CHESAPEAKE ENERGY CORP - 10-Q Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2005

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

For the transition period from to

Commission File No. 1-13726

Chesapeake Energy Corporation

(Exact Name of Registrant as Specified in Its Charter)


Oklahoma		73-1395733
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

6100 North Western Avenue Oklahoma City, Oklahoma		73118
(Address of principal executive offices)		(Zip Code)

(405) 848-8000

Registrant’s telephone number, including area code

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

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

As of May 5, 2005, there were 315,229,911 shares of our $0.01 par value common stock outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2005


		Page
PART I.
Financial Information

Item 1.	Condensed Consolidated Financial Statements (Unaudited):

	Condensed Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004	3

	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2005 and 2004	4

	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2005 and 2004	5

	Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2005 and 2004	6

	Notes to Condensed Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29

Item 4.	Controls and Procedures	33

PART II.
Other Information

Item 1.	Legal Proceedings	34

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34

Item 3.	Defaults Upon Senior Securities	34

Item 4.	Submission of Matters to a Vote of Security Holders	34

Item 5.	Other Information	34

Item 6.	Exhibits	34

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

PART I. FINANCIAL INFORMATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2005			December 31, 2004
	($ in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	6,896
Accounts receivable:
Oil and gas sales		332,693			347,081
Joint interest, net of allowances of $4,715,000 and $4,648,000, respectively		58,948			68,220
Related parties		10,341			8,286
Other		39,038			35,781
Deferred income tax asset		114,596			18,068
Short-term derivative instruments		104			51,061
Inventory and other		37,221			32,147

Total Current Assets		592,941			567,540

PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties		10,474,573			9,451,413
Unevaluated properties		928,777			761,785
Less: accumulated depreciation, depletion and amortization of oil and gas properties		(3,237,454	)		(3,057,742	)

Total oil and gas properties, at cost based on full-cost accounting		8,165,896			7,155,456
Other property and equipment		373,743			324,495
Drilling rigs		60,445			49,375
Less: accumulated depreciation and amortization of other property and equipment		(93,427	)		(84,942	)

Total Property and Equipment		8,506,657			7,444,384

OTHER ASSETS:
Investment in Pioneer Drilling		106,055			65,950
Other investments		30,186			26,793
Long-term derivative instruments		33,506			44,169
Other assets		74,066			95,673

Total Other Assets		243,813			232,585

TOTAL ASSETS	$	9,343,411		$	8,244,509

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	446,986		$	367,176
Accrued interest		51,852			66,514
Short-term derivative instruments		304,850			91,414
Other accrued liabilities		170,769			222,029
Revenues and royalties due others		191,384			216,820

Total Current Liabilities		1,165,841			963,953

LONG-TERM LIABILITIES:
Long-term debt, net		3,718,679			3,075,109
Deferred income tax liability		1,149,372			933,873
Asset retirement obligation		78,845			73,718
Long-term derivative instruments		25,730			1,296
Revenues and royalties due others		19,229			17,007
Other liabilities		17,514			16,670

Total Long-term Liabilities		5,009,369			4,117,673

CONTINGENCIES AND COMMITMENTS (Note 3)
STOCKHOLDERS’ EQUITY:
Preferred Stock, $.01 par value, 20,000,000 shares authorized:
6.00% cumulative convertible preferred stock, 102,610 and 103,110 shares issued and outstanding as of March 31, 2005 and December 31, 2004, respectively, entitled in liquidation to $5,130,500 and $5,155,500		5,131			5,156
5.00% cumulative convertible preferred stock, 1,725,000 shares issued and outstanding as of March 31, 2005 and December 31, 2004, entitled in liquidation to $172,500,000		172,500			172,500
4.125% cumulative convertible preferred stock, 313,250 shares issued and outstanding as of March 31, 2005 and December 31, 2004, entitled in liquidation to $313,250,000		313,250			313,250
Common Stock, $.01 par value, 500,000,000 shares authorized, 320,432,813 and 316,940,784 shares issued at March 31, 2005 and December 31, 2004, respectively		3,204			3,169
Paid-in capital		2,482,122			2,440,105
Retained earnings		368,549			262,987
Accumulated other comprehensive income (loss), net of tax of $54,059,000 and ($11,489,000), respectively		(94,048	)		20,425
Unearned compensation		(56,416	)		(32,618	)
Less: treasury stock, at cost; 5,329,341 and 5,072,121 common shares as of March 31, 2005 and December 31, 2004, respectively		(26,091	)		(22,091	)

Total Stockholders’ Equity		3,168,201			3,162,883

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	9,343,411		$	8,244,509

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended March 31,
	2005			2004
	($ in thousands, except per share data)
REVENUES:
Oil and gas sales	$	538,942		$	419,793
Oil and gas marketing sales		244,508			143,336

Total Revenues		783,450			563,129

OPERATING COSTS:
Production expenses		69,562			44,803
Production taxes		35,958			14,936
General and administrative expenses:
General and administrative (excluding stock-based compensation)		9,650			8,166
Stock-based compensation		2,417			1,869
Oil and gas marketing expenses		237,276			139,664
Oil and gas depreciation, depletion and amortization		180,968			119,908
Depreciation and amortization of other assets		10,082			5,739

Total Operating Costs		545,913			335,085

INCOME FROM OPERATIONS		237,537			228,044

OTHER INCOME (EXPENSE):
Interest and other income		3,357			1,343
Interest expense		(43,128	)		(46,545	)
Loss on repurchases or exchanges of Chesapeake debt		(900	)		(6,925	)

Total Other Income (Expense)		(40,671	)		(52,127	)

INCOME BEFORE INCOME TAXES		196,866			175,917
INCOME TAX EXPENSE:
Current		—			—
Deferred		71,856			63,327

Total Income Tax Expense		71,856			63,327

NET INCOME		125,010			112,590
PREFERRED STOCK DIVIDENDS		(5,463	)		(8,168	)

NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$	119,547		$	104,422

EARNINGS PER COMMON SHARE:
Basic	$	0.39		$	0.44

Assuming dilution	$	0.36		$	0.38

CASH DIVIDEND DECLARED PER COMMON SHARE	$	0.045		$	0.035

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in thousands):
Basic		309,857			236,884

Assuming dilution		351,357			299,604

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31,
	2005			2004
	($ in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$	125,010		$	112,590
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization		189,105			124,599
Unrealized losses on derivatives		114,083			22,739
Deferred income taxes		71,856			63,327
Amortization of loan costs		1,945			1,048
Amortization of bond discount		1,338			974
Stock-based compensation		2,417			1,869
Income from equity investments		(1,167	)		(422	)
Loss on repurchases or exchanges of Chesapeake debt		900			6,925
Other		(24	)		(95	)

Cash provided by operating activities before changes in assets and liabilities		505,463			333,554
Change in assets and liabilities		8,063			8,216

Cash provided by operating activities		513,526			341,770

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil and gas companies, proved properties and unproved properties, net of cash acquired		(625,407	)		(482,153	)
Exploration and development of oil and gas properties		(486,891	)		(235,888	)
Additions to buildings and other fixed assets		(43,046	)		(11,434	)
Additions to drilling rig equipment		(11,070	)		(2,466	)
Additions to investments		(7,518	)		—
Divestitures of oil and gas properties		—			249
Deposit for acquisition		—			(3,750	)
Other		(5	)		8

Cash used in investing activities		(1,173,937	)		(735,434	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings		1,166,000			381,000
Payments on long-term borrowings		(501,000	)		(381,000	)
Proceeds from issuance of preferred stock, net of offering costs		—			267,737
Proceeds from issuance of common stock, net of offering costs		—			298,107
Purchases or exchanges of senior notes, including redemption premiums		(11,841	)		(57,271	)
Common stock dividends		(13,916	)		(7,588	)
Preferred stock dividends		(5,464	)		(8,063	)
Financing costs of credit facility		(4,640	)		—
Purchases of treasury shares		(4,000	)		—
Net increase in outstanding payments in excess of cash balance		21,345			47,059
Cash received from exercise of stock options and warrants		8,682			2,706
Other financing costs		(1,651	)		(179	)

Cash provided by financing activities		653,515			542,508

Net increase (decrease) in cash and cash equivalents		(6,896	)		148,844
Cash and cash equivalents, beginning of period		6,896			40,581

Cash and cash equivalents, end of period	$	—		$	189,425

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended March 31,
	2005			2004
	($ in thousands)
Net Income	$	125,010		$	112,590
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments, net of income taxes of ($63,340,000) and ($36,804,000)		(110,195	)		(65,430	)
Reclassification of (gain) loss on settled contracts, net of income taxes of ($11,981,000) and ($6,581,000)		(20,843	)		(11,699	)
Ineffective portion of derivatives qualifying for cash flow hedge accounting, net of income taxes of $207,000 and $2,591,000		360			4,607
Unrealized gain on marketable securities, net of income taxes of $9,315,000		16,205			—

Comprehensive income	$	10,537		$	40,068

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation and Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements of Chesapeake Energy Corporation and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission. Chesapeake’s 2004 Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods have been reflected. The results for the three months ended March 31, 2005 are not necessarily indicative of the results to be expected for the full year. This Form 10-Q relates to the three months ended March 31, 2005 (the “Current Quarter”) and the three months ended March 31, 2004 (the “Prior Quarter”).

