Expand Energy (EXE) 8-K Index to Financial Statements

Exhibit 99

INDEX TO FINANCIAL STATEMENTS

CHESAPEAKE ENERGY CORPORATION

	Page
Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm	2
Consolidated Balance Sheets at December 31, 2003 and 2002	3
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001	4
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001	5
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2003, 2002 and 2001	7
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2003, 2002 and 2001	8
Notes to Consolidated Financial Statements	9
Financial Statement Schedules:
Schedule II—Valuation and Qualifying Accounts	57

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

of Chesapeake Energy Corporation

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Chesapeake Energy Corporation and its subsidiaries (the “Company”) at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule also listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, in 2001 the Company changed its method of accounting for its hedging activities as a result of adopting the provisions of Statement of Financial Accounting Standards No. 133“Accounting for Derivative Instruments and Hedging Activities”.

As discussed in Note 12 to the consolidated financial statements, effective January 1, 2003, the Company changed the manner in which it accounts for asset retirement obligations.

PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

February 29, 2004, except for Note 8, as to which the date is November 30, 2004

2

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2003			2002
	($ in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	40,581		$	247,637
Restricted cash		—			82
Accounts receivable:
Oil and gas sales		173,792			109,246
Joint interest, net of allowances of $2,669,000 and $1,433,000, respectively		37,789			22,760
Short-term derivatives		1,777			16,498
Related parties		2,983			2,155
Other		26,830			13,471
Deferred income tax asset		36,705			8,109
Short-term derivative instruments		2,690			—
Inventory and other		19,257			15,359
Total Current Assets		342,404			435,317
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties		6,221,576			4,334,833
Unevaluated properties		227,331			72,506
Less: accumulated depreciation, depletion and amortization		(2,480,261	)		(2,123,773	)
		3,968,646			2,283,566
Other property and equipment		225,891			154,092
Less: accumulated depreciation and amortization		(61,420	)		(47,774	)
Total Property and Equipment		4,133,117			2,389,884
OTHER ASSETS:
Long-term derivative instruments		17,493			2,666
Long-term investments		31,544			9,075
Other assets		47,733			38,666
Total Other Assets		96,770			50,407
TOTAL ASSETS	$	4,572,291		$	2,875,608
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	164,264		$	86,001
Accrued interest		46,648			35,025
Short-term derivative instruments		92,651			33,697
Other accrued liabilities		108,020			56,465
Revenues and royalties due others		101,573			54,364
Total Current Liabilities		513,156			265,552
LONG-TERM LIABILITIES:
Long-term debt, net		2,057,713			1,651,198
Revenues and royalties due others		13,921			13,797
Asset retirement obligation		48,812			—
Long-term derivative instruments		4,736			30,174
Deferred income tax liability		191,026			—
Other liabilities		10,117			7,012
Total Long-term Liabilities		2,326,325			1,702,181
CONTINGENCIES AND COMMITMENTS (Note 4)
STOCKHOLDERS’ EQUITY:
Preferred Stock, $.01 par value, 10,000,000 shares authorized:
6.75% cumulative convertible preferred stock, 2,998,000 issued and outstanding at December 31, 2003 and 2002, entitled in liquidation to $149,900,000		149,900			149,900
6.00% cumulative convertible preferred stock, 4,600,000 and 0 shares issued and outstanding at December 31, 2003 and 2002, respectively, entitled in liquidation to $230,000,000		230,000			—
5.00% cumulative convertible preferred stock, 1,725,000 and 0 shares issued and outstanding at December 31, 2003 and 2002, respectively, entitled in liquidation to $172,500,000		172,500			—
Common Stock, $.01 par value, 350,000,000 shares authorized, 221,855,894 and 194,936,912 shares issued at December 31, 2003 and 2002, respectively		2,218			1,949
Paid-in capital		1,389,212			1,205,554
Accumulated deficit		(168,617	)		(426,085	)
Accumulated other comprehensive income (loss), net of tax of $12,449,000 and $2,307,000, respectively		(20,312	)		(3,461	)
Less: treasury stock, at cost; 5,071,571 and 4,792,529 common shares at December 31, 2003 and 2002, respectively		(22,091	)		(19,982	)
Total Stockholders’ Equity		1,732,810			907,875
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	4,572,291		$	2,875,608

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

3

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2003			2002			2001
	(in thousands, except per share data)
REVENUES:
Oil and gas sales	$	1,296,822		$	568,187		$	820,318
Oil and gas marketing sales		420,610			170,315			148,733
Total Revenues		1,717,432			738,502			969,051
OPERATING COSTS:
Production expenses		137,583			98,191			75,374
Production taxes		77,893			30,101			33,010
General and administrative		23,753			17,618			14,449
Oil and gas marketing expenses		410,288			165,736			144,373
Oil and gas depreciation, depletion and amortization		369,465			221,189			172,902
Depreciation and amortization of other assets		16,793			14,009			8,663
Provision for legal settlements		6,402			—			—
Total Operating Costs		1,042,177			546,844			448,771
INCOME FROM OPERATIONS		675,255			191,658			520,280
OTHER INCOME (EXPENSE):
Interest and other income		2,827			7,340			2,877
Interest expense		(154,356	)		(112,031	)		(98,321	)
Loss on investment in Seven Seas		(2,015	)		(17,201	)		—
Loss on repurchases of Chesapeake debt		(20,759	)		(2,626	)		(76,667	)
Impairments of investments in securities		—			—			(10,079	)
Gain on sale of Canadian subsidiary		—			—			27,000
Gothic standby credit facility costs		—			—			(3,392	)
Total Other Income (Expense)		(174,303	)		(124,518	)		(158,582	)
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		500,952			67,140			361,698
INCOME TAX EXPENSE:
Current		5,000			(1,822	)		3,565
Deferred		185,360			28,676			140,727
Total Income Tax Expense		190,360			26,854			144,292
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX		310,592			40,286			217,406
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF INCOME TAXES OF $1,464,000		2,389			—			—
NET INCOME		312,981			40,286			217,406
PREFERRED STOCK DIVIDENDS		(22,469	)		(10,117	)		(2,050	)
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$	290,512		$	30,169		$	215,356
EARNINGS PER COMMON SHARE – BASIC:
Income before cumulative effect of accounting change	$	1.36		$	0.18		$	1.33
Cumulative effect of accounting change		0.02			—			—
	$	1.38		$	0.18		$	1.33
EARNINGS PER COMMON SHARE – ASSUMING DILUTION:
Income before cumulative effect of accounting change	$	1.20		$	0.17		$	1.25
Cumulative effect of accounting change		0.01			—			—
	$	1.21		$	0.17		$	1.25
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING(in thousands):
Basic		211,203			166,910			162,362
Assuming dilution		258,567			172,714			173,981

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

4

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2003			2002			2001
	($ in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$	312,981		$	40,286		$	217,406
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization		382,004			230,236			177,543
Deferred income taxes		186,664			28,676			138,831
Loss on repurchases of Chesapeake debt		20,759			2,626			76,667
Amortization of loan costs and bond discount		5,861			6,041			5,084
Unrealized (gains) losses on derivatives		(3,992	)		88,018			(84,789	)
Cumulative effect of accounting change		(3,853	)		—			—
Loss on investment in Seven Seas		2,015			17,201			—
Impairment of investments		—			—			10,079
Gain on sale of Canadian subsidiary		—			—			(27,000	)
Write-off of credit facility costs		—			—			3,392
Other		1,490			(567	)		1,350
Cash provided by operating activities before changes in assets and liabilities		903,929			412,517			518,563
CHANGES IN ASSETS AND LIABILITIES:
(Increase) decrease in accounts receivable		(72,683	)		(44,966	)		34,265
(Increase) decrease in inventory and other assets		(10,971	)		11,330			929
Increase (decrease) in accounts payable, accrued liabilities and other		86,861			23,223			2,454
Increase (decrease) in current and non-current revenues and royalties due others		38,466			30,427			(2,474	)
Changes in assets and liabilities		41,673			20,014			35,174
Cash provided by operating activities		945,602			432,531			553,737
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil and gas companies, proved properties and unproved properties, net of cash acquired		(1,261,275	)		(331,651	)		(316,743	)
Exploration and development of oil and gas properties		(727,231	)		(400,180	)		(420,969	)
Additions to buildings and other fixed assets		(71,454	)		(33,559	)		(24,853	)
Additions to long-term investments		(30,750	)		(2,408	)		(40,239	)
Divestitures of oil and gas properties		22,156			839			1,432
Deposits for Concho, South Texas assets and ONEOK acquisitions		(13,250	)		(15,000	)		—
Sale of non-oil and gas assets and recoveries of investments		5,799			5,774			3,204
Additions to drilling rig equipment		(1,221	)		(3,551	)		(14,145	)
Sale of Canadian subsidiary		—			—			142,906
Other		9			(9	)		(698	)
Cash used in investing activities		(2,077,217	)		(779,745	)		(670,105	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings		738,000			252,500			433,500
Payments on long-term borrowings		(738,000	)		(252,500	)		(458,500	)
Cash received from issuance of senior notes, net of offering costs		485,445			439,427			1,028,275
Proceeds from issuance of preferred stock, net of offering costs		390,365			—			145,086
Proceeds from issuance of common stock, net of offering costs		177,427			164,104			—
Cash paid to purchase senior notes, including redemption premium		(113,074	)		(111,597	)		(906,021	)
Cash paid for common stock dividend		(27,253	)		(4,987	)		—
Cash paid for preferred stock dividend		(20,916	)		(10,177	)		(1,092	)
Cash paid for financing cost of credit facilities		(2,474	)		(2,902	)		(6,611	)
Cash paid for treasury stock and preferred stock		(2,109	)		—			(10	)
Net increase in outstanding payments in excess of cash balance		28,315			—			—
Other financing costs		(496	)		(421	)		—
Cash received (paid) in settlements of make-whole provisions		—			—			(3,336	)
Cash received from exercise of stock options		9,329			3,810			3,216
Cash provided by financing activities		924,559			477,257			234,507
EFFECT OF EXCHANGE RATE CHANGES ON CASH		—			—			(545	)
Net increase (decrease) in cash and cash equivalents		(207,056	)		130,043			117,594
Cash and cash equivalents, beginning of period		247,637			117,594			—
Cash and cash equivalents, end of period	$	40,581		$	247,637		$	117,594

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

5

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)

	Years Ended December 31,
	2003		2002			2001
	($ in thousands)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION CASH PAYMENTS FOR:
Interest, net of capitalized interest	$	137,146	$	105,671		$	97,832
Income taxes, net of refunds received	$	5,160	$	(738	)	$	5,461
DETAILS OF ACQUISITION OF GOTHIC ENERGY CORPORATION:
Fair value of properties acquired	$	—	$	—		$	371,371
Stock issued (13,553,276 shares)	$	—	$	—		$	(28,000	)
Gothic preferred and common stock held by Chesapeake	$	—	$	—		$	(10,000	)
Debt assumed	$	—	$	—		$	(331,255	)
Acquisition costs and other	$	—	$	—		$	(2,116	)

SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:

In 2003, we issued $86.7 million of our 7.75% senior notes due 2015, $63.8 million of our 7.50% senior notes due 2013 and accrued interest of $1.0 million in exchange for $71.7 million of our 8.125% senior notes due 2011, $40.2 million of our 8.375% senior notes due 2008, $32.0 million of our 8.5% senior notes due 2012 and $2.2 million of our accrued interest, pursuant to privately negotiated transactions. The $71.7 million of our 8.125% senior notes, $40.2 of our 8.375% senior notes and $32.0 million of our 8.5% senior notes were retired upon receipt.

As of December 31, 2003, 2002 and 2001, dividends payable on our common and preferred stock were $15.7 million, $8.2 million, and $0, respectively.

During 2003, 2002 and 2001, $18.1 million, $1.0 million, and $13.3 million, respectively, of additions to oil and gas properties were recorded as an increase to accrued exploration and development costs.

In January 2003, Chesapeake adopted SFAS 143,Accounting For Asset Retirement Obligations. As a result, during the year ended December 31, 2003, we recorded non-cash additions to net oil and gas properties of $49.5 million.

In 2002, holders of our 6.75% cumulative convertible preferred stock converted 2,000 shares into 12,987 shares of common stock (at a conversion price of $7.70 per share).

In 2001, holders of our 7% cumulative convertible preferred stock converted 622,768 shares into 4,480,171 shares of common stock (at a conversion price of $6.95 per share), and we redeemed the remaining 1,269 shares of preferred stock for 7,239 shares of common stock and $3,000 of cash (at a redemption price of $52.45 per share, paid in 5.7 shares of common stock and cash of $2.45).

In 2001, Chesapeake completed the acquisition of Gothic Energy Corporation. We issued 3,989,813 shares of Chesapeake common stock to Gothic shareholders (other than Chesapeake).

In 2001, we issued 1,117,216 shares of Chesapeake common stock in exchange for 49.5% of RAM Energy, Inc.’s outstanding common stock. Chesapeake shares were valued at $8.854 per share. Subsequently, we made a make-whole payment to the former RAM shareholders of $3.3 million.

In 2001, Chesapeake purchased certain oil and gas assets from RAM Energy, Inc. for a total consideration of $74.4 million, consisting of $61.7 million of cash, surrender of $11.5 million principal amount of our RAM notes including $0.4 million in accrued interest, and cancellation of a $1.2 million receivable by us from RAM.

