quarter. We anticipate that stock based compensation expense for 2004 will be between $0.02 and $0.03 per mcfe produced, which is approximately the same level as the Current Quarter.

Provision for Legal Settlements. We entered into a settlement agreement, effective December 31, 2003, to resolve a legal proceeding brought against us by certain royalty owners. Under the terms of the settlement, we will refund Oklahoma royalty owners $10.5 million, including interest. The refund amount includes $3.6 million relating to marketing fees which we have previously paid into the court ($0.3 million in the Prior Quarter and $3.3 million in 2002). In the third and fourth quarter 2003, we accrued an aggregate $6.9 million related to the settlement.

Oil and Gas Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of oil and gas properties was $119.9 million and $76.6 million during the Current Quarter and the Prior Quarter, respectively. The average DD&A rate per mcfe, which is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented, was $1.52 and $1.35 in the Current Quarter and in the Prior Quarter, respectively. We expect the DD&A rate for the remainder of 2004 to be between $1.52 and $1.60 per mcfe produced. The increase in the average rate from $1.35 to $1.52 is primarily the result of higher drilling costs and higher costs associated with acquisitions.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $5.7 million in the Current Quarter, compared to $3.7 million in the Prior Quarter. The increase in the Current Quarter was primarily the result of higher depreciation costs resulting from the acquisition of a processing plant, various gathering facilities, construction of new buildings at our corporate headquarters and the purchase of additional information technology equipment and software. Other property and equipment costs are depreciated on a straight-line basis. Buildings are depreciated over 39 years, drilling rigs are depreciated over 15 years and all other property and equipment are depreciated over the estimated useful lives of the assets, which range from two to fifteen years. To the extent 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 $0.07 and $0.09 per mcfe produced for the remainder of 2004.

Interest and Other Income. Interest and other income was $1.3 million and $0.8 million in the Current Quarter and the Prior Quarter, respectively. The Current Quarter income consisted of $0.4 million of interest income, $0.4 million related to earnings of equity investees, and $0.5 million of miscellaneous income. The Prior Quarter income consisted of $0.5 million of interest income and $0.3 million of miscellaneous income.

Interest Expense. Interest expense increased to $46.5 million in the Current Quarter, compared to $37.0 million in the Prior Quarter. The increase in the Current Quarter is due to a $351.8 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 $5.3 million of interest during the Current Quarter compared to $1.9 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 effective interest rate on our outstanding borrowings. We expect 2004 interest expense to be between $0.45 and $0.50 per mcfe produced.

From time to time, we enter into derivative instruments designed to mitigate our exposure to the volatility in interest rates. For interest rate derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value of interest rate derivatives are recorded on the consolidated balance sheets as assets (liabilities) and the debt’s carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Any resulting differences are recorded currently as ineffectiveness in the consolidated statements of operations as an adjustment to interest expense. Included in interest expense in the Current Quarter are a realized gain of $0.8 million related to interest rate derivatives and an unrealized loss on interest rate derivatives of $8.7 million. Included in interest expense in the Prior Quarter are a realized gain of $0.7 million related to interest rate derivatives and an unrealized loss on interest rate derivatives of $2.0 million. A detailed explanation of our interest rate hedging appears below in Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Loss on Repurchases or Exchanges of Debt. In the Current Quarter, we completed a public exchange offer in which we retired $458.5 million of our 8.125% Senior Notes due 2011 and $10.8 million of accrued interest and issued $72.8 million of our 7.75% Senior Notes due 2015 and $2.8 million of accrued interest and $433.5 million of our 6.875% Senior Notes due 2016 and $4.1 million of accrued interest. In connection with this exchange, we recorded a pre-tax loss of $6.0 million, consisting of $5.7 million of underwriting fees and $0.3 million in other transaction costs. During the Current Quarter, we redeemed $4.3 million of our 8.5% Senior Notes due 2012 for a total consideration of $4.5 million. In connection with this transaction, we recorded a pre-tax loss of $0.9 million, consisting of $0.2 million of redemption premium, $0.1 million of unamortized debt issue costs and discount on senior notes and $0.6 million carried as a discount on the 8.5% Senior Notes based on the hedging relationship between the notes and the swaption.

Provision (Benefit) for Income Taxes. Chesapeake recorded income tax expense of $63.3 million in the Current Quarter, compared to income tax expense of $43.6 million in the Prior Quarter. During the Current Quarter, our effective income tax rate decreased to 36% to reflect our assessment of the impact state income taxes have on our overall effective tax rate.

Cumulative Effect of Accounting Change. Effective January 1, 2003, Chesapeake adopted SFAS No. 143, Accounting For Asset Retirement Obligations. Upon adoption of SFAS 143 in the Prior Quarter, we recorded the discounted fair value of our expected future obligations of $30.5 million, a cumulative effect of 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.