Stock-Based Compensation

Stock Options. Chesapeake has elected to follow APB No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for its employee and director stock options. Under APB No. 25, compensation expense is recognized for the difference between the option exercise price and market value on the measurement date. The original issuance of stock options has not resulted in the recognition of compensation expense because the exercise price of the stock options granted under the plans has equaled the market price of the underlying stock on the date of grant. 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 stock-based compensation expense (a sub-category of general and administrative expenses) arising from modifications made to previously issued stock options in the condensed consolidated statements of operations of $0.1 million in the Current Quarter and none in the Prior Quarter.

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 and director 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 the Current Quarter and the Prior Quarter, respectively: interest rates (zero-coupon U.S. government issues with a remaining life equal to the expected term of the options) ranging from 2.97% to 4.18%, dividend yields ranging from 0.82% to 1.04%, and volatility factors for the expected market price of our common stock ranging from 0.31 to 0.46. We used a weighted-average expected life of the options of five years for each of the quarters ended March 31, 2005 and March 31, 2004.

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


	Three Months Ended March 31,
	2005			2004
	($ in thousands, except per share amounts)
Net Income:
As reported	$	125,010		$	112,590
Stock-based compensation expense included in net income, net of tax		1,535			1,196
Pro forma compensation expense, net of tax		(3,887	)		(4,240	)

Pro forma	$	122,658		$	109,546

Basic earnings per common share
As reported	$	0.39		$	0.44

Pro forma	$	0.38		$	0.43

Diluted earnings per common share
As reported	$	0.36		$	0.38

Pro forma	$	0.35		$	0.37

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (continued)

For purposes of the pro forma disclosures, the estimated fair value of the options is amortized to expense over the option vesting period, which is four years for employee options.

In December 2004, the Financial Accounting Standards Board issued SFAS 123(R), Share-Based Payment, a revision of SFAS 123, accounting for stock-based compensation. This statement establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services by requiring a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost will be recognized over the period during which an employee is required to provide services in exchange for the award. The fair value of employee stock options will be estimated using option-pricing models. Excess tax benefits will be recognized as an addition to paid-in capital. Cash retained as a result of those excess tax benefits will be presented in the statement of cash flows as financing cash inflows. The write-off of deferred tax assets relating to unrealized tax benefits associated with recognized compensation cost will be recognized as income tax expense unless there are excess tax benefits from previous awards remaining in paid-in capital to which it can be offset. This statement was initially effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, in April 2005, the Securities and Exchange Commission adopted a new rule that amends the compliance dates for SFAS 123(R). The new rule allows the implementation of SFAS 123(R) at the beginning of the annual reporting period that begins after June 15, 2005, instead of the next reporting period. The SEC’s new rule only changes the date for compliance with the standard.

Chesapeake will implement SFAS 123(R) in the first quarter of 2006 and the Black-Scholes option pricing model will be used to value the stock options as of the grant date. Based on the stock options outstanding and unvested at March 31, 2005 and our current intention to limit future awards of stock options, we do not believe the new accounting requirement will have a significant impact on future results of operations.

Restricted Stock. Chesapeake issued 1.8 million shares and 1.1 million shares of restricted common stock to employees during the Current Quarter and the Prior Quarter, respectively. The total value of restricted shares granted is recorded as unearned compensation in stockholders’ equity based on the fair market value of the shares on the date of grant. This value is amortized over the vesting period, which is four years from the date of grant. To the extent amortization of compensation cost relates to employees directly involved in acquisition, exploration and development activities, such amounts are capitalized to oil and gas properties. Amounts not capitalized to oil and gas properties are recognized in stock-based compensation expense. Chesapeake recognized amortization of compensation cost related to restricted stock totaling $4.0 million and $1.9 million in the Current Quarter and Prior Quarter, respectively. Of these amounts, $2.2 million was reflected in stock-based compensation expense with the remaining $1.8 million capitalized to oil and gas properties in the Current Quarter and $1.9 million was reflected in stock-based compensation expense in the Prior Quarter. As of March 31, 2005, the unamortized balance of unearned compensation recorded as a reduction of stockholders’ equity was $56.4 million.

Critical Accounting Policies

We consider accounting policies related to stock options, hedging, oil and gas properties, income taxes and business combinations to be critical policies. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the year ended December 31, 2004, except for our accounting policy related to stock options which is summarized in Note 1 of the notes to the consolidated financial statements included in our 2004 annual report on Form 10-K.

2. Financial Instruments and Hedging Activities

Oil and Gas Hedging Activities

Our results of operations and operating cash flows are impacted by changes in market prices for oil and gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. As of March 31, 2005, our oil and gas derivative instruments were comprised of swaps, cap-swaps, basis protection swaps, call options and collars. These instruments allow us to predict with greater certainty the effective oil and gas prices to be received for our hedged production. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (continued)

•

For swap instruments, Chesapeake receives a fixed price for the hedged commodity and pays a floating market price 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.

•

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

•

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

•

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

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

With respect to counter-swaps that are designed to lock-in the value of cap-swaps, the counter-swap is effective in locking-in the value of the cap-swap until the floating price reaches the cap (or floor) stipulated in the cap-swap agreement. The value of the counter-swap will increase (or decrease), but in the opposite direction, as the value of the cap-swap decreases (or increases) until the floating price reaches the pre-determined cap (or floor) stipulated in the cap-swap agreement. However, because of the written put option embedded in the cap-swap, the changes in value of the cap-swap are not completely effective in offsetting changes in value of the corresponding counter-swap. Changes in the value of the cap-swaps and the counter-swaps are recorded as adjustments to oil and gas sales.

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

Chesapeake enters into basis protection swaps for the purpose of locking-in a price differential for oil or gas from a specified delivery point. We currently have basis protection swaps covering four different delivery points which correspond to the actual prices we receive for much of our gas production. By entering into these basis protection swaps, we have effectively reduced our exposure to market changes in future gas price differentials. As of March 31, 2005, the fair value of our basis protection swaps was $112.1 million. As of March 31, 2005, our basis protection swaps cover approximately 46% of our anticipated gas production in 2005, 28% in 2006, 26% in 2007, 23% in 2008 and 16% in 2009.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (continued)

$25.7 million, or $0.33 per mcfe, in the Prior Quarter. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e. temporary fluctuations in value) are reported currently in the consolidated statements of operations as unrealized gains (losses) within oil and gas sales. Unrealized gains (losses) included in oil and gas sales in the Current Quarter and the Prior Quarter were ($117.1) million and ($14.0) 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 as unrealized gains (losses). We recorded a gain (loss) on ineffectiveness of ($0.6) million and ($7.2) million in the Current Quarter and the Prior Quarter, respectively.

The estimated fair values of our oil and gas derivative instruments as of March 31, 2005 and December 31, 2004 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.


	March 31, 2005			December 31, 2004
	($ in thousands)
Derivative assets (liabilities):
Fixed-price gas swaps	$	(151,772	)	$	57,073
Fixed-price gas locked swaps		(66,263	)		(77,299	)
Fixed-price gas cap-swaps		(146,352	)		(48,761	)
Fixed-price gas counter-swaps		15,323			4,654
Gas basis protection swaps		112,085			122,287
Gas call options^(a)		(11,586	)		(5,793	)
Fixed-price gas collars		(9,544	)		(5,573	)
Fixed-price oil swaps		(4,180	)		—
Fixed-price oil cap-swaps		(21,080	)		(8,238	)

Estimated fair value	$	(283,369	)	$	38,350

(a)	After adjusting for the remaining $2.5 million and $3.2 million premium paid to Chesapeake by the counterparty, the cumulative unrealized loss related to these call options as of March 31, 2005 and December 31, 2004 was $9.1 million and $2.6 million, respectively.

Based upon the market prices at March 31, 2005, we expect to transfer approximately $109.8 million (net of income taxes) of the loss included in the balance in accumulated other comprehensive income to earnings during the next 12 months when the transactions actually close. All transactions hedged as of March 31, 2005 are expected to mature by December 31, 2007, with the exception of our basis protection swaps which extend through 2009.

Interest Rate Derivatives

We utilize hedging strategies to manage our exposure to changes in interest rates. To the extent 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. Changes in the fair value of derivative instruments not qualifying as fair value hedges are recorded currently as adjustments to interest expense.

As of March 31, 2005, the following interest rate swaps (which qualify as fair value hedges) used to convert a portion of our long-term fixed-rate debt to floating-rate debt were outstanding:


Term	Notional Amount		Fixed Rate		Floating Rate	Fair Value Gain (Loss)
						($ in thousands)
September 2004 – August 2012	$	75,000,000	9.000	%	6-month LIBOR plus 452 basis points	$	(2,113	)
February 2005 – June 2014	$	100,000,000	7.500	%	6-month LIBOR plus 287 basis points	$	(3,613	)
February 2005 – January 2015	$	150,000,000	7.750	%	6-month LIBOR plus 291 basis points	$	(4,718	)
March 2005 – August 2014	$	75,000,000	7.000	%	6-month LIBOR plus 205.5 basis points	$	(1,162	)
March 2005 – June 2015	$	100,000,000	6.375	%	6-month LIBOR in arrears plus 124 basis points	$	(1,652	)
March 2005 – June 2015	$	75,000,000	6.375	%	6-month LIBOR in arrears plus 114 basis points	$	(859	)
March 2005 – January 2016	$	75,000,000	6.875	%	6-month LIBOR in arrears plus 127 basis points	$	412

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (continued)

In the Current Quarter, we closed various interest rate swaps for gains totaling $0.8 million. These interest rate swaps were designated as fair value hedges, and the settlement amounts received will be amortized as a reduction to realized interest expense over the remaining terms of the related senior notes. Subsequent to the Current Quarter, we closed various interest rate swaps for gains totaling $1.3 million.