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

6

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Years Ended December 31,
	2003			2002			2001
	($ in thousands)
PREFERRED STOCK:
Balance, beginning of period	$	149,900		$	150,000		$	31,202
Issuance of 6.00% cumulative convertible preferred stock		230,000			—			—
Issuance of 5.00% cumulative convertible preferred stock		172,500			—			—
Exchange of common stock for 2,000 and 624,037 shares of preferred stock		—			(100	)		(31,202	)
Issuance of 6.75% cumulative convertible preferred stock		—			—			150,000
Balance, end of period		552,400			149,900			150,000
COMMON STOCK:
Balance, beginning of period		1,949			1,696			1,578
Exercise of stock options and warrants		39			23			21
Issuance of 23,000,000 shares of common stock		230			230			—
Issuance of 3,989,813 shares of common stock to Gothic shareholders		—			—			40
Issuance of 1,117,216 shares of common stock to RAM Energy, Inc. shareholders		—			—			11
Exchange of 4,487,410 shares of common stock for preferred stock		—			—			45
Other		—			—			1
Balance, end of period		2,218			1,949			1,696
PAID-IN CAPITAL:
Balance, beginning of period		1,205,554			1,035,156			963,584
Exercise of stock options and warrants		9,290			3,787			3,188
Issuance of common stock		186,070			172,270			—
Issuance of common stock to acquire RAM Energy, Inc. common stock		—			—			9,881
Issuance of common stock to acquire Gothic Energy Corporation		—			—			29,389
Offering expenses		(21,139	)		(8,506	)		(4,891	)
Exchange of 12,987 and 4,487,410 shares of common stock for preferred stock		—			100			31,157
Make-whole payments on common stock issued to RAM Energy, Inc. shareholders		—			—			(3,336	)
Compensation costs related to stock and stock options		2,292			356			800
Tax benefit from exercise of stock options		7,145			2,391			5,384
Balance, end of period		1,389,212			1,205,554			1,035,156
ACCUMULATED DEFICIT:
Balance, beginning of period		(426,085	)		(442,974	)		(659,286	)
Net income		312,981			40,286			217,406
Dividends on common stock		(29,128	)		(10,690	)		—
Dividends on preferred stock		(26,385	)		(12,707	)		(1,094	)
Balance, end of period		(168,617	)		(426,085	)		(442,974	)
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance, beginning of period		(3,461	)		43,511			(3,901	)
Foreign currency translation adjustments		—			—			(3,551	)
Transfer of translation adjustments related to sale of Canadian subsidiary		—			—			7,452
Gain/(loss) on hedging activity		(16,851	)		(46,972	)		43,511
Balance, end of period		(20,312	)		(3,461	)		43,511
TREASURY STOCK—COMMON:
Balance, beginning of period		(19,982	)		(19,982	)		(19,945	)
Exercised options		—			—			(37	)
Purchase of 279,042 shares of treasury stock		(2,109	)		—			—
Balance, end of period		(22,091	)		(19,982	)		(19,982	)
TOTAL STOCKHOLDERS’ EQUITY	$	1,732,810		$	907,875		$	767,407

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

7

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Years Ended December 31,
	2003			2002			2001
	($ in thousands)
NET INCOME	$	312,981		$	40,286		$	217,406
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments, net of income taxes of ($15,272), ($18,027) and $98,140		(24,917	)		(27,041	)		147,210
Reclassification of (gain) loss on settled contracts, net of income taxes of $1,448, ($14,711) and ($32,415)		2,363			(22,066	)		(48,623	)
Ineffective portion of derivatives qualifying for hedge accounting, net of income taxes of $3,495, $1,423 and ($1,002)		5,703			2,135			(1,503	)
Foreign currency translation adjustments, net of income taxes of ($2,367)		—			—			(3,551	)
Transfer of translation adjustments related to sale of Canadian subsidiary, net of income taxes of $4,968		—			—			7,452
Cumulative effect of accounting change for financial derivatives, net of income taxes of ($35,715)		—			—			(53,573	)
Comprehensive income (loss)	$	296,130		$	(6,686	)	$	264,818

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

8

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

Chesapeake Energy Corporation is an oil and natural gas exploration and production company engaged in the acquisition, exploration, and development of properties for the production of crude oil and natural gas from underground reservoirs and the marketing of natural gas and oil for other working interest owners in properties we operate. Our properties are located in Oklahoma, Texas, Arkansas, Louisiana, Kansas, Montana, Colorado, North Dakota and New Mexico.

Principles of Consolidation

The accompanying consolidated financial statements of Chesapeake Energy Corporation include the accounts of our direct and indirect wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Investments in companies and partnerships which give us significant influence, but not control, over the investee are accounted for using the equity method. Other investments are generally carried at cost.

Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Cash Equivalents

For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with maturities of three months or less at date of purchase to be cash equivalents.

Restricted Cash

Chesapeake classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. The restricted cash balance at December 31, 2003 and 2002 was $0 and $82,000 respectively.

Inventory

Inventory, which is included in current assets, consists primarily of tubular goods and other lease and well equipment which we plan to utilize in our ongoing exploration and development activities and is carried at the lower of cost or market using the specific identification method. Oil inventory in tanks is carried at the lower of the estimated cost to produce or market value.

Oil and Gas Properties

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 (see note 11). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and gas reserves. As of December 31, 2003, approximately 74% of our present value (discounted at 10%) of estimated future net revenues of proved

9

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

reserves was evaluated by independent petroleum engineers, with the balance evaluated by our internal reservoir engineers. In addition, our internal engineers evaluate all properties quarterly. The average composite rates used for depreciation, depletion and amortization were $1.38 (U.S.) per equivalent mcfe in 2003, $1.22 (U.S.) per equivalent mcfe in 2002, and $1.07 ($1.08 in U.S. and $0.90 in Canada) per equivalent mcfe in 2001.

Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved properties, in which case a gain or loss is recognized. No income is recognized in connection with contractual services provided by Chesapeake on properties in which we hold an economic interest.

The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred. Unevaluated properties are grouped by major prospect area where individual property costs are not significant and are assessed individually when individual costs are significant.

We review the carrying value of our oil and gas properties under the full-cost accounting rules of the Securities and Exchange Commission on a quarterly basis. Under these rules, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects.

Leasehold Costs

Statement of Financial Accounting Standards No. 141,Business Combinations and Statement of Financial Accounting Standards No. 142,Goodwill and Intangible Assets were issued by the Financial Accounting Standards Board in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment.

The Emerging Issues Task Forces (EITF) is considering two issues related to the reporting of oil and gas mineral rights. 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 are subject to the classification and disclosure provisions of SFAS 142 if they are intangible assets.

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 $227.3 million and $72.5 million would be classified on our consolidated balance sheets as “intangible undeveloped leasehold” and $1.4 billion and $532.8 million would be classified as “intangible developed leasehold” as of December 31, 2003 and 2002, respectively. These amounts are net of accumulated DD&A. There would be no effect on the 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.

10

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Asset Retirement Obligations

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

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

Other Property and Equipment

Other property and equipment consists primarily of gas gathering and processing facilities, drilling rigs, vehicles, land, office buildings and equipment, and software. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operations. Other property and equipment costs are depreciated on a straight-line basis. A summary of other property and equipment and the useful lives are as follows:

	December 31,
	2003		2002		Useful Life
	(in thousands)				(in years)
Land	$	11,777	$	9,000	N/A
Buildings and improvements		74,272		50,269	15 – 39
Gathering, processing and compression equipment		58,083		30,818	7 – 15
Other fixtures and equipment		55,477		38,943	2 –   7
Drilling rigs		26,282		25,062	15
Total	$	225,891	$	154,092

Debt Issue Costs

Included in other assets are costs associated with the issuance of our senior notes and costs associated with our revolving bank credit facility. The remaining unamortized debt issue costs at December 31, 2003 and 2002 totaled $28.4 million and $21.5 million, respectively, and are being amortized over the life of the senior notes or revolving credit facility.

Capitalized Interest

During 2003, 2002 and 2001, interest of approximately $13.0 million, $5.0 million and $4.7 million, respectively, was capitalized on significant investments in unproved properties that were not being currently depreciated, depleted or amortized and on which exploration activities were in progress. Interest is capitalized using the weighted average interest rate on our outstanding borrowings.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Income Taxes

Chesapeake has adopted Statement of Financial Accounting Standards No. 109,Accounting for Income Taxes. SFAS 109 requires deferred tax liabilities or assets to be recognized for the anticipated future tax effects of temporary differences that arise as a result of the differences in the carrying amounts and the tax bases of assets and liabilities.

Net Income (Loss) Per Share

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

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

• For the years ended December 31, 2003, 2002 and 2001, outstanding warrants to purchase 0.4 million, 0.6 million and 1.1 million shares of common stock at a weighted average exercise price of $14.55, $14.51 and $12.61, respectively, were antidilutive because the exercise prices of the warrants were greater than the average market price of the common stock.

• For the years ended December 31, 2003, 2002 and 2001, outstanding options to purchase 1.9 million, 0.6 million and 0.3 million shares of common stock at a weighted average exercise price of $11.15, $11.93 and $15.54, respectively, were antidilutive because the exercise prices of the options were greater than the average market price of the common stock.

• For the year ended December 31, 2002, diluted shares do not include the assumed conversion of the outstanding 6.75% preferred stock (convertible into 19.5 million common shares), and the common stock equivalent of preferred stock outstanding prior to conversion (convertible into 5,693 shares) as the effects were antidilutive.

12

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A reconciliation for the years ended December 31, 2003, 2002 and 2001 is as follows:

	Income (Numerator)			Shares (Denominator)	Per Share Amount
	(in thousands, except per share data)
For the Year Ended December 31, 2003:
Income before cumulative effect of accounting change, net of tax	$	310,592
Preferred stock dividends		(22,469	)
Basic EPS Income available to common shareholders before cumulative effect of accounting change, net of tax	$	288,123		211,203	$	1.36
Effect of Dilutive Securities
Assumed conversion at the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 5.00% convertible preferred stock		—		1,441
Common shares assumed issued for 6.00% convertible preferred stock		—		18,499
Common shares assumed issued for 6.75% convertible preferred stock		—		19,467
Preferred stock dividends		22,469		—
Employee stock options		—		7,957
Diluted EPS Income available to common shareholders before cumulative effect of accounting change, net of tax	$	310,592		258,567	$	1.20
For the Year Ended December 31, 2002:
Basic EPS Income available to common shareholders	$	30,169		166,910	$	0.18
Effect of Dilutive Securities
Employee stock options		—		5,797
Warrants assumed in Gothic acquisition		—		7
Diluted EPS Income available to common shareholders	$	30,169		172,714	$	0.17
For the Year Ended December 31, 2001:
Basic EPS Income available to common shareholders	$	215,356		162,362	$	1.33
Effect of Dilutive Securities
Assumed conversion at the beginning of the period of preferred shares exchanged during the period:
Common shares assumed issued for 6.75% convertible preferred stock		—		2,989
Common shares assumed issued prior to conversion for 7% convertible preferred stock		—		1,464
Preferred stock dividends		2,050		—
Employee stock options		—		7,160
Warrants assumed in Gothic acquisition		—		6
Diluted EPS Income available to common shareholders	$	217,406		173,981	$	1.25

13

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On January 14, 2004, we issued 23,000,000 shares of common stock at a price to the public of $13.51 per share.

On November 12, 2003, we issued 1,725,000 shares of 5% cumulative convertible preferred stock, par value $0.01 per share and liquidation preference $100 per share, in a public offering.

On March 5, 2003, we issued 4,600,000 shares of 6% cumulative convertible preferred stock, par value $0.01 per share and liquidation preference $50 per share, in a private offering. We subsequently registered, under the Securities Act of 1933, the shares of the preferred stock and underlying common stock for resale by the holders.

On March 5, 2003, we issued 23,000,000 shares of Chesapeake common stock at $8.10 per share in a public offering.

On December 18, 2002, we issued 23,000,000 shares of common stock at $7.50 per share in a public offering.

On November 13, 2001, we issued 3,000,000 shares of 6.75% cumulative convertible preferred stock, par value $0.01 per share and liquidation preference $50 per share, in a private offering. As of December 31, 2003, 2,998,000 shares remain outstanding. We subsequently registered, under the Securities Act of 1933, the shares of the preferred stock and underlying common stock for resale by the holders.

In 2001, holders of our 7% cumulative convertible preferred stock converted 622,768 shares into 4,480,171 shares of common stock (at a conversion price of $6.95 per share), and we redeemed the remaining 1,269 shares of 7% preferred stock for 7,239 shares of common stock and $3,000 of cash (at a redemption price of $52.45 per share, paid in 5.7 shares of common stock and cash of $2.45).

Revenue Recognition

Gas Imbalances. We follow the “sales method” of accounting for our gas revenue whereby we recognize sales revenue on all gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset and a liability is recognized to the extent that we have an imbalance in excess of the remaining gas reserves on the underlying properties. The gas imbalance asset and liability at December 31, 2003 and 2002 were not significant.

Oil and Natural Gas Sales. Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.

Marketing Sales. Chesapeake takes title to the natural gas it purchases from other working interest owners in operated wells and arranges for transportation and delivers the natural gas to third parties, at which time revenues are recorded. Chesapeake’s results of operations related to its oil and gas marketing activities are presented on a “gross” basis, because we act as a principal rather than an agent. All significant intercompany accounts and transactions have been eliminated. Only sales to third parties are reflected in the consolidated statements of operations.

Hedging

From time to time, Chesapeake uses commodity price and financial risk management instruments to mitigate our exposure to price fluctuations in oil and natural gas transactions and interest rates. Recognized gains and losses on derivative contracts are reported as a component of the related transaction. Results of oil and gas derivative transactions are reflected in oil and gas sales and results of interest rate hedging transactions are reflected in interest expense. The changes in fair value of derivative instruments not qualifying for designation as

14

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

either cash flow or fair value hedges that occur prior to maturity are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil and gas sales or interest expense. Cash flows from derivative instruments are classified in the same category within the statement of cash flows as the items being hedged, or on a basis consistent with the nature of the instrument.

We have established the fair value of all derivative instruments using estimates determined by our counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in the fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in oil and gas sales. For derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent gains or losses on ineffectiveness and are reflected currently in interest expense. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are also recognized currently in earnings.

Adoption of SFAS 133 at January 1, 2001 resulted in the recognition of $9.3 million of current derivative assets and $98.6 million in current derivative liabilities. The cumulative effect of the accounting change decreased accumulated other comprehensive income by $53.6 million, net of income tax, but did not have an effect on our net income or earnings per share amounts.

Accounts Payable and Accrued Liabilities

Included in accounts payable at December 31, 2003 are liabilities of approximately $28.3 million representing the amount by which checks issued, but not presented to our banks for collection, exceeded balances in applicable bank accounts. Other accrued liabilities include $34.1 million and $16.0 million of accrued drilling costs as of December 31, 2003 and 2002, respectively.

Currency Translation

The results of operations for non-U.S. subsidiaries are translated from local currencies into U.S. dollars using average exchange rates during each period; assets and liabilities are translated using exchange rates at the end of each period. Adjustments resulting from the translation process are reported in a separate component of stockholders’ equity, and are not included in the determination of the results of operations. In October 2001, we sold our Canadian subsidiary. As a result, all translation adjustments related to our investment in this subsidiary were reclassified to earnings in the fourth quarter of 2001.