Critical Accounting Policies

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 in our 2003 Form 10-K and include:

•

the volatility of oil and gas prices,

•

our substantial indebtedness,

•

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,

•

losses possible from pending or future litigation, and

•

the loss of officers or key employees.

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

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Oil and Gas Hedging Activities

•

do not qualify for designation as cash flow hedges (in accordance with SFAS 133) since the combination of the hedged item and the written put option do not provide as much potential for favorable cash flows as exposure to unfavorable cash flows.

•

In accordance with FASB Interpretation No. 39, Chesapeake nets the value of its derivative arrangements with the same counterparty in the accompanying consolidated balance sheets, to the extent that a legal right of setoff exists.

Gains or losses from derivative transactions are reflected as adjustments to oil and gas sales on the consolidated statements of operations. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the consolidated statements of operations as unrealized gains (losses) within oil and gas sales. Unrealized gains (losses) included in oil and gas sales in the Current Quarter and the Prior Quarter were ($14.0) million and $29.7 million, respectively.

As of March 31, 2004, 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 2004:


	Volume mmbtu/bbls	Weighted- Average Strike Price	Weighted- Average Put Strike Price	Weighted- Average Call Strike Price	Weighted Average Differential		SFAS 133 Hedge	Premiums Received		Fair Value at March 31, 2004 (in thousands)
Natural Gas (mmbtu):

Swaps:
2004	99,790,000	4.91	—	—	—		Yes	$	—	$	(100,678	)
2005	42,850,000	4.80	—	—	—		Yes		—		(36,654	)
2006	25,550,000	4.74	—	—	—		Yes		—		(10,949	)
2007	25,550,000	4.76	—	—	—		Yes		—		(4,830	)

Basis Protection Swaps:
2004	118,250,000	—	—	—	(0.17	)	No		—		19,160
2005	109,500,000	—	—	—	(0.16	)	No		—		19,282
2006	47,450,000	—	—	—	(0.16	)	No		—		7,793
2007	63,875,000	—	—	—	(0.17	)	No		—		10,719
2008	64,050,000	—	—	—	(0.17	)	No		—		9,844
2009	36,500,000	—	—	—	(0.16	)	No		—		5,478

Cap-Swaps:
2004	27,055,000	5.25	3.80	—	—		No		—		(21,050	)
2005	38,325,000	5.33	3.84	—	—		No		—		(18,574	)
2006	7,300,000	5.36	3.75	—	—		No		—		(1,433	)

Call Options:
2004	52,570,000	—	—	6.24	—		No		14,566		(19,206	)

Collars:
2004	3,635,000	—	3.10	4.44	—		Yes		—		(3,618	)
2005	4,745,000	—	3.10	4.44	—		Yes		—		(2,756	)

Locked Swaps:
2004	—	5.42	—	—	—		No		—		(2,485	)
2005	—	5.74	—	—	—		No		—		(1,444	)

Total Gas									14,566		(151,401	)


Oil (bbls):

Cap-Swaps:
2004	3,658,500	29.44	22.30	—	—		No		—		(17,467	)
2005	547,500	31.56	26.00	—	—		No		—		(244	)

Total Oil									—		(17,711	)

Total Gas and Oil								$	14,566	$	(169,112	)

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 as of March 31, 2004.

Based upon the market prices as of March 31, 2004, we expect to transfer approximately $72.0 million of the loss included in the balance in accumulated other comprehensive income (loss) to earnings during the next 12 months when the hedged transactions actually occur. All hedged transactions as of March 31, 2004 are expected to mature by December 31, 2007, with the exception of the basis protection swaps which extend through 2009.

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


	2004
	($ in thousands)
Fair value of contracts outstanding as of January 1	$	(44,988	)
Change in fair value of contracts during the quarter		(98,463	)
Contracts realized or otherwise settled during the quarter		(25,661	)
Fair value of new contracts when entered into during the quarter		—
Fair value of contracts when closed during the quarter		—

Fair value of contracts outstanding as of March 31	$	(169,112	)

The change in the fair value of our derivative instruments since January 1, 2004 resulted from an increase in market prices for natural gas and crude oil relative to the hedged price. 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 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, 2004
	Years of Maturity
	2004		2005		2006		2007		2008			Thereafter			Total			Fair Value
	($ in millions)
Liabilities:
Long-term debt, including current portion — fixed rate	$	—	$	—	$	—	$	—	$	209.8		$	1,880.1		$	2,089.9	⁽¹⁾	$	2,236.8
Average interest rate		—		—		—		—		8.4	%		7.6	%		7.7	%		7.7	%

(1)	This amount does not include the discount included in long-term debt of ($77.8) million.