In March 2004, Chesapeake entered into an interest rate swap which required Chesapeake to pay a fixed rate of 8.68% while the counterparty paid Chesapeake a floating rate of six month LIBOR plus 0.75% on a notional amount of $142.7 million. On March 15, 2005, we elected to terminate the interest rate swap and paid $31.8 million to the counterparty.

In January 2004, Chesapeake acquired a $50 million interest rate swap as part of the purchase of Concho Resources Inc. Under the terms of the interest rate swap, the counterparty pays Chesapeake a floating three-month LIBOR rate and Chesapeake pays a fixed rate of 2.875%. Payments are made quarterly and the interest rate swap extends through September 2005. An initial liability of $0.6 million was recorded based on the fair value of the interest rate swap at the time of acquisition. As of March 31, 2005, the interest rate swap had a fair value of $0.1 million. Because this instrument is not designated as a fair value hedge, an unrealized gain of $0.1 million was recognized in the Current Quarter as an adjustment to interest expense.

Fair Value of Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards No. 107, Disclosures About Fair Value of Financial Instruments. We have determined the estimated fair values 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 derivatives, at March 31, 2005 and December 31, 2004 was $3,004.5 million and $3,014.1 million, respectively, compared to approximate fair values of $3,203.1 million and $3,281.1 million, respectively. The carrying amounts for our 6.00% convertible preferred stock, 5.00% convertible preferred stock and 4.125% convertible preferred stock as of March 31, 2005 were $5.1 million, $172.5 million and $313.3 million, respectively, with an approximate fair value of $8.7 million, $243.2 million and $313.3 million, respectively.

Concentration of Credit Risk

A significant portion of our liquidity is concentrated in derivative instruments that enable us to hedge a portion of our exposure to price volatility from producing oil and natural gas. These arrangements expose us to credit risk from our counterparties. Other financial instruments which potentially subject us to concentrations of credit risk consist principally of investments in equity instruments and accounts receivable. Our accounts receivable are primarily from purchasers of oil and natural gas products and exploration and production companies which own interests in properties we operate. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

3. Contingencies and Commitments

Litigation

Chesapeake is currently involved in various disputes incidental to its business operations. Management, after consultation with legal counsel, is of the opinion that the final resolution of all currently pending or threatened litigation is not likely to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (continued)

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 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 plus bonuses 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 contingent 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 March 31, 2005.

Other Commitments

At March 31, 2005, we had agreements to acquire certain South Texas oil and gas assets from two private parties for approximately $46 million. This transaction closed in April 2005. Subsequent to March 31, 2005, we signed agreements to acquire various oil and gas assets for approximately $413 million which are scheduled to close in the second quarter of 2005.

As of March 31, 2005, we owned 12 rigs dedicated to drilling wells operated by Chesapeake and 13 additional rigs are under construction or on order. We expect to spend approximately $110 million to complete the rigs under construction.

4. Net Income Per Share

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

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

•

For the Current Quarter and the Prior Quarter, outstanding options to purchase 0.1 million and 0.2 million shares of common stock at a weighted-average exercise price of $30.63 and $21.05, respectively, were antidilutive because the exercise prices of the options were greater than the average market price of the common stock during the respective periods.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (continued)

•

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

The Emerging Issues Task Force (EITF) Issue 04-8, The Effect of Contingently Convertible Instruments on Diluted Earnings Per Share, which was issued in September 2004, provides new guidance on when the dilutive effect of contingently convertible securities with a market price trigger should be included in diluted EPS. The new guidance states that these securities should be included in the diluted EPS computation regardless of whether the market price trigger has been met. The guidance in EITF 04-8 is effective for all periods ending after December 15, 2004 and has been applied retrospectively by restating previously reported EPS. Accordingly, effective December 15, 2004, the company has assumed the conversion of the 4.125% convertible preferred shares issued in 2004 (if dilutive) for purposes of determining earnings per share assuming dilution.

Reconciliations for the quarters ended March 31, 2005 and 2004 are as follows:


	Income (Numerator)		Shares (Denominator)	Per Share Amount
	(in thousands, except per share data)
For the Quarter Ended March 31, 2005:
Basic EPS:
Income available to common shareholders	$	119,547	309,857	$	0.39

Effect of Dilutive Securities
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 4.125% convertible preferred stock		—	18,812
Common shares assumed issued for 5.00% convertible preferred stock		—	10,516
Common shares assumed issued for 6.00% convertible preferred stock		—	499
Common stock equivalent of 6.00% preferred stock outstanding prior to conversion		—	2
Preferred stock dividends		5,463	—
Employee stock options		—	10,662
Restricted stock		—	986
Warrants assumed in Gothic acquisition		—	23

Diluted EPS Income available to common shareholders and assumed conversions	$	125,010	351,357	$	0.36

For the Quarter Ended March 31, 2004:
Basic EPS:
Income available to common shareholders	$	104,422	236,884	$	0.44

Effect of Dilutive Securities
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 4.125% convertible preferred stock		—	363
Common shares assumed issued for 5.00% convertible preferred stock		—	10,516
Common shares assumed issued for 6.00% convertible preferred stock		—	22,358
Common shares assumed issued for 6.75% convertible preferred stock		—	19,467
Preferred stock dividends		8,168	—
Employee stock options		—	9,863
Restricted stock		—	153

Diluted EPS Income available to common shareholders before cumulative effect of accounting change, net of tax	$	112,590	299,604	$	0.38

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (continued)

5. Senior Notes and Revolving Bank Credit Facility

Our long-term debt consisted of the following as of March 31, 2005 and December 31, 2004:


	March 31, 2005			December 31, 2004
	($ in thousands)
8.375% Senior Notes due 2008	$	7,990		$	18,990
8.125% Senior Notes due 2011		245,407			245,407
9.0% Senior Notes due 2012		300,000			300,000
7.5% Senior Notes due 2013		363,823			363,823
7.0% Senior Notes due 2014		300,000			300,000
7.5% Senior Notes due 2014		300,000			300,000
7.75% Senior Notes due 2015		300,408			300,408
6.375% Senior Notes due 2015		600,000			600,000
6.875% Senior Notes due 2016		670,437			670,437
Revolving bank credit facility		724,000			59,000
Discount on senior notes		(83,578	)		(84,924	)
Premium (discount) for interest rate derivatives^(a)		(9,808	)		1,968

Total senior notes and long-term debt	$	3,718,679		$	3,075,109

(a)	See note 2 for further discussion related to these instruments.

We have repurchased or exchanged Chesapeake debt and incurred losses in connection with certain of these transactions. The following table sets forth these transactions ($ in millions):


	Notes Retired		Loss on Repurchases/Exchanges
	Notes Retired		Premium		Other^(a)		Total
For the Quarter Ended March 31, 2005:
8.375% Senior Notes due 2008	$	11.0	$	0.8	$	0.1	$	0.9

For the Quarter Ended March 31, 2004:
7.875 % Senior Notes due 2004	$	42.1	$	—	$	—	$	—
8.5% Senior Notes due 2012		4.3		0.2		0.7		0.9
8.125% Senior Notes due 2011		482.8		—		6.0		6.0
7.75% Senior Notes due 2015		9.1		—		—		—

	$	538.3	$	0.2	$	6.7	$	6.9

(a)	Includes the write-off of unamortized discounts, deferred charges, transaction costs and derivative charges.

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 our 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 payments; mergers or consolidations; and transactions with affiliates.

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 all of our subsidiaries.

We have a $1.25 billion revolving bank credit facility which matures in January 2010. As of March 31, 2005, we had $724.0 million of outstanding borrowings under our facility and utilized $57.7 million of the facility for various letters of credit. Borrowings under our facility are collateralized by certain producing oil and gas properties and bear interest at either (i) the greater of the reference rate of Union Bank of California, N.A. or the federal funds effective rate plus 0.50% or (ii) the London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are determined periodically. The unused portion of the facility is subject to an annual commitment fee that also varies according to our senior unsecured long-term debt ratings. Currently, the annual commitment fee rate is 0.30%. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The credit facility agreement contains various covenants and restrictive provisions which govern our ability to incur additional indebtedness, sell properties, purchase or redeem our capital stock, make investments or loans, and create liens. The credit facility agreement requires us to maintain a fixed charge coverage ratio (as defined) of at least 2.5 to 1 and an indebtedness to EBITDA ratio (as defined) not to exceed 3.5 to 1. At March 31, 2005, our fixed charge

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (continued)

coverage ratio was 5.9 to 1 and our indebtedness to EBITDA ratio was 2.3 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 $50 million.

In May 2004, we entered into a secured natural gas hedging facility with a nationally recognized counterparty. Under this hedging facility, which matures in May 2009, we can enter into cash-settled natural gas and oil commodity transactions, valued by the counterparty, for up to $600 million. Outstanding transactions under the facility are collateralized by certain oil and gas properties, exclusive of the oil and gas properties that collateralize our revolving bank credit facility. The hedging facility is subject to an annual fee of 0.30% of the maximum total capacity and a 1.0% exposure fee, which is assessed quarterly on the average of the daily negative fair market value amounts, if any, during the quarter. As of March 31, 2005, the fair market value of the natural gas and oil hedging transactions related to the hedging facility was a liability of $76.6 million.

The hedging facility contains the standard representations and default provisions that are typical of such agreements. The agreement also contains various restrictive provisions which govern the aggregate gas and oil production volumes that we are permitted to hedge under all of our agreements at any one time.