Stock Options

Chesapeake has elected to follow APB No. 25,Accounting for Stock Issued to Employees and related interpretations in accounting for its employee stock options. Under APB No. 25, compensation expense is

15

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 compensation expense of $0.9 million, $0.4 million and $0.8 million in 2003, 2002, and 2001, 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 2003, 2002 or 2001 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.

Pro forma information regarding net income and earnings per share is required by SFAS No. 123 and has been determined as if we had accounted for our employee stock options under the fair value method of the statement. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 2003, 2002 and 2001, respectively: interest rates (zero-coupon U.S. government issues with a remaining life equal to the expected term of the options) ranging from 2.24% to 4.97%, dividend yields ranging from 0.0% to 1.55%, and volatility factors of the expected market price of our common stock ranging from 0.35 to 0.58. We used a weighted-average expected life of the options of five years for each of 2003, 2002 and 2001.

The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because our employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion the existing models do not necessarily provide a reliable single measure of the fair value of the company’s employee stock options.

Pro forma information applying the fair value method follows:

	Years Ended December 31,
	2003		2002		2001
	($ in thousands, except per share amounts)
Net Income:
As reported	$	312,981	$	40,286	$	217,406
Less compensation expense, net of tax(1)		11,018		8,644		9,063
Pro forma	$	301,963	$	31,642	$	208,343
Basic Earnings per common share:
As reported	$	1.38	$	0.18	$	1.33
Less compensation expense, net of tax(1)		0.06		0.05		0.06
Pro forma	$	1.32	$	0.13	$	1.27
Diluted Earnings per common share:
As reported	$	1.21	$	0.17	$	1.25
Less compensation expense, net of tax(1)		0.04		0.05		0.05
Pro forma	$	1.17	$	0.12	$	1.20

(1) Adjustments are net of compensation expenses related to FIN 44 of $0.9 million, $0.4 million and $0.8 million in 2003, 2002 and 2001, respectively.

16

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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. The above pro forma disclosures may not be representative of the effects on pro forma net income for future years.

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for 2002 and 2001 to conform to the presentation used for the 2003 consolidated financial statements.

2. Senior Notes

On November 26, 2003, we issued $200.0 million principal amount of 6.875% senior notes due 2016 in a private placement.

On March 5, 2003, we issued $300.0 million principal amount of 7.50% senior notes due 2013, which were exchanged on November 5, 2003 for substantially identical notes registered under the Securities Act of 1933. On October 17, 2003, we issued an additional $63.8 million of our 7.50% senior notes due 2013 and accrued interest of $0.4 million in exchange for $54.9 million of our 8.125% senior notes due 2011, $6.3 million of our 8.375% senior notes due 2008 and accrued interest of $0.4 million, pursuant to a privately negotiated transaction. The $54.9 million of 8.125% senior notes and $6.3 million of 8.375% senior notes were retired upon receipt.

On December 20, 2002, we issued $150.0 million principal amount of 7.75% senior notes due 2015, which were exchanged on February 20, 2003 for substantially identical notes registered under the Securities Act of 1933. On July 16, 2003, we issued an additional $29.5 million of our 7.75% senior notes due 2015 in exchange for $27.9 million of our 8.375% senior notes due 2008 and $0.5 million of accrued interest, pursuant to a privately negotiated transaction. The $27.9 million of 8.375% senior notes due 2008 were retired upon receipt. On August 5, 2003, we issued an additional $33.5 million of our 7.75% senior notes due 2015 and accrued interest of $0.1 million in exchange for $32.0 million of our 8.5% senior notes due 2012 and $1.1 million of accrued interest, pursuant to a privately negotiated transaction. The $32.0 million of 8.5% senior notes were retired upon receipt. On October 3, 2003, we issued an additional $23.7 million of our 7.75% senior notes due 2015 and accrued interest of $0.4 million in exchange for $16.8 million of our 8.125% senior notes due 2011, $6.0 million of our 8.375% senior notes due 2008 and accrued interest of $0.2 million, pursuant to a privately negotiated transaction. The $16.8 million of 8.125% senior notes and $6.0 million of 8.375% senior notes were retired upon receipt.

On August 12, 2002, we issued $250.0 million principal amount of 9% senior notes due 2012, which were exchanged on October 24, 2002 for substantially identical notes registered under the Securities Act of 1933. In a private offering on November 14, 2002 we issued an additional $50.0 million principal amount of 9% senior notes due 2012 which were exchanged on February 20, 2003 for substantially identical notes registered under the Securities Act of 1933.

On March 17, 1997, we issued $150.0 million principal amount of 8.5% senior notes due 2012. During the quarter ended March 31, 2001, Chesapeake purchased and subsequently retired $7.3 million of these notes for total consideration of $7.4 million, including accrued interest of $0.2 million and the write-off of $0.1 million of unamortized bond discount. On August 5, 2003, we exchanged $32.0 million principal of 8.5% senior notes for $33.5 million of our 7.75% senior notes discussed above. In the fourth quarter of 2003, we purchased and subsequently retired $106.4 million of these notes for a total consideration of $114.9 million, including accrued interest of $1.8 million. In connection with this repurchase transaction, we recorded a pre-tax loss of $20.8 million, consisting of $6.7 million of redemption premium, $1.8 million write-off of unamortized debt

17

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

issue costs and notes discount, $0.3 million of transaction costs, and a write-off of the call option value of $12.0 million recorded as a discount on the 8.5% senior notes based on the hedging relationship between the notes and our 8.5% swaption further discussed in Note 10.

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 periods presented. Mayfield Processing, L.L.C. and MidCon Compression, L.P. were established as non-guarantor subsidiaries during 2003. All of our other wholly-owned subsidiaries were guarantor subsidiaries during all periods presented.

18

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2003

($ in thousands)

	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Parent			Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents, including restricted cash	$	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 (DEFICIT)
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 (DEFICIT):
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

19

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2002

($ in thousands)

	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Parent			Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents, including restricted cash	$	(31,893	)	$	24,448		$	255,164		$	—		$	247,719
Accounts receivable		122,074			69,362			3,006			(46,810	)		147,632
Short-term derivative receivable		16,498			—			—			—			16,498
Deferred income tax asset		—			—			8,109			—			8,109
Inventory and other		14,202			1,157			—			—			15,359
Total Current Assets		120,881			94,967			266,279			(46,810	)		435,317
PROPERTY AND EQUIPMENT:
Evaluated oil and gas properties		4,334,833			—			—			—			4,334,833
Unevaluated leasehold		72,506			—			—			—			72,506
Other property and equipment		64,475			30,818			58,799			—			154,092
Less: accumulated depreciation, depletion and amortization		(2,146,538	)		(20,789	)		(4,220	)		—			(2,171,547	)
Net Property and Equipment		2,325,276			10,029			54,579			—			2,389,884
OTHER ASSETS:
Investments in subsidiaries and intercompany advances		—			—			357,698			(357,698	)		—
Deferred income tax asset (liability)		(124,455	)		(1,941	)		128,467			—			2,071
Long-term derivative instruments		2,666			—			—			—			2,666
Long-term investments		—			—			9,075			—			9,075
Other assets		20,246			57			16,349			(57	)		36,595
Total Other Assets		(101,543	)		(1,884	)		511,589			(357,755	)		50,407
TOTAL ASSETS	$	2,344,614		$	103,112		$	832,447		$	(404,565	)	$	2,875,608
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	82,083		$	71,316		$	—		$	(67,398	)	$	86,001
Accrued interest		—			—			35,025			—			35,025
Short-term derivative instruments		33,697			—			—			—			33,697
Other accrued liabilities		46,231			1,960			8,326			(52	)		56,465
Revenues and royalties due others		33,776			—			—			20,588			54,364
Total Current Liabilities		195,787			73,276			43,351			(46,862	)		265,552
OTHER LIABILITIES:
Long-term debt, net		—			—			1,651,198			—			1,651,198
Revenues and royalties due others		13,797			—			—			—			13,797
Long-term derivative instruments		—			—			30,174			—			30,174
Other liabilities		5,687			1,325			—			—			7,012
Intercompany payables (receivable)		1,801,833			(1,677	)		(1,800,151	)		(5	)		—
Total Other Liabilities		1,821,317			(352	)		(118,779	)		(5	)		1,702,181
STOCKHOLDERS’ EQUITY (DEFICIT):
Common Stock		56			1			1,949			(57	)		1,949
Preferred Stock		—			—			149,900			—			149,900
Other		327,454			30,187			756,026			(357,641	)		756,026
Total Stockholders’ Equity		327,510			30,188			907,875			(357,698	)		907,875
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,344,614		$	103,112		$	832,447		$	(404,565	)	$	2,875,608

20

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

($ in thousands)

	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Parent			Eliminations			Consolidated
For the Year Ended December 31, 2003:
REVENUES:
Oil and gas sales	$	1,296,822		$	—		$	—		$	—		$	1,296,822
Oil and gas marketing sales		—			1,295,872			—			(875,262	)		420,610
Total Revenues		1,296,822			1,295,872			—			(875,262	)		1,717,432
OPERATING COSTS:
Production expenses		137,583			—			—			—			137,583
Production taxes		77,893			—			—			—			77,893
General and administrative		18,802			3,453			1,498			—			23,753
Oil and gas marketing expenses		—			1,285,550			—			(875,262	)		410,288
Oil and gas depreciation, depletion and amortization		369,465			—			—			—			369,465
Depreciation and amortization of other assets		8,715			3,193			4,885			—			16,793
Provision for legal settlements		6,402			—			—			—			6,402
Total Operating Costs		618,860			1,292,196			6,383			(875,262	)		1,042,177
INCOME (LOSS) FROM OPERATIONS		677,962			3,676			(6,383	)		—			675,255
OTHER INCOME (EXPENSE):
Interest and other income		515			1,154			157,978			(156,820	)		2,827
Interest expense		(148,102	)		(11	)		(163,063	)		156,820			(154,356	)
Loss on investment in Seven Seas		—			—			(2,015	)		—			(2,015	)
Loss on repurchases of Chesapeake debt		—			—			(20,759	)		—			(20,759	)
Equity in net earnings of subsidiaries		—			—			334,211			(334,211	)		—
Total Other Income (Expense)		(147,587	)		1,143			306,352			(334,211	)		(174,303	)
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE		530,375			4,819			299,969			(334,211	)		500,952
Income tax expense (benefit)		201,541			1,831			(13,012	)		—			190,360
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		328,834			2,988			312,981			(334,211	)		310,592
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAXES		2,389			—			—			—			2,389
NET INCOME	$	331,223		$	2,988		$	312,981		$	(334,211	)	$	312,981
For the Year Ended December 31, 2002:
REVENUES:
Oil and gas sales	$	568,187		$	—		$	—		$	—		$	568,187
Oil and gas marketing sales		—			548,388			—			(378,073	)		170,315
Total Revenues		568,187			548,388			—			(378,073	)		738,502
OPERATING COSTS:
Production expenses		98,191			—			—			—			98,191
Production taxes		30,101			—			—			—			30,101
General and administrative		15,069			1,934			615			—			17,618
Oil and gas marketing expenses		—			543,809			—			(378,073	)		165,736
Oil and gas depreciation, depletion and amortization		221,189			—			—			—			221,189
Depreciation and amortization of other assets		9,515			1,820			2,674			—			14,009
Total Operating Costs		374,065			547,563			3,289			(378,073	)		546,844
INCOME (LOSS) FROM OPERATIONS		194,122			825			(3,289	)		—			191,658
OTHER INCOME (EXPENSE):
Interest and other income		1,580			597			120,046			(114,883	)		7,340
Interest expense		(111,943	)		(10	)		(114,961	)		114,883			(112,031	)
Loss on investment in Seven Seas		—			—			(17,201	)		—			(17,201	)
Loss on repurchases of Chesapeake debt		—			—			(2,626	)		—			(2,626	)
Equity in net earnings of subsidiaries		—			—			51,104			(51,104	)		—
Total Other Income (Expense)		(110,363	)		587			36,362			(51,104	)		(124,518	)
INCOME BEFORE INCOME TAXES		83,759			1,412			33,073			(51,104	)		67,140
Income tax expense (benefit)		33,502			565			(7,213	)		—			26,854
NET INCOME	$	50,257		$	847		$	40,286		$	(51,104	)	$	40,286

21

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

($ in thousands)

	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Parent			Eliminations			Consolidated
For the Year Ended December 31, 2001:
REVENUES:
Oil and gas sales	$	820,318		$	—		$	—		$	—		$	820,318
Oil and gas marketing sales		—			419,279			—			(270,546	)		148,733
Total Revenues		820,318			419,279			—			(270,546	)		969,051
OPERATING COSTS:
Production expenses		75,374			—			—			—			75,374
Production taxes		33,010			—			—			—			33,010
General and administrative		12,201			1,311			937			—			14,449
Oil and gas marketing expenses		—			414,919			—			(270,546	)		144,373
Oil and gas depreciation, depletion and amortization		172,902			—			—			—			172,902
Depreciation and amortization of other assets		6,035			80			2,548			—			8,663
Total Operating Costs		299,522			416,310			3,485			(270,546	)		448,771
INCOME (LOSS) FROM OPERATIONS		520,796			2,969			(3,485	)		—			520,280
OTHER INCOME (EXPENSE):
Interest and other income		(130	)		473			96,665			(94,131	)		2,877
Interest expense		(100,531	)		(2	)		(91,919	)		94,131			(98,321	)
Loss on repurchases of Chesapeake debt		(13,618	)		—			(63,049	)		—			(76,667	)
Impairments of investments in securities		(8,579	)		—			(1,500	)		—			(10,079	)
Gain on sale of Canadian subsidiary		—			—			27,000			—			27,000
Gothic standby credit facility costs		—			—			(3,392	)		—			(3,392	)
Equity in net earnings of subsidiaries		—			—			239,968			(239,968	)		—
Total Other Income (Expense)		(122,858	)		471			203,773			(239,968	)		(158,582	)
INCOME BEFORE INCOME TAXES		397,938			3,440			200,288			(239,968	)		361,698
Income tax expense (benefit)		160,034			1,376			(17,118	)		—			144,292
NET INCOME	$	237,904		$	2,064		$	217,406		$	(239,968	)	$	217,406

22

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

($ in thousands)