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

Interest Rate Derivatives

In January 2004, Chesapeake acquired a $50 million interest rate swap as part of the purchase of Concho Resources Inc. Under the terms of the interest rate swap, the counterparty pays a floating three month LIBOR rate and Chesapeake pays a fixed rate of 2.875%. Payments are made quarterly and the interest rate extends through September 2005. An initial liability of $0.6 million was recorded based on the fair value of the interest rate swap at the time of acquisition. As of March 31, 2004, the interest rate swap had a fair value of ($1.0) million. Because this instrument is not designated as a fair value hedge, an unrealized loss of $0.4 million was recognized in the Current Quarter.

ITEM

4. Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of March 31, 2004, have concluded the company’s disclosure controls and procedures are effective. No changes in the company’s internal control over financial reporting occurred during the Current Quarter that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Chesapeake is currently involved in various disputes incidental to its business operations. Management 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.

Item 2. Changes in Securities and Use of Proceeds

(a) On November 12, 2003, we commenced a tender offer to purchase for cash our $110,669,000 aggregate principal amount of 8.5% Senior Notes due 2012 and concurrently conducted a consent solicitation to amend the indenture governing the 8.5% Senior Notes. We purchased all of the $106,379,000 8.5% Senior Notes tendered on or prior to December 10, 2003, the expiration date, which represented approximately 96% of the outstanding aggregate principal amount of the 8.5% Senior Notes, and amended the indenture eliminating substantially all of the restrictive covenants. We redeemed all remaining 8.5% Senior Notes that were not tendered pursuant to the tender offer on March 15, 2004.

(c) On March 30, 2004, we completed a private sale of 255,000 shares of 4.125% Cumulative Convertible Preferred Stock (liquidation preference $1,000 per share) to Lehman Brothers Inc., Banc of America Securities LLC, Bear, Stearns & Co. Inc., Credit Suisse First Boston LLC and the several other investment banking firms named as purchasers in the Purchase Agreement for the transaction. On April 5, 2004, we sold an additional 38,250 shares of preferred stock to these purchasers pursuant to an option we had granted to them. The purchasers resold the shares pursuant to Rule 144A under the Securities Act of 1933, as amended, at the liquidation preference. The aggregate offering price was $293.3 million, the aggregate discount to the initial purchasers was $8.1 million, and net proceeds to us, after expenses, were $284.9 million. On March 30, 2004, Aubrey K. McClendon, our chief executive officer, and Tom L. Ward, our chief operating officer, each purchased an additional 10,000 shares of preferred stock directly from us in a separate concurrent private placement at the same price offered to investors in the Rule 144A offering, resulting in additional proceeds to us of $20 million.

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

Each share of preferred stock is convertible initially into 60.0555 shares of common stock (which is calculated using an initial conversion price of $16.6513 per share of common stock), subject to adjustment upon the occurrence of certain events. A holder’s right to convert will arise only when the closing sale price of our common stock reaches, or the trading price of the preferred stock falls below, specified thresholds or upon the occurrence of specified corporate transactions.

At any time on or after March 15, 2009, 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 $1,000 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. In addition, if there are less than 25,000 shares of preferred stock outstanding, we may, at any time on or after March 15, 2009, at our option, cause each share of preferred stock to be automatically converted into that number of shares of common stock equal to $1,000 divided by the lesser of (i) the then prevailing conversion price and (ii) the market value at the time.

Upon a change of control (as defined in the certificate of designation for the preferred stock), holders of preferred stock will, if the market value of our common stock at such time is less than the conversion price, have a one-time option to convert all of their shares of preferred stock into shares of common stock at an adjusted conversion price equal to the greater of (i) the market value of the common stock as of the change of control date and (ii) $8.0733. 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 of such common stock otherwise issuable.

(e) The following table presents information about repurchases of our common stock during the three months ended March 31, 2004:


Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid Per Share		Total Expended		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs ⁽²⁾
January 1, 2004 through January 31, 2004	65,008	$	13.37	$	869,157	—	—
February 1, 2004 through February 29, 2004	36,580	$	12.54		458,713	—	—
March 1, 2004 through March 31, 2004	33,251	$	13.22		439,578	—	—

Total	134,839	$	13.11	$	1,767,448	—	—

(1)	Shares purchased on the open market for our matching contribution to the company’s 401(k) plan.

(2)

We make matching contributions to our 401(k) plan and 401(k) make-up plan using Chesapeake common stock which is purchased by the respective plan trustees on the open market in accordance with the plans. The plans contain no limitation on the number of shares that may be purchased for purposes of company contributions. There are no other repurchase plans or programs currently authorized by the Board of Directors.

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 the Certificates of Designation for the Series A Junior Participating Preferred Stock, 6.75% Cumulative Convertible Preferred Stock, 6.0% Cumulative Convertible Preferred Stock, 5.0% Cumulative Convertible Preferred Stock and 4.125% Cumulative Convertible Preferred Stock.