6. Segment Information

In accordance with Statement of Financial Accounting Standards No. 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 $405.2 million and $272.1 million for the Current Quarter and Prior Quarter, respectively.

Management evaluates the performance of our segments based upon income before income taxes.


	Exploration and Production		Marketing		Consolidated
For the Three Months Ended March 31, 2005:
Revenues	$	538,942	$	244,508	$	783,450
Income before income taxes		195,106		1,760		196,866
For the Three Months Ended March 31, 2004:
Revenues	$	419,793	$	143,336	$	563,129
Income before income taxes		174,947		970		175,917
As of March 31, 2005:
Total assets	$	8,997,447	$	345,964	$	9,343,411
As of December 31, 2004:
Total assets	$	7,926,263	$	318,246	$	8,244,509

7. Acquisitions

In February 2005, we acquired Mid-Continent and Ark-La-Tex oil and natural gas assets through the purchase of the stock of BRG Petroleum Corporation and the acquisition of various other related partnership interests for cash consideration of approximately $325 million, of which $16.3 million was paid in 2004. In March 2005, we acquired South Texas oil and natural gas assets from Laredo Energy II, L.L.C. for cash consideration of approximately $227.5 million. These acquisitions were financed using borrowings from our revolving credit facility.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (continued)

In addition to the acquisitions mentioned previously, we invested approximately $32 million to acquire various other oil and natural gas properties during the Current Quarter.

Results of operations of these acquired activities and oil and gas properties have been included in Chesapeake’s results of operations from the respective closing dates of the acquisitions.

8. Recently Issued Accounting Standards

The Financial Accounting Standards Board and the Securities and Exchange Commission recently issued the following standards which were reviewed by Chesapeake to determine the potential impact on our financial statements upon adoption.

In September 2004, the Emerging Issues Task Force issued EITF No. 04-8, The Effect of Contingently Convertible Instruments on Diluted Earnings Per Share. EITF No. 04-8 provides new guidance on when the dilutive effect of contingently convertible securities with a market price trigger should be included in diluted EPS. The guidance in EITF No. 04-8 is effective for all periods ending after December 15, 2004 and Chesapeake has complied by retrospectively restating previous reported EPS. The effect of this pronouncement on diluted EPS is more fully described in note 4.

In March 2005, the FASB issued FASB Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement Obligations. FIN 47 specifies the accounting treatment for conditional asset retirement obligations under the provisions of Statement of Financial Accounting Standards No. 143. FIN 47 is effective no later than the end of the fiscal year ending after December 15, 2005. We plan to adopt this statement effective December 31, 2005. Implementation of FIN 47 is not expected to have a material effect on our financial statements.

9. Subsequent Events

In April 2005, we completed private offerings of $600 million principal amount of 6.625% Senior Notes due 2016 and 4,600,000 shares of 5.0% convertible preferred stock having a liquidation preference of $100 per share. Net proceeds of $1,031.5 million from these transactions were used to finance acquisitions totaling $459 million scheduled to close in the second quarter of 2005 and to repay debt incurred under our credit facility for acquisitions completed in the Current Quarter.

PART I. FINANCIAL INFORMATION

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

Overview

The following table sets forth certain information regarding the production volumes, oil and gas sales, average sales prices received and expenses for the three months ended March 31, 2005 (the “Current Quarter”) and the three months ended March 31, 2004 (the “Prior Quarter”) :


	Three Months Ended March 31,
	2005			2004
Net Production:
Oil (mbbl)		1,746			1,465
Gas (mmcf)		94,131			70,098
Gas equivalent (mmcfe)		104,607			78,888
Oil and Gas Sales ($ in thousands):
Oil sales	$	79,944		$	48,031
Oil derivatives – realized gains (losses)		(7,067	)		(8,330	)
Oil derivatives – unrealized gains (losses)		(12,842	)		(6,019	)

Total oil sales		60,035			33,682

Gas sales		535,777			360,101
Gas derivatives – realized gains (losses)		47,415			33,991
Gas derivatives – unrealized gains (losses)		(104,285	)		(7,981	)

Total gas sales		478,907			386,111

Total oil and gas sales	$	538,942		$	419,793

Average Sales Price (excluding all gains (losses) on derivatives):
Oil ($ per bbl)	$	45.79		$	32.79
Gas ($ per mcf)	$	5.69		$	5.14
Gas equivalent ($ per mcfe)	$	5.89		$	5.17
Average Sales Price (excluding unrealized gains (losses) on derivatives):
Oil ($ per bbl)	$	41.74		$	27.10
Gas ($ per mcf)	$	6.20		$	5.62
Gas equivalent ($ per mcfe)	$	6.27		$	5.50
Expenses ($ per mcfe):
Production expenses	$	0.66		$	0.57
Production taxes^(a)	$	0.34		$	0.19
General and administrative expenses:
General and administrative expenses (excluding stock-based compensation)	$	0.09		$	0.10
Stock-based compensation	$	0.02		$	0.02
Oil and gas depreciation, depletion and amortization	$	1.73		$	1.52
Depreciation and amortization of other assets	$	0.10		$	0.07
Interest expense ^(b)	$	0.44		$	0.48
Interest Expense ($ in thousands):
Interest expense	$	47,293		$	38,564
Interest rate derivatives – realized (gains) losses		(1,121	)		(758	)
Interest rate derivatives – unrealized (gains) losses		(3,044	)		8,739

Total interest expense	$	43,128		$	46,545

Net Wells Drilled		169			109
Net Producing Wells as of the End of Period		8,611			6,661

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

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

Chesapeake is the fourth largest independent producer of natural gas in the U.S. and owns interests in approximately 20,700 producing oil and gas wells. Our primary operating area is the Mid-Continent region of the United States, which includes Oklahoma, western Arkansas, southwestern Kansas and the Texas Panhandle, and we are building significant secondary operating areas in the South Texas and Texas Gulf Coast regions, the Permian Basin of western Texas and eastern New Mexico and in the Barnett Shale and Ark-La-Tex areas of central and eastern Texas and northern Louisiana.

Our revenues, operating results, profitability and future growth depend on our ability to find, develop and acquire oil and gas reserves that are economically recoverable based on prevailing prices for natural gas and oil. We favor gas over oil, strive to establish regional dominance in our operating areas, have grown through a combination of drilling and acquisitions and manage price risk through opportunistic oil and natural gas hedging. We believe we have the largest onshore U.S. inventories of leasehold and 3-D seismic data (more than 3.5 million and 10 million net acres, respectively) with a seven year drilling backlog of approximately 7,000 locations.

Oil and natural gas production for the Current Quarter was 104.6 bcfe, an increase of 25.7 bcfe, or 33%, over the 78.9 bcfe produced in the Prior Quarter. We have increased our production for 15 consecutive quarters. During these 15 quarters, Chesapeake’s U.S. production has increased 190%, for an average compound quarterly growth rate of 7.4% and an average compound annual growth rate of 32.6%.

In addition to increased oil and natural gas production, the prices we received were higher in the Current Quarter than in the Prior Quarter. On a natural gas equivalent basis, weighted average prices (excluding the effect of unrealized gains or losses on derivatives) were $6.27 per mcfe in the Current Quarter compared to $5.50 per mcfe in the Prior Quarter. The increase in prices resulted in an increase in revenue of $80.8 million, and increased production resulted in an increase in revenue of $141.5 million, for a total increase in revenue of $222.3 million (excluding the effect of unrealized gains or losses on derivatives). In each of the core operating areas where Chesapeake sells its oil and natural gas, established marketing and transportation infrastructures exist thereby contributing to relatively high wellhead price realizations on all properties in which we own an economic interest.

Chesapeake began the Current Quarter with estimated proved reserves of 4,901.7 bcfe and ended the quarter with 5,434.0 bcfe. Taking into account production of 104.6 bcfe, reserve replacement during the quarter was 636.9 bcfe, or 609% of our production. Reserve additions through the drill bit were 332.6 bcfe (including 45.1 bcfe from positive performance revisions and 29.9 bcfe from revisions due to oil and natural gas price increases), or 52% of the total increase in the Current Quarter, and reserve additions through acquisitions were 304.3 bcfe, or 48% of the total increase.

During the Current Quarter, Chesapeake drilled 189 (143 net) operated wells and participated in another 209 (26 net) wells operated by other companies. Chesapeake’s drilling costs were $302 million for operated wells and $75 million for non-operated wells. The company’s success rate was 98%. Our investment in leasehold and 3-D seismic data totaled $66 million (exclusive of leases acquired through acquisitions) and our acquisition expenditures totaled $385 million during the Current Quarter (excluding $120 million of deferred taxes in connection with certain corporate acquisitions).

We have taken several actions to mitigate higher field service costs, ensure our timely access to drilling rigs and participate in service industry growth. Through our wholly owned subsidiary Nomac Drilling Corporation, we have 12 rigs dedicated to Chesapeake-operated wells and we have an additional 13 rigs on order for delivery between now and 2006. In addition, we have entered into drilling contracts for the use of 17 rigs currently being built or refurbished by private drilling companies, to be available to us in 2005 and 2006. We also have invested $42.7 million in the common stock of publicly held Pioneer Drilling Company over the past two years, including $14.3 million in the Current Quarter, and now hold 17% of its outstanding common stock. At March 31, 2005, our Pioneer shares had a market value of $106.1 million.