	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Parent			Eliminations			Consolidated
For the Year Ended December 31, 2003:
CASH FLOWS FROM OPERATING ACTIVITIES	$	981,939		$	(44,660	)	$	342,534		$	(334,211	)	$	945,602
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net		(838,908	)		—			(1,127,442	)		—			(1,966,350	)
Additions to buildings and other fixed assets		(18,631	)		(27,265	)		(26,779	)		—			(72,675	)
Additions to long-term investments		(5,000	)		—			(25,750	)		—			(30,750	)
Deposit for Concho acquisition		—			—			(10,000	)		—			(10,000	)
Deposit for South Texas asset acquisition		(3,250	)		—			—			—			(3,250	)
Sale of non-oil and gas assets and recoveries of investments		314			—			5,485			—			5,799
Other investments		9			—			—			—			9
Cash (used in) provided by investing activities		(865,466	)		(27,265	)		(1,184,486	)		—			(2,077,217	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowing		738,000			—			—			—			738,000
Payments on long-term borrowings		(738,000	)		—			—			—			(738,000	)
Cash received from issuance of senior notes, net of costs		—			—			485,445			—			485,445
Proceeds from issuance of preferred stock, net of costs		—			—			390,365			—			390,365
Proceeds from issuance of common stock, net of costs		—			—			177,427			—			177,427
Cash paid to repurchase senior notes, including redemption premium		—			—			(113,074	)		—			(113,074	)
Cash paid for common stock dividends		—			—			(27,253	)		—			(27,253	)
Cash paid for preferred stock dividends		—			—			(20,916	)		—			(20,916	)
Cash paid for financing cost of credit facility		(2,474	)		—			—			—			(2,474	)
Cash paid for treasury stock		—			—			(2,109	)		—			(2,109	)
Net increase in outstanding payments in excess of cash balances		28,315			—			—			—			28,315
Additions to other financing costs		—			—			(496	)		—			(496	)
Cash received from exercise of stock options		—			—			9,329			—			9,329
Intercompany advances, net		(110,091	)		79,608			(303,728	)		334,211			—
Cash provided by (used in) financing activities		(84,250	)		79,608			594,990			334,211			924,559
NET INCREASE IN CASH AND CASH EQUIVALENTS		32,223			7,683			(246,962	)		—			(207,056	)
CASH, BEGINNING OF PERIOD		(31,975	)		24,448			255,164			—			247,637
CASH, END OF PERIOD	$	248		$	32,131		$	8,202		$	—		$	40,581

23

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Parent			Eliminations			Consolidated
For the Year Ended December 31, 2002:
CASH FLOWS FROM OPERATING ACTIVITIES	$	397,211		$	1,360		$	85,064		$	(51,104	)	$	432,531
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net		(419,100	)		—			(311,892	)		—			(730,992	)
Additions to buildings and other fixes assets		(12,927	)		(3,860	)		(20,323	)		—			(37,110	)
Deposit for ONEOK acquisition		(15,000	)		—			—			—			(15,000	)
Sale of non-oil and gas assets		1,559			—			4,215			—			5,774
Additions to long-term investments		—			—			(2,408	)		—			(2,408	)
Other investments		(9	)		—			—			—			(9	)
Cash (used in) provided by investing activities		(445,477	)		(3,860	)		(330,408	)		—			(779,745	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings		252,500			—			—			—			252,500
Payments on long-term borrowings		(252,500	)		—			—			—			(252,500	)
Cash received from issuance of senior notes, net of costs		—			—			439,427			—			439,427
Proceeds from issuance of common stock, net of costs		—			—			164,104			—			164,104
Cash paid to repurchase senior notes, including redemption premium		—			—			(111,597	)		—			(111,597	)
Cash dividends paid on preferred stock and common stock		—			—			(15,164	)		—			(15,164	)
Additions to other financing costs		(2,902	)		—			(421	)		—			(3,323	)
Cash received from exercise of stock options		—			—			3,810			—			3,810
Intercompany advances, net		30,506			7,234			(88,844	)		51,104			—
Cash provided by (used in) financing activities		27,604			7,234			391,315			51,104			477,257
NET INCREASE IN CASH AND CASH EQUIVALENTS		(20,662	)		4,734			145,971			—			130,043
CASH, BEGINNING OF PERIOD		(11,313	)		19,714			109,193			—			117,594
CASH, END OF PERIOD	$	(31,975	)	$	24,448		$	255,164		$	—		$	247,637

24

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

($ in thousands)

	Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Parent			Eliminations			Consolidated
For the Year Ended December 31, 2001:
CASH FLOWS FROM OPERATING ACTIVITIES	$	526,589		$	22,484		$	244,632		$	(239,968	)	$	553,737
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net		(736,280	)		—			142,906			—			(593,374	)
Additions to buildings and other fixes assets		(26,212	)		(292	)		(12,494	)		—			(38,998	)
Sale of non-oil and gas assets		3,204			—			—			—			3,204
Additions to long-term investments		—			—			(40,239	)		—			(40,239	)
Other investments		(825	)		127			—			—			(698	)
Cash (used in) provided by investing activities		(760,113	)		(165	)		90,173			—			(670,105	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings		433,500			—			—			—			433,500
Payments on long-term borrowings		(458,500	)		—			—			—			(458,500	)
Cash received on issuance of senior notes, net of costs		—			—			1,028,275			—			1,028,275
Cash received from issuance of preferred stock, net of costs		—			—			145,086			—			145,086
Cash paid to purchase senior notes. including redemption premium		—			—			(906,021	)		—			(906,021	)
Cash dividends paid on preferred stock		—			—			(1,092	)		—			(1,092	)
Additions to other financing costs		(5,984	)		—			(627	)		—			(6,611	)
Cash paid for purchase of preferred stock		—			—			(10	)		—			(10	)
Cash paid on make whole provision		—			—			(3,336	)		—			(3,336	)
Cash received from exercise of stock options		—			—			3,216			—			3,216
Intercompany advances, net		273,608			(9,805	)		(503,771	)		239,968			—
Cash provided by (used in) financing activities		242,624			(9,805	)		(238,280	)		239,968			234,507
EFFECT OF EXCHANGE RATE CHANGES ON CASH		(545	)		—			—			—			(545	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		8,555			12,514			96,525			—			117,594
CASH, BEGINNING OF PERIOD		(19,868	)		7,200			12,668			—			—
CASH, END OF PERIOD	$	(11,313	)	$	19,714		$	109,193		$	—		$	117,594

25

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

($ in thousands)

	Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Parent			Eliminations			Consolidated
For the Year Ended December 31, 2003:
NET INCOME	$	331,223		$	2,988	$	312,981		$	(334,211	)	$	312,981
Other comprehensive income (loss)—net of income tax:
Change in fair value of derivative instruments		(24,917	)		—		—			—			(24,917	)
Reclassification of gain on settled contracts		2,363			—		—			—			2,363
Ineffective portion of derivatives qualifying for hedge accounting		5,703			—		—			—			5,703
Equity in net other comprehensive income (loss) of subsidiaries		—			—		(16,851	)		16,851			—
Comprehensive income (loss)	$	314,372		$	2,988	$	296,130		$	(317,360	)	$	296,130
For the Year Ended December 31, 2002:
NET INCOME	$	50,257		$	847	$	40,286		$	(51,104	)	$	40,286
Other comprehensive income (loss)—net of income tax:
Change in fair value of derivative instruments		(27,041	)		—		—			—			(27,041	)
Reclassification of gain on settled contracts		(22,066	)		—		—			—			(22,066	)
Ineffective portion of derivatives qualifying for hedge accounting		2,135			—		—			—			2,135
Equity in net other comprehensive income (loss) of subsidiaries		—			—		(46,972	)		46,972			—
Comprehensive income (loss)	$	3,285		$	847	$	(6,686	)	$	(4,132	)	$	(6,686	)
For the Year Ended December 31, 2001:
NET INCOME	$	237,904		$	2,064	$	217,406		$	(239,968	)	$	217,406
Other comprehensive income (loss)—net of income tax:
Change in fair value of derivative instruments		147,210			—		—			—			147,210
Reclassification of gain on settled contracts		(48,623	)		—		—			—			(48,623	)
Ineffective portion of derivatives qualifying for hedge accounting		(1,503	)		—		—			—			(1,503	)
Foreign currency translation adjustments		(3,551	)		—		—			—			(3,551	)
Transfer of translation adjustments related to sale of Canadian subsidiary		7,452			—		—			—			7,452
Cumulative effect of accounting change for financial derivatives		(53,573	)		—		—			—			(53,573	)
Equity in net other comprehensive income (loss) of subsidiaries		—			—		47,412			(47,412	)		—
Comprehensive income	$	285,316		$	2,064	$	264,818		$	(287,380	)	$	264,818

26

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

3. Notes Payable and Long-Term Debt

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

	December 31,
	2003			2002
	($ in thousands)
7.875% Senior Notes due 2004 (a)	$	42,137		$	42,137
8.5% Senior Notes due 2012		4,290			142,665
8.125% Senior Notes due 2011		728,255			800,000
8.375% Senior Notes due 2008		209,815			250,000
9.0% Senior Notes due 2012		300,000			300,000
7.5% Senior Notes due 2013		363,823			—
7.75% Senior Notes due 2015		236,691			150,000
6.875% Senior Notes due 2016		200,000			—
Discount on senior notes		(26,959	)		(15,482	)
Discount for interest rate swap and swaption (b)		(339	)		(18,122	)
Total notes payable and long-term debt	$	2,057,713		$	1,651,198

(a) This amount was classified as long-term debt based on our ability and intent to satisfy this obligation with funding from our bank credit facility.

(b) See Note 10 for further discussion related to these instruments.

We have a $350 million revolving bank credit facility (with a committed borrowing base of $350 million) which matures in May 2007. As of December 31, 2003, we had no outstanding borrowings under this facility and utilized $35.8 million of the facility for various letters of credit. Borrowings under the facility are collateralized by certain producing oil and gas properties and bear interest at either the reference rate of Union Bank of California, N.A., or London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies according to our senior unsecured long-term debt rating. The unused portion of the facility is subject to an annual commitment fee of 0.375%. Interest is payable quarterly. The collateral value and borrowing base are redetermined periodically.

The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, sell properties, pay dividends, purchase or redeem our capital stock, make investments or loans, purchase certain of our senior notes 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. At December 31, 2003, our current ratio was 1.6 to 1 and our fixed charge coverage ratio was 4.8 to 1. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million or more, would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $25.0 million.

27

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The aggregate scheduled maturities of notes payable and long-term debt for the five fiscal years ending December 31, 2008 and thereafter were as follows as of December 31, 2003 ($ in thousands):

2004	$	42,137
2005		—
2006		—
2007		—
2008		209,815
After 2008		1,833,059
	$	2,085,011

4. Contingencies and Commitments

Royalty Owner Litigation. Royalty owners have commenced litigation against a number of oil and gas producers claiming that amounts paid for production attributable to the royalty owners’ interest violates the terms of applicable leases and state law, that deductions from the proceeds of oil and gas production are unauthorized under the leases, and that amounts received by upstream sellers should be used to compute the amounts paid to the royalty owners. Typically this litigation has taken the form of class action suits.

In one such lawsuit that has been filed against Chesapeake and a subsidiary, the parties have entered into a settlement agreement, effective December 31, 2003, pursuant to which we have agreed to 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 and $3.3 million were charged to provisions for legal settlements in 2003 and 2002, respectively), $2.4 million relating to gathering, compression, dehydration, field fuel or transportation costs with respect to certain of our gathering systems, and $4.5 million relating to other such gathering system costs and other claims. The lawsuit has been certified for settlement as a class action, and the court has preliminarily approved the settlement for the purpose of giving class members notice of the proposed settlement and setting a fairness hearing on May 6, 2004. Assuming the settlement is approved and is not appealed, the distribution of settlement proceeds is scheduled to occur prior to October 5, 2004. The class members are substantially all royalty owners under Oklahoma oil and gas leases or pooling orders covering wells in which any of Chesapeake, its subsidiaries or their predecessors is a joint working interest owner or operator. In connection with the settlement, we incurred a $6.9 million charge in the third and fourth quarter of 2003 for litigation and settlement costs. We believe the potential liability associated with post-production claims made against us by royalty owners in three other pending lawsuits filed as class actions is not material. There has been no class certification in any of these cases.

Other Litigation. Chesapeake is currently involved in various other 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 one of the parties provides 30 days notice of non-extension. The agreements with the chief

28

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 his or her base compensation plus 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 at December 31, 2003.

Other. We completed an acquisition of Permian Basin and Mid-Continent oil and gas assets from Concho Resources Inc. in January 2004. We paid approximately $420 million in cash for these assets, $10 million of which was paid in 2003.

We also completed an acquisition of South Texas gas assets in January 2004. We paid approximately $65 million for these assets, $3.3 million of which was paid in 2003.

Chesapeake has entered into various operating leases for office space and equipment. Future minimum lease payments required as of December 31, 2003 related to these operating leases are as follows ($ in thousands):

2004	$	2,353
2005		1,547
2006		622
2007		316
2008		184
After 2008		415
Total	$	5,437

Rent expense, including short-term rentals, for the years ended December 31, 2003, 2002 and 2001 was $13.1 million, $7.7 million and $6.4 million, respectively.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

5. Income Taxes

The components of the income tax provision (benefit) for each of the periods presented below are as follows:

	Years Ended December 31,
	2003			2002			2001
	($ in thousands)
Current	$	5,000		$	(1,822	)	$	3,565
Deferred:
United States		186,824			28,676			136,991
Foreign		—			—			3,736
Total	$	191,824	(1)	$	26,854		$	144,292

(1) Includes $1,464,000 of tax expense related to the change in accounting principle.