4.8		Fourth Amended and Restated Credit Agreement, dated as of May 7, 2004, among Chesapeake Energy Corporation, Chesapeake Exploration Limited Partnership, as Borrower, Union Bank of California, N.A., as Administrative Agent and Collateral Agent, BNP Paribas and SunTrust Bank, as Co-Syndication Agents, Calyon New York Branch and Comerica Bank, as Co-Documentation Agents, Bank of Scotland, Washington Mutual Bank and Bank of America, as Co-Agents, and the several lenders from time to time parties thereto.

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

21		Subsidiaries of Chesapeake.

31.1		Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Marcus C. Rowland, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Aubrey K. McClendon Chairman and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Marcus C. Rowland, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Furnished as provided in Item 601 of Regulation S-K.

(b) Reports on Form 8-K

During the quarter ended March 31, 2004, we filed the following current reports on Form 8-K:

On January 7, 2004, we filed a current report on Form 8-K, furnishing under Items 9 and 12 a press release we issued on January 7, 2004 announcing a public offering of our common stock. We also furnished the preliminary prospectus supplement dated January 7, 2004 for the offering and related prospectus dated October 23, 2003 and noted information contained in the preliminary prospectus regarding fourth quarter 2003 charges. In addition, we filed the press release and preliminary prospectus supplement and prospectus under Item 7.

On January 9, 2004, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on January 8, 2004 announcing the pricing of our public offering of 20 million shares of common stock.

On January 12, 2004, we filed a current report on Form 8-K, reporting under Item 5 that we entered into an underwriting agreement on January 8, 2004 with Lehman Brothers Inc., Banc of America Securities LLC, Morgan Stanley & Co. Incorporated, and others in connection with the issuance and sale of 20,000,000 shares of our common stock. In addition, we filed the underwriting agreement under Item 7.

On January 12, 2004, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on January 12, 2004 announcing the receipt of valid tenders of approximately $457.1 million principal amount of our 8.125% senior notes due 2011 pursuant to our previously announced exchange offer.

On January 14, 2004, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on January 13, 2004 announcing the expiration of our exchange offer for our 8.125% senior notes due 2011 and receipt of tenders of a total of approximately $458.5 million principal amount of such notes.

On January 16, 2004, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on January 15, 2004 announcing the closing of our public offering of common stock and our exchange offer for our 8.125% senior notes due 2011.

On January 29, 2004, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on January 28, 2004 announcing our fourth quarter and full year 2003 earnings release and conference call dates.

On February 3, 2004, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on February 2, 2004 announcing the completion of acquisitions of $510 million of Mid-Continent, Permian Basin, South Texas and onshore Gulf Coast natural gas reserves.

On February 24, 2004, we filed a current report on Form 8-K, furnishing under Item 9 and Item 12 a press release we issued on February 23, 2004 announcing financial and operating results for the fourth quarter and full year 2003 and updated 2004 guidance.

On March 9, 2004, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on March 8, 2004 announcing the declaration of quarterly common and preferred stock dividends.

On March 25, 2004, we filed a current report on Form 8-K, reporting under Item 5 that we issued two press releases on March 23, 2004 announcing a private offering of $255 million of cumulative convertible preferred stock, agreements to acquire $100 million of producing properties and updated hedging positions. In addition, we furnished under Item 9 additional information concerning the proposed acquisitions and our hedging positions and updated 2004 guidance. We filed both press releases under Item 7.

On March 25, 2004, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on March 24, 2004 announcing the pricing of our private offering of 4.125% Cumulative Convertible Preferred Stock.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


CHESAPEAKE ENERGY CORPORATION
(Registrant)

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

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

Date: May 10, 2004

INDEX TO EXHIBITS


Exhibit Number		Description
3.1		Chesapeake’s Restated Certificate of Incorporation, together with the Certificates of Designation for the Series A Junior Participating Preferred Stock, 6.75% Cumulative Convertible Preferred Stock, 6.0% Cumulative Convertible Preferred Stock, 5.0% Cumulative Convertible Preferred Stock and 4.125% Cumulative Convertible Preferred Stock.

4.8		Fourth Amended and Restated Credit Agreement, dated as of May 7, 2004, among Chesapeake Energy Corporation, Chesapeake Exploration Limited Partnership, as Borrower, Union Bank of California, N.A., as Administrative Agent and Collateral Agent, BNP Paribas and SunTrust Bank, as Co-Syndication Agents, Calyon New York Branch and Comerica Bank, as Co-Documentation Agents, Bank of Scotland, Washington Mutual Bank and Bank of America, as Co-Agents, and the several lenders from time to time parties thereto.

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

21		Subsidiaries of Chesapeake.

31.1		Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Marcus C. Rowland, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Aubrey K. McClendon Chairman and Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Marcus C. Rowland, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Furnished as provided in Item 601 of Regulation S-K.

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