As of March 31, 2005, the company’s debt as a percentage of total capitalization (total capitalization is the sum of debt and stockholders’ equity) was 54%, compared to 49% as of December 31, 2004. In April 2005, we received

net proceeds of $1,031.5 million through issuances of $460 million of preferred equity (5.0% convertible preferred stock) and $600 million principal amount of 6.625% Senior Notes due 2016. On a pro forma basis, this reduced our debt to total capitalization to 51% as of March 31, 2005. On a pro forma basis to include our April 2005 senior notes and preferred stock offerings, we have extended the average maturity of our long-term debt to over nine years and have lowered our average interest rate to approximately 7.2%.

We intend to continue to focus on improving the strength of our balance sheet. We believe our business strategy and operational performance will lead to an investment grade credit rating for our unsecured debt in the future.

Liquidity and Capital Resources

Sources of Liquidity

Our primary source of liquidity to meet operating expenses and fund capital expenditures (other than for certain acquisitions) is cash flow from operations. Based on our current production, price and expense assumptions, we expect cash flow from operations will exceed our drilling capital expenditures in 2005. Our budget for drilling, land and seismic activities during 2005 is currently between $1.7 billion and $1.9 billion. While we believe this level of exploration and development will be sufficient to increase our reserves in 2005 and achieve our goal of a 10% to 20% increase in production over 2004 production (inclusive of acquisitions completed or scheduled to close in 2005 through the filing date of this report but without regard to any additional acquisitions that may be completed in 2005), higher drilling and field operating costs, drilling results that alter planned development schedules, acquisitions or other factors could cause us to revise our drilling program, which is largely discretionary. Any cash flow from operations not needed to fund our drilling program will be available for acquisitions, debt repayment or other general corporate purposes in 2005.

Cash provided by operating activities (exclusive of changes in assets and liabilities) was $505.5 million in the Current Quarter compared to $333.6 million in the Prior Quarter. The $171.9 million increase in the Current Quarter was primarily due to higher realized prices and higher volumes of oil and gas production. We expect that 2005 production volumes will be higher than in 2004 and that cash provided by operating activities in 2005 will exceed 2004 levels. While a precipitous decline in gas prices in 2005 would significantly affect the amount of cash flow that would be generated from operations, we have 45% of our expected oil production in 2005 hedged at an average NYMEX price of $45.01 per barrel of oil and 57% of our expected natural gas production in 2005 hedged at an average NYMEX price of $6.44 per mcf. This level of hedging provides certainty of the cash flow we will receive for a substantial portion of our 2005 production. Depending on changes in oil and gas futures markets and management’s view of underlying oil and natural gas supply and demand trends, however, we may increase or decrease our current hedging positions.

Based on fluctuations in natural gas and oil prices, our hedging counterparties may require us to deliver cash collateral or other assurances of performance from time to time. At March 31, 2005 and May 6, 2005, we had issued $55 million and $25 million, respectively, of letters of credit securing our performance of hedging contracts. To mitigate the liquidity impact of those collateral requirements, we have negotiated caps on the amount of collateral that we might be required to post with five of our counterparties. All of our existing commodity hedges that are not under our secured hedge facility (described below under Contractual Obligations) are with these counterparties and the maximum amount of collateral that we would be required to post with these counterparties is capped at $230 million.

A significant source of liquidity is our $1.25 billion revolving bank credit facility which matures in January 2010. At May 6, 2005, there was $884.3 million of borrowing capacity available under the revolving bank credit facility. We use the facility to fund daily operating activities and acquisitions as needed. We borrowed $1,166.0 million and repaid $501.0 million in the Current Quarter, and we borrowed and repaid $381.0 million in the Prior Quarter under our bank credit facility. We incurred $4.6 million of financing costs related to our revolving credit facility in the Current Quarter as a result of the amendment to the credit agreement.

We believe that our available cash, cash provided by operating activities and funds available under our revolving bank credit facility will be sufficient to fund our operating, interest and general and administrative expenses, our capital expenditure budget, our short-term contractual obligations and dividend payments at current levels for the foreseeable future. Our revolving bank credit facility and secured hedge facility are both syndicated facilities, neither of which contains material adverse or adequate assurance clauses. Although the applicable interest rates and commitment fees in our bank credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, neither the bank facility nor the secured hedge facility contains provisions which would trigger an acceleration of amounts due under the facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings.

The public and institutional markets have been our principal source of long-term financing for acquisitions. We have sold debt and equity in both public and private offerings in the past, and we expect that these sources of capital will continue to be available to us in the future for acquisitions. Nevertheless, we caution that ready access to capital on reasonable terms and the availability of desirable acquisition targets at attractive prices are subject to many uncertainties, as explained under “Risk Factors” in Item 1—Business of our Form 10-K for the year ended December 31, 2004.

The following table reflects the proceeds from sales of securities we issued in the Prior Quarter ($ in millions):


	Total Proceeds		Net Proceeds
Convertible preferred stock	$	275.0	$	267.7
Common stock		310.7		298.1

Total	$	585.7	$	565.8

There were no sales of debt or equity securities in the Current Quarter. In April 2005, we issued senior notes and preferred stock as described below.

We filed a $600 million “universal shelf” registration statement with the Securities and Exchange Commission in September 2004. Securities issued under this shelf may be in the form of common stock, preferred stock, depository shares representing fractional shares of preferred stock or debt securities of Chesapeake. A prospectus supplement will be prepared at the time of a debt or equity offering and will contain specific information about the security issued and the use of proceeds. No securities have been issued under this shelf registration statement.

We paid dividends on our common stock of $13.9 million and $7.6 million in the Current Quarter and the Prior Quarter, respectively, and we paid dividends on our preferred stock of $5.5 million and $8.1 million in the Current Quarter and the Prior Quarter, respectively. We received $8.7 million and $2.7 million from the exercise of employee and director stock options and warrants in the Current Quarter and the Prior Quarter, respectively.

Outstanding payments from certain disbursement accounts in excess of funded cash balances where no legal right of set-off exists increased by $21.3 million and $47.1 million in the Current Quarter and the Prior Quarter, respectively. All disbursements are funded on the day they are presented to our bank using available cash on hand or draws on our credit facility.

Historically, we have used significant funds to purchase and retire outstanding senior notes issued by Chesapeake. The following table shows our purchases and exchanges of senior notes ($ in millions):


	Senior Notes Activity
	Retired		Premium		Other ^(a)		Issued^(b)			Cash Paid
For the Quarter Ended March 31, 2005:
8.375% Senior Notes due 2008	$	11.0	$	0.8	$	—	$	—		$	11.8

For the Quarter Ended March 31, 2004:
7.875% Senior Notes due 2004	$	42.1	$	—	$	—	$	—		$	42.1
8.5% Senior Notes due 2012		4.3		0.2		—		—			4.5
8.125% Senior Notes due 2011		482.8		—		61.5		(533.6	)		10.7
7.75% Senior Notes due 2015		9.1		—		0.6		(9.7	)		—

	$	538.3	$	0.2	$	62.1	$	(543.3	)	$	57.3

(a)	Includes adjustments to accrued interest and discount associated with notes retired and new notes issued, cash in lieu of fractional notes, transaction costs and fair value hedging adjustments.

(b)	We issued $72.8 million of our 7.75% Senior Notes and $470.5 million of our 6.875% Senior Notes.

Cash used in investing activities increased to $1,173.9 million during the Current Quarter, compared to $735.4 million during the Prior Quarter. The following table shows our capital expenditures during these quarters ($ in millions):


	Three Months Ended March 31,
	2005		2004
Exploration and development of oil and gas properties	$	486.9	$	235.9
Acquisitions of oil and gas companies, proved and unproved properties, net of cash acquired		625.4		482.2
Additions to buildings and other fixed assets		43.0		11.4
Additions to drilling rig equipment		11.1		2.5
Additions to investments		7.5		—
Deposit for acquisition		—		3.7
Divestitures of oil and gas properties and other		—		(0.3	)

Total	$	1,173.9	$	735.4

During 2004 and continuing in 2005, we have taken several steps to improve our capital structure. These transactions enabled us to extend our average maturity of long-term debt to over nine years with an average interest rate of approximately 7.2%. As of March 31, 2005, the company’s debt as a percentage of total capitalization increased to 54% compared to 49% as of December 31, 2004 and debt per mcfe of proved reserves increased to $0.68 per mcfe as compared to $0.63 per mcfe as of December 31, 2004. Subsequent to March 31, 2005, we received net proceeds of $1,031.5 million through issuances of $460 million of preferred equity (5.0% convertible preferred stock) and $600 million principal amount of 6.625% Senior Notes due 2016. On a pro forma basis to include our April 2005 senior notes and preferred stock offerings, our debt to capitalization ratio decreased to 51% as of March 31, 2005. Achieving a debt-to-total-capitalization ratio of below 50% and reducing debt per mcfe of proved reserves remain key goals of our business strategy.

Our accounts receivable are primarily from purchasers of oil and natural gas ($332.7 million at March 31, 2005) and exploration and production companies which own interests in properties we operate ($58.9 million at March 31, 2005). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

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

Investing and Financing Transactions

The following table describes significant investing transactions that we completed in the Current Quarter ($ in millions):


Acquisition	Location	Amount
BRG Petroleum Corporation	Mid-Continent and Ark-La-Tex	$	325	^(a)
Laredo Energy II, L.L.C.	South Texas		228
Other	Various		89	^(b)

		$	642

(a)	We paid $16.3 million of the purchase amount in 2004.

(b)	During the Current Quarter, we paid the remaining $57 million of the purchase price related to the Hallwood acquisition.

Financing Transactions

First Quarter 2005

•

Amended our revolving bank credit facility to increase the committed borrowing base to $1.25 billion and extend the maturity of the facility to January 2010.