The effective income tax expense (benefit) differed from the computed “expected” federal income tax expense (benefit) on earnings before income taxes for the following reasons:

	Years Ended December 31,
	2003			2002			2001
	($ in thousands)
Computed “expected” federal income tax provision	$	176,682		$	23,499		$	126,594
State income taxes and other		10,968			3,492			15,061
Change in valuation allowance		4,364			—			2,441
Tax percentage depletion		(190	)		(137	)		(195	)
Foreign taxes in excess of U.S. statutory rate		—			—			391
	$	191,824		$	26,854		$	144,292

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:

	Years Ended December 31,
	2003			2002
	($ in thousands)
Deferred tax liabilities:
Acquisition, exploration and development costs and related depreciation, depletion and amortization	$	(342,396	)	$	(265,837	)
Deferred tax assets:
Net operating loss carryforwards	$	154,784		$	256,547
Derivative liabilities and other		31,857			18,837
Percentage depletion carryforwards		3,228			3,063
Alternative minimum tax credits		5,011			11
Deferred tax assets	$	194,880		$	278,458
Net deferred tax asset (liability)		(147,516	)		12,621
Less: Valuation allowance		(6,805	)		(2,441	)
Total deferred tax asset (liability)	$	(154,321	)(1)	$	10,180
Reflected in accompanying balance sheets as:
Current deferred income tax asset	$	36,705		$	8,109
Non-current deferred income tax asset		—			2,071
Non-current deferred income tax liability		(191,026	)		—
	$	(154,321	)	$	10,180

(1) Activity during 2003 includes a net asset of $4.9 million related to acquisitions, a benefit of $10.2 million related to derivative instruments, and a benefit of $7.2 million related to stock option compensation. These items were not recorded as part of the provision for deferred income taxes.

SFAS 109 requires that we record a valuation allowance when it is more likely than not that some portion or all of deferred tax assets will not be realized. As of December 31, 2001, we determined that it is more likely than not that $2.4 million of the net deferred tax assets related to Louisiana net operating losses generated by Louisiana properties will not be realized and have recorded a valuation allowance equal to such amounts. During 2003, we determined that it was more likely than not that an additional $4.4 million of the deferred tax assets related to Louisiana net operating losses will not be realized and we recorded an additional valuation allowance equal to such amounts.

As of December 31, 2003, we classified $36.7 million of deferred tax assets as current that were attributable to the current portion of derivative liabilities and other current temporary differences. As of December 31, 2002, we classified $8.1 million of deferred tax assets as current that were attributable to the current portion of derivative liabilities and other current temporary differences.

At December 31, 2003, Chesapeake had federal income tax net operating loss (NOL) carryforwards of approximately $403.8 million. Additionally, we had $71.5 million of alternative minimum tax (AMT) NOL carryforwards available as a deduction against future AMT income and approximately $8.5 million of percentage depletion carryforwards. During 2003, we estimate that we will be able to utilize approximately $253.3 million of NOLs to reduce our 2003 federal taxable income. The NOL carryforwards expire from 2012 through 2022.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The value of these carryforwards depends on the ability of Chesapeake to generate taxable income. In addition, for AMT purposes, only 90% of AMT income in any given year may be offset by AMT NOLs. A summary of our NOLs follows:

	NOL		AMT NOL
	($ in thousands)
Expiration Date:
December 31, 2012	$	171,586	$	—
December 31, 2018		42,187		—
December 31, 2019		139,222		57,414
December 31, 2020		5,156		1,393
December 31, 2021		12,701		5,313
December 31, 2022		32,988		7,399
Total	$	403,840	$	71,519

The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax of Chesapeake is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake.

In the event of an ownership change (as defined for income tax purposes), Section 382 of the Code imposes an annual limitation on the amount of a corporation’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of the company multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains (as defined in the Code) inherent in the assets sold. Chesapeake had an ownership change in March 1998 which triggered a limitation. Certain NOLs acquired through various acquisitions are also subject to limitations.

The following table summarizes our net operating losses as of December 31, 2003 and any related limitations:

	Total		Limited		Annual Limitation
	($ in thousands)
Net operating loss	$	403,840	$	312,140	$	46,658
AMT net operating loss	$	71,519	$	71,519	$	21,081

Although no assurances can be made, we do not believe that an additional ownership change has occurred as of December 31, 2003. Equity transactions after the date hereof by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs.

6. Related Party Transactions

As of December 31, 2003, we had accrued accounts receivable from our chief executive officer and chief operating officer $0.3 million and $2.6 million, respectively, representing billings for December 2003 which

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

were paid in January 2004. Since Chesapeake was founded in 1989, our CEO and COO have acquired small working interests in certain of our oil and gas properties by participating in our drilling activities. Joint interest billing accounts of the CEO and COO are settled in cash. Under their employment agreements, the CEO and COO are permitted to participate in all, or none, of the wells drilled by or on behalf of Chesapeake during each calendar quarter, but they are not allowed to participate only in selected wells. A participation election is required to be received by the Compensation Committee of Chesapeake’s board of directors 30 days prior to the start of a quarter. Their participation is permitted only under the terms outlined in their employment agreements, which, among other things, limit their individual participation to a maximum working interest of 2.5% in a well and prohibits participation in situations where Chesapeake’s working interest would be reduced below 12.5% as a result of their participation.

In October 2001, we sold Chesapeake Canada Corporation, a wholly-owned subsidiary, for net proceeds of approximately $143.0 million. Our CEO and COO each received $2.0 million related to their fractional ownership interest in these Canadian assets, which they acquired and paid for pursuant to the terms of their employment agreements. The portion of the proceeds allocated to our CEO and COO was based upon the estimated fair values of the assets sold as determined by management and the independent members of our board of directors using a methodology similar to that used by Chesapeake for acquisitions of assets from disinterested third parties.

During 2003, 2002 and 2001, we paid legal fees of $2,123,000, $600,000, and $391,000, respectively, for legal services provided by a law firm of which a director is a member.

7. Employee Benefit Plans

We maintain three deferred compensation plans. They include the following:

• The Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan,

• The 401(k) Make-Up Plan and

• The Deferred Compensation Plan.

The Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan is a qualified 401(k) profit sharing plan. Eligible employees may elect to defer voluntary contributions to the plan. The amount an employee can contribute is subject to the plan contribution limitations and annual dollar limits as set out by the IRS. Chesapeake currently matches up to 15% of the employee’s annual compensation dollar for dollar with Chesapeake’s common stock purchased in the open-market. The Company contributed $4.0 million, $2.9 million and $2.0 million to this plan during 2003, 2002 and 2001, respectively.

In January 2003, Chesapeake established the 401(k) Make-Up Plan and the Deferred Compensation Plan, both of which are nonqualified deferred compensation plans as defined by the Internal Revenue Service. Eligible employees that complete a timely election to defer compensation to Chesapeake’s 401(k) plan in excess of the Internal Revenue Service imposed maximum, may defer compensation up to a total of 60% of their salary and 100% of performance bonus in the aggregate for the 401(k) Plan, 401(k) Make-Up Plan and the Deferred Compensation Plan.

The 401(k) Make-Up Plan allows employees receiving a base salary and bonus compensation of at least $90,000 during the prior 12 month period, and having a minimum of five years of service, to defer additional compensation beyond the IRS imposed limit applicable to our Savings and Incentive Stock Bonus Plan. The Company provides a matching contribution equal to 100%, up to 15% of the participating employee’s compensation. The employer match is payable in common stock. The 401(k) Make-Up Plan is an unsecured

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

deferred compensation plan and participants are general creditors of the Company as to their deferred compensation in the plan. We contributed $1.2 million to this plan during 2003.

Under the Deferred Compensation Plan, eligible employees and non-employee directors that complete a timely election may defer receipt of a portion of their compensation to some future date. Chesapeake has no requirement to make a matching contribution to the Deferred Compensation Plan.

Any assets placed in trust by Chesapeake to fund future obligations of the 401(k) Make-Up Plan and the Deferred Compensation Plan are subject to the claims of creditors in the event of insolvency or bankruptcy.

8. Major Customers and Segment Information

Sales to individual customers constituting 10% or more of total revenues were as follows:

Year Ended December 31,	Customer	Amount		Percent of Total Revenues
		($ in thousands)
2003	Reliant Energy Services	$	189,140	11	%
2003	Duke Energy Field Services	$	163,329	10	%
2002	Continental Natural Gas	$	123,813	17	%
2002	Reliant Energy Services	$	96,682	13	%
2002	Duke Energy Field Services	$	83,115	11	%
2001	Reliant Energy Services	$	131,885	14	%
2001	Continental Natural Gas	$	120,500	12	%

In accordance with SFAS 131,Disclosures about Segments of an Enterprise and Related Information, we have identified two reportable operating segments. These segments are managed separately because of the nature of their products and services. Chesapeake’s two segments are the exploration and production segment and the marketing segment. The exploration and production segment is responsible for finding and producing natural gas and crude oil. The marketing segment is responsible for gathering, processing, transporting, and selling natural gas and crude oil production primarily from Chesapeake operated wells. Revenues from the marketing segment’s sale of oil and gas related to Chesapeake’s ownership interests are reflected as exploration and production revenues. Such amounts totaled $875.3 million, $378.1 million and $270.5 million for 2003, 2002 and 2001, respectively.

Management has determined that these are its only two segments and any assets that do not support the marketing segment are considered part of the exploration and production segment. Management evaluates each segment’s performance based upon income before income taxes and cumulative effect of accounting change. The following table presents information about each segment’s operations:

	Exploration and Production		Marketing		Consolidated
For the Year Ended December 31, 2003:
Revenue	$	1,296,822	$	420,610	$	1,717,432
Production expenses and taxes		215,476		—		215,476
General and administrative		26,702		3,453		30,155
Oil and gas marketing expenses		—		410,288		410,288
Depreciation, depletion and amortization		383,065		3,193		386,258
Interest and other income		1,673		1,154		2,827
Interest expenses		154,345		11		154,356
Other expenses		22,774		—		22,774
INCOME BEFORE INCOME TAXES		496,133		4,819		500,952
Income tax expense (benefit)		188,529		1,831		190,360
NET INCOME	$	307,604	$	2,988	$	310,592
TOTAL ASSETS	$	4,376,558	$	195,733	$	4,572,291
CAPITAL EXPENDITURES	$	2,086,102	$	27,265	$	2,113,367
For the Year Ended December 31, 2002:
Revenue	$	568,187	$	170,315	$	738,502
Production expenses and taxes		128,292		—		128,292
General and administrative		15,684		1,934		17,618
Oil and gas marketing expenses		—		165,736		165,736
Depreciation, depletion and amortization		233,378		1,820		235,198
Interest and other income		6,743		597		7,340
Interest expense		112,021		10		112,031
Other expenses		19,827		—		19,827
INCOME BEFORE INCOME TAXES		65,728		1,412		67,140
Income tax expense (benefit)		26,289		565		26,854
NET INCOME	$	39,439	$	847	$	40,286
TOTAL ASSETS	$	2,772,496	$	103,112	$	2,875,608
CAPITAL EXPENDITURES	$	826,088	$	7,281	$	833,369
For the Year Ended December 31, 2001:
Revenue	$	820,318	$	148,733	$	969,051
Production expenses and taxes		108,384		—		108,384
General and administrative		13,138		1,311		14,449
Oil and gas marketing expenses		—		144,373		144,373
Depreciation, depletion and amortization		181,485		80		181,565
Interest and other income		2,404		473		2,877
Interest expense		98,319		2		98,321
Other expenses		63,138		—		63,138
INCOME BEFORE INCOME TAXES		358,258		3,440		361,698
Income tax expense (benefit)		142,916		1,376		144,292
NET INCOME	$	215,342	$	2,064	$	217,406
TOTAL ASSETS	$	2,232,426	$	54,342	$	2,286,768
CAPITAL EXPENDITURES	$	1,031,676	$	291	$	1,031,967

9. Stockholders’ Equity and Stock-Based Compensation

In November 2003, we issued 1,725,000 shares of 5.00% cumulative convertible preferred stock, par value $.01 per share and liquidation preference $100 per share, in a public offering. As of December 31, 2003, 1,725,000 shares remain outstanding. The net proceeds from the offering were $167.6 million. Each preferred share is convertible at any time at the option of the holder into 6.0962 shares of common stock, subject to adjustment. At December 31, 2003, 10,515,945 shares of our common stock were reserved for issuance upon conversion. The conversion rate is based on an initial conversion price of $16.40 per common share, plus cash in lieu of fractional shares. The preferred stock is subject to mandatory conversion, at our option, (1) on or after November 18, 2006 at the same rate, if the market price of the common stock equals or exceeds 130% of the conversion price, or $21.32, for a specified time period and (2) on or after November 18, 2008, at the lower of conversion price and the then current market price of common stock if there are less than 250,000 shares of preferred stock outstanding at the time. Annual cumulative cash dividends of $5.00 per share are payable quarterly on the fifteenth day of each February, May, August and November.

In March 2003, we issued 23,000,000 shares of Chesapeake common stock at $8.10 per share in a public offering for net proceeds of $177.4 million.

In March 2003, we issued 4,600,000 shares of 6.00% cumulative convertible preferred stock, par value $.01 per share and liquidation preference $50 per share, in a private offering, all of which are outstanding as of

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2003. The net proceeds from the offering were $222.8 million. Each preferred share is convertible at any time at the option of the holder into 4.8605 shares of common stock, subject to adjustment. At December 31, 2003, 22,358,300 shares of common stock were reserved for issuance upon conversion. The conversion rate is based on an initial conversion price of $10.287 per common share, plus cash in lieu of fractional shares. The preferred stock is subject to mandatory conversion at our option, (1) on or after March 20, 2006 at the same rate if the market price of the common stock equals or exceeds 130% of the conversion price, or $13.37, at the time and (2) on or after March 20, 2008 at the lower of the conversion price and the then current market price of the common stock if there are less than 250,000 shares of preferred stock outstanding at the time. Annual cumulative cash dividends of $3.00 per share are payable quarterly on the fifteenth day of March, June, September and December.

In December 2002, we issued 23,000,000 shares of Chesapeake common stock at $7.50 per share in a public offering for net proceeds of $164.1 million.

On November 13, 2001, we issued 3,000,000 shares of 6.75% cumulative convertible preferred stock, par value $.01 per share and liquidation preference $50 per share, in a private offering. As of December 31, 2003, 2,998,000 shares remain outstanding. The net proceeds from the offering were $145.1 million. Each preferred share is convertible at any time at the option of the holder into 6.4935 shares of our common stock, subject to adjustment. At December 31, 2003, 19,467,513 shares of our common stock were reserved for issuance upon conversion. The conversion rate is based on an initial conversion price of $7.70 per common share, plus cash in lieu of fractional shares. The preferred stock is subject to mandatory conversion, at our option, (1) on or after November 20, 2004 at the same rate if the market price of the common stock equals or exceeds 130% of the conversion price, or $10.01, at the time and (2) on or after November 20, 2006 at the lower of the conversion price and the then current market price of the common stock if there are less than 250,000 shares of preferred stock outstanding at the time. Annual cumulative cash dividends of $3.375 per share are payable quarterly on the fifteenth day of each February, May, August and November.