•

Completed a private purchase of $11.0 million of our 8.375% Senior Notes due 2008 for $12.0 million (including premium of $0.8 million and accrued interest of $0.2 million).

April 2005

•

In April 2005, we completed private offerings of $600 million principal amount of 6.625% Senior Notes due 2016 and 4,600,000 shares of 5.0% convertible preferred stock having a liquidation preference of $100 per share. Net proceeds of $1,031.5 million from these transactions were used to finance acquisitions totaling $459 million that closed in the second quarter of 2005 and to repay debt incurred under our credit facility to temporarily finance the BRG and the Laredo acquisitions completed in the Current Quarter.

Contractual Obligations

We currently have a $1.25 billion revolving bank credit facility which matures in January 2010. The credit facility was increased from $600 million to $1.25 billion in January 2005. As of March 31, 2005, we had $724.0 million of outstanding borrowings under this facility and had utilized $57.7 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 (i) the greater of the reference rate of Union Bank of California, N.A., or the federal funds effective rate plus 0.50% or (ii) London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are redetermined periodically. The unused portion of the facility is subject to an annual commitment fee that also varies according to our senior unsecured long-term debt ratings. Currently the annual commitment fee is 0.30%. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, sell properties, purchase or redeem our capital stock, make investments or loans, and create liens. The credit facility agreement requires us to maintain a fixed charge coverage ratio (as defined) of at least 2.5 to 1 and an indebtedness to EBITDA ratio (as defined) not to exceed 3.5 to 1. At March 31, 2005, our fixed charge coverage ratio was 5.9 to 1 and our indebtedness to EBITDA ratio was 2.3 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 $50 million.

Some of our commodity price and financial risk management arrangements require us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations exceed certain levels. As of March 31, 2005, we were required to post $55 million of collateral in the form of letters of credit with respect to such derivative transactions. These collateral requirements were $25 million as of May 6, 2005. Future collateral requirements are uncertain and will depend on arrangements with our counterparties and fluctuations in natural gas and oil prices and interest rates. We currently have arrangements with five of our counterparties which limit the amount of collateral that we would be required to post with them to no more than $230 million in the aggregate.

Our subsidiary, Chesapeake Exploration Limited Partnership, is the borrower under our revolving bank credit facility and is the named party to our hedging facility. The facilities are guaranteed by Chesapeake and all its other subsidiaries. Our revolving bank credit facility and secured hedge facility are both syndicated facilities, neither of which contains material adverse or adequate assurance clauses. Although the applicable interest rates and commitment fees in our bank credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, neither the bank facility nor the secured hedge facility contains provisions which would trigger an acceleration of amounts due under the facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings.

In addition to outstanding revolving bank credit facility borrowings discussed above, as of March 31, 2005, our senior notes represented approximately $3.0 billion of our long-term debt and consisted of the following ($ in thousands):


8.375% senior notes due 2008	$	7,990
8.125% senior notes due 2011		245,407
9.0% senior notes due 2012		300,000
7.5% senior notes due 2013		363,823
7.0% senior notes due 2014		300,000
7.5% senior notes due 2014		300,000
7.75% senior notes due 2015		300,408
6.375% senior notes due 2015		600,000
6.875% senior notes due 2016		670,437
Discount on senior notes		(83,578	)
Discount for interest rate swap		(9,808	)

	$	2,994,679

No scheduled principal payments are required on any of the senior notes until 2008, when $8.0 million is due.

Debt ratings for the senior notes are Ba3 by Moody’s Investor Service (positive outlook), BB- by Standard & Poor’s Ratings Services (positive outlook) and BB by Fitch Ratings.

Our senior notes are unsecured senior obligations of Chesapeake and rank equally with all of our other unsecured indebtedness. All of our wholly owned subsidiaries guarantee the notes. The indentures permit us to redeem the senior notes at any time at specified make-whole or redemption prices. The indentures contain covenants limiting our ability and our restricted subsidiaries’ ability to incur additional indebtedness; pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; make investments and other restricted payments; incur liens; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The debt incurrence covenants do not presently restrict our ability to borrow under or expand our secured credit facility. As of March 31, 2005, we estimate that secured commercial bank indebtedness of approximately $2.1 billion could have been incurred under the most restrictive indenture covenant.

Results of Operations — Three Months Ended March 31, 2005 vs. March 31, 2004

General. For the Current Quarter, Chesapeake had net income of $125.0 million, or $0.36 per diluted common share, on total revenues of $783.5 million. This compares to net income of $112.6 million, or $0.38 per diluted common share, on total revenues of $563.1 million during the Prior Quarter. The Current Quarter net income includes, on a pre-tax basis, $114.1 million in net unrealized losses on oil and gas and interest rate derivatives and a $0.9 million loss on repurchase of debt. The Prior Quarter net income included, on a pre-tax basis, $22.7 million in net unrealized losses on oil and gas and interest rate derivatives and a $6.9 million loss on repurchases or exchanges of debt.

Oil and Gas Sales. During the Current Quarter, oil and gas sales were $538.9 million compared to $419.8 million in the Prior Quarter. In the Current Quarter, Chesapeake produced 104.6 bcfe at a weighted average price of $6.27 per mcfe, compared to 78.9 bcfe produced in the Prior Quarter at a weighted average price of $5.50 per mcfe (weighted average prices exclude the effect of unrealized gains or (losses) on derivatives of ($117.1) million and ($14.0) million in the Current Quarter and Prior Quarter, respectively). The increase in prices in the Current Quarter resulted in an increase in revenue of $80.8 million and increased production resulted in a $141.5 million increase, for a total increase in revenues of $222.3 million (excluding unrealized gains or losses on oil and gas derivatives). The increase in production from the Prior Quarter to the Current Quarter is due to the combination of production growth generated from drilling as well as acquisitions completed in 2004 and the Current Quarter.

The change in oil and gas prices has a significant impact on our oil and gas revenues and cash flows. Assuming the Current Quarter production levels, a change of $0.10 per mcf of gas sold would have resulted in an increase or decrease in revenues and cash flow of approximately $9.4 million and $8.9 million, respectively, and a change of $1.00 per barrel of oil sold would have resulted in an increase or decrease in revenues and cash flow of approximately $1.7 million and $1.6 million, respectively, without considering the effect of derivative activities.

For the Current Quarter, we realized an average price per barrel of oil of $41.74, compared to $27.10 in the Prior Quarter (weighted average prices for both quarters discussed exclude the effect of unrealized gains or losses on derivatives). Natural gas prices realized per mcf (excluding unrealized gains or losses on derivatives) were $6.20 and $5.62 in the Current Quarter and Prior Quarter, respectively. Realized gains or losses from our oil and gas derivatives resulted in a net increase in oil and gas revenues of $40.3 million or $0.39 per mcfe in the Current Quarter and a net increase of $25.7 million or $0.33 per mcfe in the Prior Quarter.

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


	For the Three Months Ended March 31,
	2005			2004
	Mmcfe	Percent		Mmcfe	Percent
Mid-Continent	72,812	70	%	62,699	79	%
South Texas and Texas Gulf Coast	11,937	11		8,234	10
Ark-La-Tex (including Barnett Shale)	11,423	11		1,992	3
Permian Basin	7,787	7		5,299	7
Other	648	1		664	1

Total Production	104,607	100	%	78,888	100	%

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

Oil and Gas Marketing Sales and Expenses. Chesapeake realized $244.5 million in oil and gas marketing sales to third parties in the Current Quarter, with corresponding oil and gas marketing expenses of $237.3 million, for a net margin of $7.2 million. Marketing activities are substantially for third parties that are owners in Chesapeake operated wells. This compares to sales of $143.3 million, expenses of $139.7 million and a net margin of $3.6 million in the Prior Quarter. In the Current Quarter, Chesapeake realized an increase in oil and gas marketing sales volumes and an increase in oil and gas prices.

Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $69.6 million in the Current Quarter compared to $44.8 million in the Prior Quarter. On a unit-of-production basis, production expenses were $0.66 per mcfe in the Current Quarter compared to $0.57 per mcfe in the Prior Quarter. The increase in the Current Quarter was primarily due to higher field service costs and ad valorem taxes on oil and gas properties. We expect that production expenses per mcfe during the remainder of 2005 will range from $0.68 to $0.72.

Production Taxes. Production taxes were $36.0 million and $14.9 million in the Current Quarter and the Prior Quarter, respectively. On a unit-of-production basis, production taxes were $0.34 per mcfe in the Current Quarter compared to $0.19 per mcfe in the Prior Quarter. The $21.1 million increase in production taxes in the Current Quarter is due primarily to 25.7 bcfe of increased production and the increase in sales price (excluding gains or losses on derivatives). Also included in the Prior Quarter was a credit of $6.8 million, or $0.09 per mcfe, related to certain Oklahoma severance tax abatements for the period July 2003 through December 2003. In April 2004, the Oklahoma Tax Commission concluded that a pre-determined oil and gas price cap for 2003 sales had not been exceeded (on a statewide basis) and notified the company that it was eligible to receive certain severance tax abatements for the period from July 1, 2003 through June 30, 2004. The company had previously estimated that the average oil and gas sales prices in Oklahoma (on a statewide basis) could exceed the price cap, and did not reflect the benefit from these potential severance tax abatements until the first quarter of 2004. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil and gas prices are higher. We expect production taxes per mcfe to range from $0.40 to $0.45 during the remainder of 2005 based on NYMEX prices of $45.00 per barrel of oil and natural gas wellhead prices ranging from $6.50 to $7.50 per mcf.

General and Administrative Expenses (excluding stock-based compensation). General and administrative expenses, which are net of internal payroll and non-payroll costs capitalized in our oil and gas properties, were $9.7 million, or $0.09 per mcfe, in the Current Quarter and $8.2 million, or $0.10 per mcfe, in the Prior Quarter. The

$1.5 million increase in the Current Quarter was the result of the company’s growth related to various acquisitions completed in the Current Quarter and in 2004 and the increase in drilling activity. This growth has resulted in a substantial increase in employees and related costs. We anticipate that general and administrative expenses for the remainder of 2005 will be between $0.10 and $0.12 per mcfe produced, which is approximately the same level as the Current Quarter.

Chesapeake follows the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $20.5 million and $10.9 million of internal costs in the Current Quarter and the Prior Quarter, respectively, directly related to our oil and gas exploration and development efforts.

Stock-Based Compensation. Stock-based compensation was $2.4 million in the Current Quarter and $1.9 million in the Prior Quarter. During the Current Quarter, 1.8 million shares of restricted stock were issued to employees. The cost of all outstanding restricted shares is amortized over a four-year period which resulted in the recognition of $4.0 million of stock-based compensation costs during the Current Quarter. Of this amount, $2.2 million was reflected as stock-based compensation expense (a sub-category of general and administrative expenses) in the condensed consolidated statements of operations, and the remaining $1.8 million was capitalized to oil and gas properties. We also recognized $0.1 million in stock-based compensation expense in the Current Quarter as a result of modifications made to previously issued stock options and an additional $0.1 million related to the issuance of common stock to a director. Stock-based compensation was $0.02 per mcfe for the Current Quarter and $0.02 per mcfe for the Prior Quarter. We anticipate that stock-based compensation expense for the remainder of 2005 will be between $0.03 and $0.05 per mcfe produced assuming no additional acquisitions are completed.

Oil and Gas Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of oil and gas properties was $181.0 million and $119.9 million during the Current Quarter and the Prior Quarter, respectively. The average DD&A rate per mcfe, which is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented, was $1.73 and $1.52 in the Current Quarter and in the Prior Quarter, respectively. The $0.21 increase in the average DD&A rate is primarily the result of higher drilling costs and higher costs associated with acquisitions, including the recognition of the tax effect of acquisition costs in excess of tax basis acquired in certain corporate acquisitions. We expect the DD&A rate for the remainder of 2005 to be between $1.75 and $1.85 per mcfe produced assuming no additional acquisitions are completed.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $10.1 million in the Current Quarter compared to $5.7 million in the Prior Quarter. The increase in the Current Quarter was primarily the result of higher depreciation costs resulting from the acquisition of various gathering facilities, construction of new buildings at our corporate headquarters and the purchase of additional information technology equipment and software in 2004 and the Current Quarter. Property and equipment costs are depreciated on a straight-line basis. Buildings are depreciated over 39 years, drilling rigs are depreciated over 15 years and all other property and equipment are depreciated over the estimated useful lives of the assets, which range from two to fifteen years. To the extent drilling rigs are used to drill our wells, the depreciation is capitalized in oil and gas properties as exploration or development costs. We expect depreciation and amortization of other assets to be between $0.09 and $0.11 per mcfe produced for the remainder of 2005.

Interest and Other Income. Interest and other income was $3.4 million in the Current Quarter compared to $1.3 million in the Prior Quarter. The Current Quarter income consisted of $2.7 million of interest income, $0.1 million related to earnings of equity investees and $0.6 million of miscellaneous income. The Prior Quarter income consisted of $0.4 million of interest income, $0.4 million related to earnings of equity investees and $0.5 million of miscellaneous income.

Interest Expense. Interest expense decreased from $46.5 million in the Prior Quarter to $43.1 million in the Current Quarter as follows:


	Three Months Ended March 31,
	2005			2004
Interest expense on senior notes and revolving bank credit facility facility	$	61.9		$	42.9
Capitalized interest		(16.0	)		(5.3	)
Amortization of loan discount		1.3			1.0
Unrealized (gain) loss on interest rate derivatives		(3.0	)		8.7
Realized gain on interest rate derivatives		(1.1	)		(0.8	)

Total interest expense	$	43.1		$	46.5

Average long-term borrowings	$	3,091		$	2,112

The $10.7 million increase in capitalized interest is the direct result of interest capitalized on our additional investments in unevaluated properties acquired since the Prior Quarter. Interest is capitalized on significant investments in unevaluated properties that are not being currently depreciated, depleted or amortized and on which exploration activities are in progress.

We use interest rate derivatives to mitigate our exposure to the volatility in interest rates. For interest rate derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value of interest rate derivatives are recorded on the consolidated balance sheets as assets (liabilities) and the debt’s carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Any resulting differences are recorded currently as ineffectiveness in the consolidated statements of operations as an adjustment to interest expense. Changes in the fair value of derivative instruments not qualifying as fair value hedges are recorded currently as adjustments to interest expense. A detailed explanation of our interest rate derivative activity appears below in Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Interest expense, excluding unrealized gains or losses on derivatives, was $0.44 per mcfe in the Current Quarter compared to $0.48 per mcfe in the Prior Quarter. We expect interest expense for the remainder of 2005 to be between $0.43 and $0.47 per mcfe produced (before considering the effect of interest rate derivatives).

Loss on Repurchases or Exchanges of Chesapeake Debt. We have repurchased or exchanged Chesapeake debt and incurred losses in connection with these transactions. The following table shows the losses related to these transactions ($ in millions):


	Notes Retired		Loss on Repurchases/Exchanges
	Notes Retired		Premium		Other^(a)		Total
For the Quarter Ended March 31, 2005:
8.375% Senior Notes due 2008	$	11.0	$	0.8	$	0.1	$	0.9

For the Quarter Ended March 31, 2004:
8.5% Senior Notes due 2012	$	4.3	$	0.2	$	0.7	$	0.9
8.125% Senior Notes due 2011		482.8		—		6.0		6.0

	$	487.1	$	0.2	$	6.7	$	6.9

(a)	Includes write-offs of discounts, deferred charges and interest rate derivatives associated with notes retired and transaction costs.

Income Tax Expense. Chesapeake recorded income tax expense of $71.9 million in the Current Quarter, compared to income tax expense of $63.3 million in the Prior Quarter. Our effective income tax rate increased to 36.5% in the Current Quarter compared to 36% in the Prior Quarter. The increase in the Current Quarter reflected the impact state income taxes and permanent differences had on our overall effective rate. All 2004 income tax expense was deferred, and we expect most, if not all, of our 2005 income tax expense to be deferred.

Critical Accounting Policies

Recently Issued Accounting Standards

In September 2004, the Emerging Issues Task Force issued EITF No. 04-8, The Effect of Contingently Convertible Instruments on Diluted Earnings per Share. EITF No. 04-8 provides new guidance on when the dilutive effect of contingently convertible securities with a market price trigger should be included in diluted EPS. The guidance in EITF No. 04-8 is effective for all periods ending after December 15, 2004 and Chesapeake has complied by retrospectively restating previous reported EPS. The effect of this pronouncement on diluted EPS is more fully described in Note 4 of the notes to our condensed consolidated financial statements included in Part 1.

In March 2005, the FASB issued FASB Interpretation No. (FIN) 47, Accounting for Conditional Asset Retirement Obligations. FIN 47 specifies the accounting treatment for conditional asset retirement obligations under the provisions of Statement of Financial Accounting Standards No. 143. FIN 47 is effective no later than the end of the fiscal year ending after December 15, 2005. We plan to adopt this statement effective December 31, 2005. Implementation of FIN47 is not expected to have a material effect on our financial statements.

Forward-Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include statements regarding oil and gas reserve estimates, planned capital expenditures, the drilling of oil and gas wells and future acquisitions, expected oil and gas production, cash flow and anticipated liquidity, business strategy and other plans and objectives for future operations, expected future expenses and utilization of net operating loss carryforwards. Statements concerning the fair values of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility.

Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in Item 1 of our annual report on Form 10-K for the year ended December 31, 2004 and include:

•

the volatility of oil and gas prices,

•

our level of indebtedness,

•

the strength and financial resources of our competitors,

•

the availability of capital on an economic basis to fund reserve replacement costs,

•

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

•

our ability to replace reserves and sustain production,

•

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

•

unsuccessful exploration and development drilling,

•

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

•

lower prices realized on oil and gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities, and

•

drilling and operating risks.

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

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Oil and Gas Hedging Activities

•

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.

With respect to counter-swaps that are designed to lock-in the value of cap-swaps, the counter-swap is effective in locking-in the value of the cap-swap until the floating price reaches the cap (or floor) stipulated in the cap-swap agreement. The value of the counter-swap will increase (or decrease), but in the opposite direction, as the value of the cap-swap decreases (or increases) until the floating price reaches the pre-determined cap (or floor) stipulated in the cap-swap agreement. However, because of the written put option embedded in the cap-swap, the changes in value of the cap-swap are not completely effective in offsetting changes in value of the corresponding counter-swap. Changes in the value of cap-swaps and the counter-swaps are recorded as adjustments to oil and gas sales.

Gains or losses from derivative transactions are reflected as adjustments to oil and gas sales on the condensed consolidated statements of operations. Realized gains or losses from our oil and gas derivatives resulted in a net increase in oil and gas revenues of $40.3 million, or $0.39 per mcfe, in the Current Quarter and a net increase of $25.7 million, or $0.33 per mcfe, in the Prior Quarter. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e. temporary fluctuations in value) are reported currently in the consolidated statements of operations as unrealized gains (losses) within oil and gas sales. Unrealized gains (losses) included in oil and gas sales in the Current Quarter and the Prior Quarter were ($117.1) million and ($14.0) million, respectively.