On March 30, 2001, we issued 1,117,216 shares of Chesapeake common stock in exchange for 49.5% of RAM Energy, Inc.’s, outstanding common stock. Our shares were valued at $8.854 each, or $9.9 million in total. In the third quarter of 2001, we made make-whole cash payments of $3.3 million to the former RAM shareholders. In December 2001, we sold all the RAM shares we owned for minimal consideration.

In January 2001, we acquired Gothic Energy Corporation in a stock merger. We issued 3,989,813 common shares in exchange for Gothic common shares at the rate of 0.1908 of a share of Chesapeake common stock for each share of Gothic common stock. In addition, outstanding warrants and options to purchase Gothic common stock were converted to the right to purchase Chesapeake common stock based on the merger exchange ratio. As of December 31, 2003, 0.4 million shares of Chesapeake common stock may be purchased upon the exercise of such warrants and options at an average price of $14.55 per share.

In 2001, holders of our 7% cumulative convertible preferred stock converted 622,768 shares into 4,480,171 shares of common stock (at a conversion price of $6.95 per share), and we redeemed the remaining 1,269 shares of preferred stock for 7,239 shares of common stock and $3,000 of cash (at a redemption price of $52.45 per share, paid in 5.7 shares of common stock and cash of $2.45).

Stock-Based Compensation Plans

Under Chesapeake’s 2003 Stock Incentive Plan, restricted stock and incentive and nonqualified stock options to purchase our common stock may be awarded to employees and consultants of Chesapeake. Subject to

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

any adjustments as provided by the plan, the aggregate number of shares which may be issued and sold may not exceed 10 million shares. The maximum period for exercise of an option may not be more than ten years from the date of grant and the exercise price may not be less than the fair market value of the shares underlying the option on the date of grant. Restricted stock and options granted become vested at dates determined by the compensation committee of the board of directors. No restricted stock or option can be granted under this plan after April 14, 2013. This plan has been approved by our shareholders. No options or restricted shares were issued during 2003 from this plan.

Under Chesapeake’s 2003 Stock Award Plan for Non-Employee Directors, 10,000 shares of Chesapeake’s common stock will be awarded to each newly appointed non-employee director on his or her first day of service. Subject to any adjustments as provided by the plan, the aggregate number of shares which may be issued may not exceed 50,000 shares. This plan was not required to be approved by our shareholders. In 2003, 10,000 shares of common stock were awarded to a new director from this plan.

Under Chesapeake’s 2002 Non-Employee Director Stock Option Plan, non-qualified options to purchase our common stock may be granted to members of our board of directors who are not Chesapeake employees. Subject to any adjustments as provided by this plan, the aggregate number of shares which may be issued and sold may not exceed 500,000 shares. The maximum period for exercise of an option may not be more than ten years from the date of grant, and the exercise price may not be less than the fair market value of the shares underlying the options on the date of grant. Options granted become exercisable at dates determined by the compensation committee of the board of directors. This plan also contains a formula award provision pursuant to which each non-employee director receives every quarter a ten-year immediately exercisable option to purchase 10,000 shares of common stock at an exercise price equal to the fair market value of the shares on the date of grant. No options can be granted under this plan after April 14, 2012. This plan has been approved by our shareholders.

Under Chesapeake’s 2001 and 2002 Stock Option Plans, incentive and nonqualified stock options to purchase our common stock may be granted to employees and consultants of Chesapeake. Subject to any adjustment as provided by the plans, the aggregate number of shares which may be issued and sold may not exceed 3,200,000 and 3,000,000 shares, respectively. The maximum period for exercise of an option may not be more than ten years from the date of grant and the exercise price may not be less than the fair market value of the shares underlying the options on the date of grant; provided, however, nonqualified stock options not exceeding 10% of the options issuable under each plan may be granted at an exercise price which is not less than 85% of the grant date fair market value. Options granted become exercisable at dates determined by the compensation committee of the board of directors. No options can be granted under the 2001 plan after February 28, 2011 and under the 2002 plan after February 29, 2012. These plans have been approved by our shareholders.

Under Chesapeake’s 2000 and 2001 Executive Officer Stock Option Plans, nonqualified stock options to purchase our common stock may be granted to executive officers of Chesapeake. Subject to any adjustment as provided by the plan, the aggregate number of shares which may be sold may not exceed 2,500,000 shares under the 2000 plan and 4,000,000 shares under the 2001 plan and must represent issued shares which have been reacquired by Chesapeake. The maximum period for exercise of an option may not be more than ten years from the date of grant and the exercise price may not be less than the fair market value of the shares underlying the options on the date of grant; provided, however, nonqualified stock options not exceeding 10% of the options issuable under this plan may be granted at an exercise price which is not less than 85% of the grant date fair market value. Options granted become exercisable at dates determined by the compensation committee of the board of directors. No options can be granted under the 2000 plan after April 25, 2010 or after April 14, 2011 under the 2001 plan. These plans were not required to be approved by our shareholders.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Under Chesapeake’s 1999 Stock Option Plan, 2000 Employee Stock Option Plan, 2001 Nonqualified Stock Option Plan and 2002 Nonqualified Stock Option Plan, nonqualified stock options to purchase our common stock may be granted to employees and consultants of Chesapeake. Subject to any adjustment as provided by the respective plans, the aggregate number of shares which may be issued and sold may not exceed 3,000,000 shares from each of the 1999, 2000 and 2001 plans and 4,000,000 from the 2002 plan. The maximum period for exercise of an option may not be more than ten years from the date of grant and the exercise price may not be less than the fair market value of the shares underlying the options on the date of grant; provided, however, nonqualified stock options not exceeding 10% of the options issuable under this plan may be granted at an exercise price which is not less than 85% of the grant date fair market value. Options granted become exercisable at dates determined by the compensation committee of the board of directors. No options can be granted after March 4, 2009 under the 1999 plan, after April 25, 2010 under the 2000 plan, after April 14, 2011 under the 2001 plan, and after February 29, 2012 under the 2002 plan. These plans were not required to be approved by our shareholders.

Under Chesapeake’s 1994 Stock Option Plan and 1996 Stock Option Plan, incentive and nonqualified stock options to purchase our common stock may be granted to employees and consultants of Chesapeake. Subject to any adjustment as provided by the respective plans, the aggregate number of shares which may be issued and sold may not exceed 4,886,910 shares under the 1994 plan and 6,000,000 shares under the 1996 plan. The maximum period for exercise of an option may not be more than ten years from the date of grant and the exercise price of incentive stock options may not be less than the fair market value of the shares underlying the options on the date of grant. The exercise price of nonqualified stock options under the 1996 plan must be at least 85% of the fair market value of the shares underlying the options on the date of grant. Options granted become exercisable at dates determined by the compensation committee of the board of directors. No options can be granted under the 1994 plan after October 17, 2004 or under the 1996 plan after October 14, 2006. These plans were approved by our shareholders.

Chesapeake’s 1992 Nonstatutory Stock Option Plan terminated on December 10, 2002. The last option grants under this plan were made in April 2002. The plan permitted grants of nonqualified stock options to purchase our common stock to directors of Chesapeake. Subject to any adjustment as provided by the plan, the aggregate number of shares which may be issued and sold may not exceed 3,132,000 shares. All options granted under the plan were made pursuant to a formula set forth in the plan. Under this provision, each director who was not an executive officer received every quarter a ten-year immediately exercisable option to purchase a specified number of shares of common stock at an option price equal to the fair market value of the shares on the date of grant. This plan was approved by our shareholders.

37

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A summary of our stock option activity and related information follows:

	Years Ended December 31,
	2003					2002					2001
	Options			Weighted-Avg. Exercise Price		Options			Weighted-Avg. Exercise Price		Options			Weighted-Avg. Exercise Price
Outstanding beginning of period		24,576,775		$	4.40		23,232,655		$	3.96		18,399,162		$	2.83
Granted		7,168,623			8.98		4,170,700			5.38		7,422,300			6.18
Exercised		(4,262,915	)		3.04		(2,519,429	)		1.83		(2,264,374	)		1.83
Canceled/forfeited		(249,198	)		8.51		(307,151	)		5.30		(324,433	)		5.68
Outstanding end of period		27,233,285		$	5.78		24,576,775		$	4.40		23,232,655		$	3.96
Exercisable end of period		12,131,098		$	4.26		11,014,775		$	3.55		7,495,255		$	2.88
Shares authorized for future grants		11,018,225					7,602,339					3,836,856
Fair value of options granted during the period	$	3.36				$	2.31				$	3.34

The following table summarizes information about stock options outstanding at December 31, 2003:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding	Weighted-Avg. Remaining Contractual Life	Weighted- Avg. Exercise Price		Number Exercisable	Weighted-Avg. Exercise Price
$  0.56 – $    1.13	3,124,783	4.78	$	1.07	3,124,783	$	1.07
1.38 –       4.00	4,048,937	5.36		3.16	2,877,588		3.16
4.06 –       5.20	3,511,411	8.53		5.19	779,478		5.17
5.35 –       5.56	2,362,240	6.87		5.56	1,637,858		5.56
5.60 –       6.11	6,381,917	7.72		6.10	2,912,535		6.10
6.13 –       7.74	511,185	6.27		6.91	376,226		6.87
7.80 –       7.80	3,325,150	9.02		7.80	—		—
7.81 –     10.01	418,437	8.58		8.56	244,505		8.73
10.08 –     10.08	3,077,850	9.48		10.08	—		—
10.10 –     30.63	471,375	8.04		14.49	178,125		20.24
$  0.56 – $  30.63	27,233,285	7.41	$	5.78	12,131,098	$	4.26

The exercise of certain stock options results in state and federal income tax benefits to us related to the difference between the market price of the common stock at the date of disposition and the option price. During 2003, 2002 and 2001, we recognized tax benefits of $7.1 million, $2.4 million and $5.4 million, which were recorded as adjustments to additional paid-in capital and deferred income taxes with respect to such benefits.

38

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Shareholder Rights Plan

Chesapeake maintains a shareholder rights plan designed to deter coercive or unfair takeover tactics, to prevent a person or group from gaining control of Chesapeake without offering fair value to all shareholders and to deter other abusive takeover tactics which are not in the best interest of shareholders.

Under the terms of the plan, each share of common stock is accompanied by one right, which given certain acquisition and business combination criteria, entitles the shareholder to purchase from Chesapeake one one-thousandth of a newly issued share of Series A preferred stock at a price of $25.00, subject to adjustment by Chesapeake.

The rights become exercisable 10 days after Chesapeake learns that an acquiring person (as defined in the plan) has acquired 15% or more of the outstanding common stock of Chesapeake or 10 business days after the commencement of a tender offer which would result in a person owning 15% or more of such shares. Chesapeake may redeem the rights for $0.01 per right within ten days following the time Chesapeake learns that a person has become an acquiring person. The rights will expire on July 27, 2008, unless redeemed earlier by Chesapeake.

10. 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 December 31, 2003, our oil and gas derivative instruments were comprised of swaps, cap-swaps, basis protection swaps and call options. These instruments allow us to predict with greater certainty the effective oil and gas prices to be received for our hedged production. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended.

• For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price, as defined in each instrument, to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

• For cap-swaps, 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.

39

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 consolidated balance sheets, to the extent that a legal right of set off 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 2003, 2002 and 2001 were $10.5 million, $(87.3) million and $84.8 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 $(9.2) million, $(3.6) million and $2.5 million in 2003, 2002 and 2001, respectively.

40

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The estimated fair values of our oil and gas derivative instruments as of December 31, 2003 and 2002 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.

	December 31,
	2003			2002
	($ in thousands)
Derivative assets (liabilities):
Fixed-price gas swaps	$	(44,794	)	$	(21,523	)
Fixed-price gas cap-swaps		(18,608	)		(50,732	)
Gas basis protection swaps		46,205			8,227
Fixed-price gas counter-swaps		—			37,048
Gas call options		(17,876	)		—
Fixed-price gas locked swaps		1,777			16,498
Fixed-price crude oil swaps		—			(1,799	)
Fixed-price crude oil cap-swaps		(11,692	)		(2,252	)
Estimated fair value	$	(44,988	)	$	(14,533	)

Based upon the market prices at December 31, 2003, we expect to transfer a loss of approximately $17.6 million from accumulated other comprehensive income to earnings during the next 12 months when the transactions actually close. All transactions hedged as of December 31, 2003 are expected to mature by December 31, 2007, with the exception of the basis protection swaps which extend through 2009.

Interest Rate Hedging

We also utilize hedging strategies to manage the exposure our fixed-rate senior notes have to interest rate changes. 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.

The following describes interest rate swaps entered into during 2002 and 2003, all of which were terminated prior to contractual maturity for cash settlements ($ in thousands):

Date Initiated	Fair Value at December 31, 2003		Date Closed	Cash Settlement Received		Gains Recognized in 2002			Gains Recognized in 2003		Gains to be Recognized in 2004
March 2002(a)	$	—	July 2002	$	7,500	$	6,778	(c)	$	599	$	123
June 2002(b)		—	July 2002		1,130		1,130			—		—
August 2003(b)		870	January 2004		940		—			870		70
August 2003(b)		1,292	January 2004		1,370		—			1,292		78

(a) This instrument was designated as a fair value hedge with changes in the fair value recorded as an adjustment to the debt. Upon termination of the hedging relationship, the previously recorded changes in the fair value of the debt are amortized to earnings over the term of the debt.

(b) These instruments were not designated as fair value hedges; therefore, changes in the fair value were recorded as adjustments to interest expense.

(c) Of this amount, $1.7 million was recognized as a reduction to the loss on repurchases of debt upon retirement of 7.875% notes.

41

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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, which was the principal amount then outstanding under the 8.5% senior notes. The 8.5% senior notes included a “call option” whereby Chesapeake may redeem the debt at declining redemption prices beginning in March 2004. 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 $7.8 million. The interest rate swap, if executed by the counterparty, requires Chesapeake to pay a fixed rate of 8.5% while the counterparty pays Chesapeake a floating rate of 6 month LIBOR plus 0.75%. Additionally, if the counterparty elects to enter into the interest rate swap, it may also elect to force Chesapeake to settle the transaction at the then current value of the interest rate swap.

According to SFAS 133, a fair value hedge relationship exists between the embedded call option in the 8.5% senior notes and the swaption. The fair value of the swaption is recorded on the consolidated balance sheets as a liability, and the carrying amount of the debt is adjusted by the change in the fair value of the call option subsequent to the initiation of the swaption. Any resulting differences are recorded currently as ineffectiveness in the consolidated statements of operations as an adjustment to interest expense.

During the third quarter 2003, we exchanged and subsequently retired $32.0 million of our 8.5% senior notes. The exchange of debt was treated as a modification rather than an extinguishment. Accordingly, the adjustment to the carrying value of the debt of $3.3 million related to the application of hedge accounting was reflected as a discount on the notes issued in the exchange transaction and will be amortized to interest expense using the effective interest method. During the fourth quarter 2003, we purchased and subsequently retired $106.4 million of the remaining $110.7 million of 8.5% senior notes pursuant to a tender offer and recorded a $12.0 million loss related to the removal of the fair value designation of the corresponding amount of the swaption. Temporary fluctuations in the fair value of the portion of the swaption no longer designated as a fair value hedge are recorded as adjustments to interest expense. We recorded a $3.3 million unrealized loss in interest expense during 2003 due to a decline in the fair value of the portion of the swapion no longer designated as a fair value hedge.

As of December 31, 2003, the remaining notional amount of the swaption designated as a fair value hedge was $4.3 million. We have recorded an adjustment to the carrying amount of the debt of $0.5 million which represents the temporary fluctuations in the fair value of the call option included in the $4.3 million principal amount of 8.5% senior notes. Since the inception of the swaption, we have recorded a change in the fair market value of the swaption from a $7.8 million liability to a $32.6 million liability, an increase of $24.8 million. We have recorded as additional interest expense $5.6 million to reflect ineffectiveness after giving effect to the removal of the designation of a portion of the swaption as a fair value hedge under SFAS 133 as described previously.

On February 27, 2004, Chesapeake and the counterparty agreed to extend the counterparty’s right to require Chesapeake to settle the transaction on March 15, 2004 to April 15, 2004. On March 10, 2004, the counterparty exercised its option to enter into the interest rate swap effective March 15, 2004. On April 15, 2004 and each succeeding March 15, the counterparty may elect to terminate the swap and cause it to be settled at the then current value of the interest rate swap. We may elect to terminate the swap and cause it to be settled at the then current value of the interest rate swap at any time during the term of the swap. Cash payments related to the interest rate swap, if initiated, or as a result of cash settlement at termination will be recorded as adjustments to interest expense.

42

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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 ofFinancial 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, at December 31, 2003 and 2002 was $2,058.1 million and $1,669.3 million, respectively, compared to approximate fair values of $2,279.5 million and $1,744.7 million, respectively. The carrying amount for our 6.75% convertible preferred stock at December 31, 2003 was $149.9 million, with a fair value of $275.8 million. The carrying amount and fair value for our 6.00% convertible preferred stock at December 31, 2003 was $230.0 million. The carrying amount and fair value for our 5.00% preferred stock at December 31, 2003 was $172.5 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 receivables. Our accounts receivable are primarily from purchasers of oil and natural gas products and exploration and production companies which own interests in properties we operate. The industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. Cash and cash equivalents are deposited with major banks or institutions and may at times exceed the federally insured limits.

43

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

11. Disclosures About Oil And Gas Producing Activities

Net Capitalized Costs

Evaluated and unevaluated capitalized costs related to Chesapeake’s oil and gas producing activities are summarized as follows:

	2003
	($ in thousands)
Oil and gas properties:
Proved	$	6,221,576
Unproved		227,331
Total		6,488,907
Less accumulated depreciation, depletion and amortization		(2,480,261	)
Net capitalized costs	$	3,968,646
	2002
	($ in thousands)
Oil and gas properties:
Proved	$	4,334,833
Unproved		72,506
Total		4,407,339
Less accumulated depreciation, depletion and amortization		(2,123,773	)
Net capitalized costs	$	2,283,566

Unproved properties not subject to amortization at December 31, 2003 and 2002 consisted mainly of leasehold acquired through acquisitions and lease acquisition costs. We capitalized approximately $13.0 million, $5.0 million and $4.7 million of interest during 2003, 2002 and 2001, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined.

44

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Costs Incurred in Oil and Gas Acquisition, Exploration and Development

Costs incurred in oil and gas property acquisition, exploration and development activities which have been capitalized are summarized as follows:

Year Ended December 31, 2003	U.S.			Canada			Combined
				($ in thousands)
Development and leasehold costs	$	543,371		$	—		$	543,371
Exploration costs		103,424			—			103,424
Acquisition costs:
Proved properties		1,110,077			—			1,110,077
Unproved properties		198,394			—			198,394
Deferred tax adjustments		(4,903	)		—			(4,903	)
Sales of oil and gas properties		(22,156	)		—			(22,156	)
Geological and geophysical costs		38,181			—			38,181
Asset retirement obligation (a)		39,686			—			39,686
Capitalized internal costs		35,494			—			35,494
Total	$	2,041,568		$	—		$	2,041,568
Year Ended December 31, 2002	U.S.			Canada			Combined
				($ in thousands)
Development and leasehold costs	$	266,291		$	—		$	266,291
Exploration costs		89,422			—			89,422
Acquisition costs:
Proved properties		316,583			—			316,583
Unproved properties		14,000			—			14,000
Deferred tax adjustments		62,398			—			62,398
Sales of oil and gas properties		(839	)		—			(839	)
Geological and geophysical costs		22,798			—			22,798
Capitalized internal costs		24,318			—			24,318
Total	$	794,971		$	—		$	794,971
Year Ended December 31, 2001	U.S.			Canada(b)			Combined
				($ in thousands)
Development and leasehold costs	$	322,582		$	11,090		$	333,672
Exploration costs		47,937			8			47,945
Acquisition costs:
Proved properties		669,201			—			669,201
Unproved properties		35,132			—			35,132
Deferred tax adjustments		36,309			—			36,309
Sales of oil and gas properties		(1,138	)		(150,306	)		(151,444	)
Geological and geophysical costs		7,131			—			7,131
Capitalized internal costs		18,225			—			18,225
Total	$	1,135,379		$	(139,208	)	$	996,171

(a) The amount includes $24.1 million of asset retirement costs recorded as a result of implementation of SFAS 143 effective January 1, 2003.

(b) In October 2001, we sold our Canadian subsidiary which had oil and gas operations primarily in Northeast British Columbia for net proceeds of approximately $143.0 million.

45

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Results of Operations from Oil and Gas Producing Activities (unaudited)

Chesapeake’s results of operations from oil and gas producing activities are presented below for 2003, 2002 and 2001. The following table includes revenues and expenses associated directly with our oil and gas producing activities. It does not include any interest costs and general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil and gas operations.

Year Ended December 31, 2003	U.S.			Canada			Combined
	($ in thousands)
Oil and gas sales (b)	$	1,296,822		$	—		$	1,296,822
Production expenses		(137,583	)		—			(137,583	)
Production taxes		(77,893	)		—			(77,893	)
Depletion and depreciation		(369,465	)		—			(369,465	)
Imputed income tax provision (a)		(270,515	)		—			(270,515	)
Results of operations from oil and gas producing activities	$	441,366		$	—		$	441,366
Year Ended December 31, 2002
Oil and gas sales (c)	$	568,187		$	—		$	568,187
Production expenses		(98,191	)		—			(98,191	)
Production taxes		(30,101	)		—			(30,101	)
Depletion and depreciation		(221,189	)		—			(221,189	)
Imputed income tax provision (a)		(87,482	)		—			(87,482	)
Results of operations from oil and gas producing activities	$	131,224		$	—		$	131,224
Year Ended December 31, 2001
Oil and gas sales (d)	$	788,390		$	31,928		$	820,318
Production expenses		(73,016	)		(2,358	)		(75,374	)
Production taxes		(33,010	)		—			(33,010	)
Depletion and depreciation		(164,693	)		(8,209	)		(172,902	)
Imputed income tax provision (a)		(207,068	)		(9,612	)		(216,680	)
Results of operations from oil and gas producing activities	$	310,603		$	11,749		$	322,352

(a) The imputed income tax provision is hypothetical (at the statutory rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision will be payable.

(b) Includes $10.5 million of unrealized gains on oil and gas derivatives.

(c) Includes $87.3 million of unrealized losses on oil and gas derivatives.

(d) Includes $84.8 million of unrealized gains on oil and gas derivatives.

46

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Oil and Gas Reserve Quantities (unaudited)

The reserve information presented below is based upon reports prepared by independent petroleum engineers and Chesapeake’s petroleum engineers.

• As of December 31, 2003, Ryder Scott Company L.P., Netherland, Sewell & Associates, Inc., Lee Keeling and Associates and our internal reservoir engineers evaluated 31%, 26%, 17% and 26%, respectively, of the combined discounted future net revenues from our estimated proved reserves.

• As of December 31, 2002, Lee Keeling and Associates, Ryder Scott Company L.P., Netherland, Sewell & Associates, Inc., Williamson Petroleum Consultants, Inc. and our internal reservoir engineers evaluated 23%, 20%, 20%, 10% and 27%, respectively, of the combined discounted future net revenues from our estimated proved reserves.

• As of December 31, 2001, Ryder Scott Company L.P., Lee Keeling and Associates, Williamson Petroleum Consultants, Inc. and our internal reservoir engineers evaluated 26%, 24%, 22% and 28%, respectively, of the combined discounted future net revenues from our estimated proved reserves.

The information is presented in accordance with regulations prescribed by the Securities and Exchange Commission. Chesapeake emphasizes that reserve estimates are inherently imprecise. Our reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available.

Proved oil and gas reserves represent the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production responses that increased recovery will be achieved.

47

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Presented below is a summary of changes in estimated reserves of Chesapeake for 2003, 2002 and 2001:

	U.S.						Canada					Combined
	Oil (mbbl)		Gas (mmcf)		Total (mmcfe)		Oil (mbbl)	Gas (mmcf)		Total (mmcfe)		Oil (mbbl)		Gas (mmcf)		Total (mmcfe)
December 31, 2003
Proved reserves, beginning of period	37,587		1,979,601		2,205,125		—	—		—		37,587		1,979,601		2,205,125
Extensions, discoveries and other additions	3,574		359,681		381,123		—	—		—		3,574		359,681		381,123
Revisions of previous estimates	1,329		48,388		56,365		—	—		—		1,329		48,388		56,365
Production	(4,665	)	(240,366	)	(268,356	)	—	—		—		(4,665	)	(240,366	)	(268,356	)
Sale of reserves-in-place	(183	)	(9,626	)	(10,723	)	—	—		—		(183	)	(9,626	)	(10,723	)
Purchase of reserves-in-place	13,780		722,362		805,041		—	—		—		13,780		722,362		805,041
Proved reserves, end of period	51,422		2,860,040		3,168,575		—	—		—		51,422		2,860,040		3,168,575
Proved developed reserves:
Beginning of period	28,111		1,458,284		1,626,952		—	—		—		28,111		1,458,284		1,626,952
End of period	38,442		2,121,734		2,352,389		—	—		—		38,442		2,121,734		2,352,389
December 31, 2002
Proved reserves, beginning of period	30,093		1,599,386		1,779,946		—	—		—		30,093		1,599,386		1,779,946
Extensions, discoveries and other additions	4,348		217,116		243,205		—	—		—		4,348		217,116		243,205
Revisions of previous estimates	3,189		70,359		89,493		—	—		—		3,189		70,359		89,493
Production	(3,466	)	(160,682	)	(181,478	)	—	—		—		(3,466	)	(160,682	)	(181,478	)
Sale of reserves-in-place	(24	)	(1,003	)	(1,146	)	—	—		—		(24	)	(1,003	)	(1,146	)
Purchase of reserves-in-place	3,447		254,425		275,105		—	—		—		3,447		254,425		275,105
Proved reserves, end of period	37,587		1,979,601		2,205,125		—	—		—		37,587		1,979,601		2,205,125
Proved developed reserves:
Beginning of period	22,496		1,134,381		1,269,359		—	—		—		22,496		1,134,381		1,269,359
End of period	28,111		1,458,284		1,626,952		—	—		—		28,111		1,458,284		1,626,952
December 31, 2001
Proved reserves, beginning of period	23,797		1,053,069		1,195,849		—	158,964		158,964		23,797		1,212,033		1,354,813
Extensions, discoveries and other additions	2,425		256,616		271,167		—	—		—		2,425		256,616		271,167
Revisions of previous estimates	(2,750	)	(166,146	)	(182,644	)	—	—		—		(2,750	)	(166,146	)	(182,644	)
Production	(2,880	)	(135,096	)	(152,376	)	—	(9,075	)	(9,075	)	(2,880	)	(144,171	)	(161,451	)
Sale of reserves-in-place	—		—		—		—	(149,889	)	(149,889	)	—		(149,889	)	(149,889	)
Purchase of reserves-in-place	9,501		590,943		647,950		—	—		—		9,501		590,943		647,950
Proved reserves, end of period	30,093		1,599,386		1,779,946		—	—		—		30,093		1,599,386		1,779,946
Proved developed reserves:
Beginning of period	15,445		739,775		832,445		—	118,688		118,688		15,445		858,463		951,133
End of period	22,496		1,134,381		1,269,359		—	—		—		22,496		1,134,381		1,269,359

During 2003, Chesapeake acquired approximately 805 bcfe of proved reserves through purchases of oil and gas properties for consideration of $1,105 million (primarily in nine separate transactions of greater than $10 million each). We also sold 11 bcfe of proved reserves for consideration of approximately $22.2 million or $2.07 per mcfe. During 2003, we recorded upward revisions of 56 bcfe to the December 31, 2002 estimates of our reserves. Approximately 11.1 bcfe of the upward revisions was caused by higher oil and gas prices at December 31, 2003. Higher prices extend the economic lives of the underlying oil and gas properties and thereby increase the estimated future reserves. The weighted average oil and gas wellhead prices used in computing our reserves were $30.22 per bbl and $5.68 per mcf at December 31, 2003, compared to $30.18 per bbl and $4.28 per mcf at December 31, 2002.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

During 2002, Chesapeake acquired approximately 275 bcfe of proved reserves through purchases of oil and gas properties for consideration of $379 million (primarily in six separate transactions of greater than $10 million each). We also sold 1 bcfe of proved reserves for consideration of approximately $0.8 million. During 2002, we recorded upward revisions of 89 bcfe to the December 31, 2001 estimates of our reserves. Approximately 76 bcfe of the upward revisions was caused by higher oil and gas prices at December 31, 2002. Higher prices extend the economic lives of the underlying oil and gas properties and thereby increase the estimated future reserves. The weighted average oil and gas wellhead prices used in computing our reserves were $30.18 per bbl and $4.28 per mcf at December 31, 2002, compared to $18.82 per bbl and $2.51 per mcf at December 31, 2001.

During 2001, Chesapeake acquired 648 bcfe of proved reserves for consideration of $706 million in approximately 160 separate transactions (primarily in six separate transactions of greater than $10 million each). In October 2001, we sold our Canadian subsidiary, which had oil and gas operations primarily in northeast British Columbia, for approximately $143.0 million. Also during 2001, we recorded downward revisions to our U.S. oil and gas reserves of 183 bcfe. Approximately 156 bcfe of the downward revisions to our reserves was related to significantly lower gas and oil prices at December 31, 2001, which had the effect of reducing the economic life of our properties. The weighted average oil and gas wellhead prices used in computing our reserves were $18.82 per bbl and $2.51 per mcf at December 31, 2001, compared to $26.41 per bbl and $10.12 per mcf at December 31, 2000.

Standardized Measure of Discounted Future Net Cash Flows (unaudited)

Statement of Financial Accounting Standards No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Chesapeake has followed these guidelines which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. Estimated future income taxes are computed using current statutory income tax rates including consideration for the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process.

49

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following summary sets forth our future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in SFAS 69 ($ in thousands):

December 31, 2003
Future cash inflows(a)	$	17,807,624
Future production costs		(3,816,607	)
Future development costs		(912,594	)
Future income tax provision		(3,827,408	)
Net future cash flows		9,251,015
Less effect of a 10% discount factor		(3,924,262	)
Standardized measure of discounted future net cash flows	$	5,326,753
Discounted (at 10%) future net cash flows before income taxes	$	7,333,142
December 31, 2002
Future cash inflows(b)	$	9,640,070
Future production costs		(2,273,610	)
Future development costs		(606,042	)
Future income tax provision		(1,867,315	)
Net future cash flows		4,893,103
Less effect of a 10% discount factor		(2,059,185	)
Standardized measure of discounted future net cash flows	$	2,833,918
Discounted (at 10%) future net cash flows before income taxes	$	3,717,645
December 31, 2001
Future cash inflows(c)	$	4,586,743
Future production costs		(1,169,199	)
Future development costs		(450,181	)
Future income tax provision		(484,474	)
Net future cash flows		2,482,889
Less effect of a 10% discount factor		(1,021,916	)
Standardized measure of discounted future net cash flows	$	1,460,973
Discounted (at 10%) future net cash flows before income taxes	$	1,646,667

(a) Calculated using weighted average prices of $30.22 per barrel of oil and $5.68 per mcf of gas.

(b) Calculated using weighted average prices of $30.18 per barrel of oil and $4.28 per mcf of gas.

(c) Calculated using weighted average prices of $18.82 per barrel of oil and $2.51 per mcf of gas.

In October 2001, we sold our Canadian subsidiary, which had oil and gas operations primarily in northeast British Columbia, for net proceeds of approximately $143.0 million.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

December 31, 2003

	U.S.			Canada		Combined
	($ in thousands)
Standardized measure, beginning of period	$	2,833,918		$	—	$	2,833,918
Sales of oil and gas produced, net of production costs(a)		(1,088,184	)		—		(1,088,184	)
Net changes in prices and production costs		(2,364	)		—		(2,364	)
Extensions and discoveries, net of production and development costs		1,041,108			—		1,041,108
Changes in future development costs		74,719			—		74,719
Development costs incurred during the period that reduced future development costs		130,195			—		130,195
Revisions of previous quantity estimates		99,927			—		99,927
Purchase of reserves-in-place (b)		2,012,686			—		2,012,686
Sales of reserves-in-place (b)		(827	)		—		(827	)
Accretion of discount		371,765			—		371,765
Net change in income taxes		(1,122,661	)		—		(1,122,661	)
Changes in production rates and other		976,471			—		976,471
Standardized measure, end of period (c)	$	5,326,753		$	—	$	5,326,753

December 31, 2002

	U.S.			Canada		Combined
	($ in thousands)
Standardized measure, beginning of period	$	1,460,973		$	—	$	1,460,973
Sales of oil and gas produced, net of production costs(a)		(431,116	)		—		(431,116	)
Net changes in prices and production costs		779,756			—		779,756
Extensions and discoveries, net of production and development costs		463,674			—		463,674
Changes in future development costs		32,812			—		32,812
Development costs incurred during the period that reduced future development costs		68,387			—		68,387
Revisions of previous quantity estimates		137,639			—		137,639
Purchase of reserves-in-place		528,734			—		528,734
Sales of reserves-in-place		(535	)		—		(535	)
Accretion of discount		164,667			—		164,667
Net change in income taxes		(698,033	)		—		(698,033	)
Changes in production rates and other		326,960			—		326,960
Standardized measure, end of period (c)	$	2,833,918		$	—	$	2,833,918

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2001

	U.S.			Canada			Combined
	($ in thousands)
Standardized measure, beginning of period	$	3,575,320		$	487,941		$	4,063,261
Sales of oil and gas produced, net of production costs(a)		(492,184	)		(29,570	)		(521,754	)
Net changes in prices and production costs		(4,390,317	)		—			(4,390,317	)
Extensions and discoveries, net of production and development costs		292,051			—			292,051
Changes in future development costs		75,694			—			75,694
Development costs incurred during the period that reduced future development costs		32,955			—			32,955
Revisions of previous quantity estimates		(151,455	)		—			(151,455	)
Purchase of reserves-in-place		816,865			—			816,865
Sales of reserves-in-place		(157	)		(458,371	)		(458,528	)
Accretion of discount		536,523			—			536,523
Net change in income taxes		1,604,216			—			1,604,216
Changes in production rates and other		(438,538	)		—			(438,538	)
Standardized measure, end of period (c)	$	1,460,973		$	—		$	1,460,973

(a) Excluding unrealized gains (losses) on derivatives.

(b) Purchases and sales of reserves are shown net of the 9.9 bcfe which was acquired and immediately sold for $19 million.

(c) The discounted amounts related to cash flow hedges that would affect future net cash flows have not been included in any of the periods presented.

12. Asset Retirement Obligations

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

We identified and estimated all of our asset retirement obligations for tangible, long-lived assets as of January 1, 2003. These obligations were for future plugging and abandonment costs for depleted oil and gas wells. Prior to the adoption of SFAS 143, we included an estimate of our asset retirement obligations related to our oil and gas properties in our calculation of oil and gas depreciation, depletion and amortization expense. Upon adoption of SFAS 143, we recorded the discounted fair value of our expected future obligations 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. The pro-forma effect on prior periods’ financial position and results of operations was not material.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The components of the change in our asset retirement obligations are shown below:

	Twelve Months Ended December 31, 2003
	($ in thousands)
Asset retirement obligations, beginning balance	$	30,479
Additions and revisions		19,445
Settlements and disposals		(4,255	)
Accretion expense		3,143
Asset retirement obligations, ending balance	$	48,812

13. Acquisitions and Divestitures

Acquisitions. In January 2003 we acquired the stock of a subsidiary of ONEOK, Inc., in May the stock of Oxley Petroleum Company and in October the partnership interests in Laredo Energy LP for an aggregate purchase price of approximately $638 million. The assets of these entities were comprised mainly of proved and unproved oil and gas properties. These acquisitions were accounted for using the purchase method of accounting and, accordingly, results of operations of these acquired entities have been included in our results of operations from the respective closing dates of these acquisitions. Had these acquisitions been consummated at January 1, 2003, the effect on revenues and operating costs for 2003 would not have been significant. In addition to the above noted business combinations, during 2003 we acquired interests in leaseholds and proved and unproved oil and gas properties for aggregate purchase consideration of approximately $654 million. The largest purchase of oil and gas assets was a purchase from a subsidiary of El Paso Corporation for $510 million in March 2003. Acquisitions of both companies and oil and gas assets during 2002 and 2001 amounted to $393 million and $741 million, respectively.

Divestiture of Chesapeake Canada Corporation. In October 2001, we sold Chesapeake Canada Corporation, a wholly-owned subsidiary, for net proceeds of approximately $143.0 million.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

14. Quarterly Financial Data (unaudited)

Summarized unaudited quarterly financial data for 2003 and 2002 are as follows ($ in thousands except per share data):

	Quarters Ended
	March 31, 2003			June 30, 2003		September 30, 2003		December 31, 2003
Total revenues	$	376,327	(b)	$	429,815	$	454,549	$	456,741
Gross profit(a)		150,952			169,902		182,741		171,660
Net income before cumulative effect of accounting change, net of tax		71,120			82,240		87,859		69,373
Cumulative effect of accounting change, net of tax		2,389			—		—		—
Net income	$	73,509		$	82,240	$	87,859	$	69,373	(c)
Net earnings per share – basic:
Income before cumulative effect of accounting change	$	0.34		$	0.36	$	0.38	$	0.29
Cumulative effect of accounting change		0.01			—		—		—
	$	0.35		$	0.36	$	0.38	$	0.29
Net earnings per share – assuming dilution:
Income before cumulative effect of accounting change	$	0.31		$	0.31	$	0.33	$	0.25
Cumulative effect of accounting change		0.01			—		—		—
	$	0.32		$	0.31	$	0.33	$	0.25
	Quarters Ended
	March 31, 2002			June 30, 2002		September 30, 2002		December 31, 2002
Total revenues	$	89,989		$	193,690	$	196,466	$	258,357
Gross profit(a)		(19,817	)		62,067		57,723		91,685
Net income		(27,586	)		25,033		16,600		26,239
Net earnings per common share:
Basic	$	(0.18	)	$	0.14	$	0.08	$	0.14
Diluted	$	(0.18	)	$	0.13	$	0.08	$	0.13

(a) Total revenue less total operating costs.

(b) Gives effect to reclassification of unrealized gains (losses) on interest rate derivatives from risk management income (loss) to interest expense as discussed in Note 16 of the 2002 Form 10-K/A.

(c) Includes a pre-tax loss on repurchases of debt of $20.8 million.

15. Recent Accounting Pronouncements

During 2002 and 2003, the Financial Accounting Standards Board issued the following Statements of Financial Accounting Standards which were reviewed by Chesapeake to determine the potential impact on our financial statements upon adoption.

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In July 2002, the FASB issued SFAS No. 146,Accounting For Costs Associated with Exit or Disposal Activities. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002. We adopted this standard during the quarter ended March 31, 2003 and it did not have any impact on our financial position or results of operations.

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

In January 2003, the FASB issued Financial Interpretation No. 46,Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51. FIN 46 is an interpretation of Accounting Research Bulletin 51, “Consolidated Financial Statements,” and addresses consolidation of variable interest entities (VIEs) by business enterprises. The primary objective of FIN 46 is to provide guidance on the identification and financial reporting of entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses, receive a majority of the entity’s expected residual returns, or both. An enterprise shall consider the rights and obligations conveyed by its variable interest in making this determination. At December 31, 2003, Chesapeake did not have any entities that would qualify for consolidation in accordance with the provisions of FIN 46, as amended. Therefore, the adoption of FIN 46, as amended, did not have an impact on our consolidated financial statements.

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

In May 2003, the FASB issued SFAS No. 150,Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. This statement establishes new standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 requires that an issuer classify a financial instrument that is within the scope of this statement as a liability because the financial instrument embodies an obligation of the issuer. This statement applies to certain forms of mandatorily redeemable financial instruments including certain types of preferred stock, written put options and forward contracts. Adoption of this standard did not have any significant impact on our financial position or results of operations.

In December 2003, the Securities and Exchange Commission issued Staff Accounting Bulletin 104,Revenue Recognition. SAB 104 revises or rescinds certain guidance included in previously issued staff accounting

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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

bulletins in order to make this interpretive guidance consistent with current authoritative accounting and auditing guidance and SEC rules and regulations relating to revenue recognition. This bulletin was effective immediately upon issuance. Chesapeake’s current revenue recognition policies comply with SAB 104.

16. Subsequent Events

We completed an acquisition of Permian Basin and Mid-Continent oil and gas assets from Concho Resources Inc. in January 2004. We paid approximately $420 million in cash for these assets, $10 million of which was paid in 2003.

We also completed an acquisition of South Texas gas assets 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 from this offering of approximately $298.3 million to finance a portion of the acquisitions completed in January 2004.

On January 14, 2004, we completed a public exchange offer in which we retired $458.5 million of our 8.125% notes due 2011 and $10.8 million of accrued interest and issued $72.8 million of our 7.75% notes due 2015 and $2.8 million of accrued interest and $433.5 million of our 6.875% notes due 2016 and $4.1 million of accrued interest. The exchange of notes did not represent a substantial change in the terms of the debt instruments in accordance with EITF 96-19, accordingly, no gain or loss on debt extinguishment was recorded. We recognized transaction costs related to the exchange of approximately $6 million.

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

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Schedule II

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

($ in thousands)

	Balance at Beginning Of Period		Additions					Deductions		Balance at End of Period
Description			Charged To Expense			Charged To Other Accounts
December 31, 2003:
Allowance for doubtful accounts	$	1,433	$	156		$	1,202	$	122	$	2,669
Valuation allowance for deferred tax assets	$	2,441	$	4,364	(a)	$	—	$	—	$	6,805
December 31, 2002:
Allowance for doubtful accounts	$	947	$	315		$	171	$	—	$	1,433
Valuation allowance for deferred tax assets	$	2,441	$	—		$	—	$	—	$	2,441
December 31, 2001:
Allowance for doubtful accounts	$	1,085	$	69		$	44	$	251	$	947
Valuation allowance for deferred tax assets	$	—	$	2,441	(a)	$	—	$	—	$	2,441

(a) As of December 31, 2001, we determined that it is more likely than not that $2.4 million of the net deferred tax assets related to Louisiana net operating losses generated by Louisiana properties would not be realized and recorded a valuation allowance equal to such amount. During 2003, we determined that it was more likely than not that an additional $4.4 million of the deferred tax assets related to Louisiana net operating losses would not be realized and we recorded an additional valuation allowance equal to such amount.

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