As of March 31, 2005, we had the following open oil and gas derivative instruments designed to hedge a portion of our oil and gas production for periods after March 2005:


	Volume		Weighted- Average Fixed Price to be Received (Paid)			Weighted- Average Put Fixed Price		Weighted- Average Call Fixed Price		Weighted- Average Differential			SFAS 133 Hedge	Premiums Received		Fair Value at March 31, 2005 ($ in thousands)
Natural Gas (mmbtu):
Swaps:
2005	94,835,000		$	6.52		$	—	$	—	$	—		Yes	$	—	$	(121,364	)
2006	43,785,000			7.00			—		—		—		Yes		—		(30,408	)

Basis Protection Swaps:
2005	142,690,000			—			—		—		(0.27	)	No		—		29,966
2006	130,140,000			—			—		—		(0.32	)	No		—		20,377
2007	126,495,000			—			—		—		(0.28	)	No		—		23,827
2008	118,610,000			—			—		—		(0.27	)	No		—		23,206
2009	86,600,000			—			—		—		(0.29	)	No		—		14,709

Cap-Swaps:
2005	63,415,000			6.26			4.66		—		—		No		—		(103,642	)
2006	42,950,000			6.90			5.12		—		—		No		—		(42,710	)

Counter Swaps:
2006	(7,300,000	)		(5.59	)		—		—		—		No		—		15,323

Call Options:
2005	5,500,000			—			—		5.77		—		No		2,448		(11,586	)

Collars:
2005	3,300,000			—			3.10		4.44		—		Yes		—		(9,544	)

Locked Swaps:
2005	24,750,000			—			—		—		—		No		—		(32,036	)
2006	25,550,000			—			—		—		—		No		—		(22,601	)
2007	25,550,000			—			—		—		—		No		—		(11,626	)

Total Natural Gas															2,448		(258,109	)

Oil (bbls):
Swaps:
2005	596,500			51.04			—		—		—		Yes		—		(3,414	)
2006	333,500			52.81			—		—		—		Yes		—		(766	)
Cap-Swaps:
2005	1,462,000			43.20			32.98		—		—		No		—		(20,112	)
2006	501,500			57.58			40.54		—		—		No		—		(968	)

Total Oil															—		(25,260	)

Total Natural Gas and Oil														$	2,448	$	(283,369	)

We have established the fair value of all derivative instruments using estimates of fair value reported by our counterparties and subsequently evaluated internally using established index prices and other sources. The actual contribution to our future results of operations will be based on the market prices at the time of settlement and may be more or less than the fair value estimates used at March 31, 2005.

Based upon the market prices at March 31, 2005, we expect to transfer approximately $109.8 million (net of income taxes) of the loss included in the balance in accumulated other comprehensive income to earnings during the next 12 months when the transactions actually occur. All transactions hedged as of March 31, 2005 are expected to mature by December 31, 2007, with the exception of our basis protection swaps which extend through 2009.

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


	2005
	($ in thousands)
Fair value of contracts outstanding, as of January 1	$	38,350
Change in fair value of contracts during the period		(281,371	)
Contracts realized or otherwise settled during the period		(40,348	)

Fair value of contracts outstanding, as of March 31	$	(283,369	)

The change in the fair value of our derivative instruments since January 1, 2005 resulted from the settlement of derivatives for a realized gain as well as an increase in oil and natural gas prices. Derivative instruments reflected as current in the condensed consolidated balance sheet represent the estimated fair value of derivative instrument settlements scheduled to occur over the subsequent twelve-month period based on market prices for oil and gas as of the condensed consolidated balance sheet date. The derivative settlement amounts are not due and payable until the month in which the related underlying hedged transaction occurs.

Interest Rate Risk

The table below presents principal cash flows and related weighted average interest rates by expected maturity dates. As of March 31, 2005, the fair value of the fixed-rate long-term debt has been estimated based on quoted market prices.


	Years of Maturity
	2005		2006		2007		2008			2009		Thereafter			Total			Fair Value
	($ in millions)
Liabilities:
Long-term debt—fixed-rate ^(a)	$	—	$	—	$	—	$	8.0		$	—	$	3,080.1		$	3,088.1		$	3,203.1
Average interest rate		—		—		—		8.4	%		—		7.3	%		7.3	%		7.3	%
Long-term debt—variable-rate	$	—	$	—	$	—	$	—		$	—	$	724.0		$	724.0		$	724.0
Average interest rate		—		—		—		—			—		4.2	%		4.2	%		4.2	%

(a)	This amount does not include the discount included in long-term debt of ($83.6) million and the discount for interest rate swaps of ($9.8) million.

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

Interest Rate Derivatives

As of March 31, 2005, the following interest rate swaps (which qualify as fair value hedges) used to convert a portion of our long-term fixed-rate debt to floating-rate debt were outstanding:


Term	Notional Amount		Fixed Rate		Floating Rate	Fair Value Gain (Loss)
						($ in thousands)
September 2004 – August 2012	$	75,000,000	9.000	%	6-month LIBOR plus 452 basis points	$	(2,113	)
February 2005 – June 2014	$	100,000,000	7.500	%	6-month LIBOR plus 287 basis points	$	(3,613	)
February 2005 – January 2015	$	150,000,000	7.750	%	6-month LIBOR plus 291 basis points	$	(4,718	)
March 2005 – August 2014	$	75,000,000	7.000	%	6-month LIBOR plus 205.5 basis points	$	(1,162	)
March 2005 – June 2015	$	100,000,000	6.375	%	6-month LIBOR in arrears plus 124 basis points	$	(1,652	)
March 2005 – June 2015	$	75,000,000	6.375	%	6-month LIBOR in arrears plus 114 basis points	$	(859	)
March 2005 – January 2016	$	75,000,000	6.875	%	6-month LIBOR in arrears plus 127 basis points	$	412

ITEM 4. Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed by Chesapeake in reports filed or submitted by it under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. At the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of Chesapeake management, including Chesapeake’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Chesapeake’s disclosure controls and procedures pursuant to Securities Exchange Act Rule 13a-15(b). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.

No changes in Chesapeake’s internal control over financial reporting occurred during the Current Quarter that have materially affected, or are reasonably likely to materially affect, Chesapeake’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Chesapeake is currently involved in various disputes incidental to its business operations. Management is of the opinion that the final resolution of currently pending or threatened litigation is not likely to have a material adverse effect on our consolidated financial position or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table presents information about repurchases of our common stock during the three months ended March 31, 2005:


Period	Total Number of Shares Purchased^(a)	Average Price Paid Per Share^(a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs(b)
January 1, 2005 through January 31, 2005	211,946	$	16.718	—	—
February 1, 2005 through February 28, 2005	89,732	$	19.086	—	—
March 1, 2005 through March 31, 2005	49,691	$	21.663	—	—

Total	351,369	$	18.022	—	—

(a)

Includes 172,236 shares purchased in the open market for the matching contributions we make to our 401(k) plans, the deemed surrender to the company of 80,439 shares of common stock to pay the exercise price in connection with the exercise of employee stock options and the surrender to the company of 98,694 shares of common stock to pay withholding taxes in connection with the vesting of employee restricted stock.

(b)

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

Item 3. Defaults Upon Senior Securities

Not applicable.

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

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits

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


Exhibit Number		Description
3.1.1		Restated Certificate of Incorporation, as amended.

3.1.2		Certificate of Designation of Series A Junior Participating Preferred Stock, as amended.

3.1.3		Certificate of Designation of 6% Cumulative Convertible Preferred Stock, as amended.

3.1.4		Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2003).

3.1.5		Certificate of Designation of 4.125% Cumulative Convertible Preferred Stock.

3.1.6		Certificate of Designation of 5% Cumulative Convertible Preferred stock (Series 2005).

4.12		Indenture dated as of April 19, 2005 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee, with respect to the 6.625% Senior Notes due 2016.

4.13		Registration Rights Agreement dated as of April 19, 2005 among Chesapeake Energy Corporation, as issuer, and Lehman Brothers Inc., Banc of America Securities LLC, Credit Suisse First Boston LLC, Deutsche Bank Securities Inc., UBS Securities LLC, Bear, Stearns & Co. Inc., BNP Paribas Securities Corp., Citigroup Global Markets Inc., Morgan Stanley & Co. Incorporated, ABN Amro Incorporated, BOSC, Inc., Calyon Securities (USA) Inc., Comerica Securities, Inc., Fortis Securities LLC, Harris Nesbitt Corp., Piper Jaffray & Co., RBC Capital Markets Corporation, Greenwich Capital Markets Inc., SunTrust Capital Markets, Inc., TD Securities (USA) LLC, Wachovia Capital Markets, LLC and Wells Fargo Securities, LLC (collectively, the “Initial Purchasers”), with respect to the 6.625% Senior Notes due 2016.

4.14		Registration Rights Agreement dated as of April 19, 2005 among Chesapeake Energy Corporation, as issuer, and Credit Suisse First Boston LLC, Banc of America Securities LLC, Bear, Stearns & Co. Inc., Lehman Brothers Inc., Morgan Stanley & Co. Incorporated, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Raymond James & Associates, Inc., RBC Capital Markets Corporation, UBS Securities LLC, Howard Weil Incorporated, Johnson Rice & Company L.L.C., Pritchard Capital Partners LLC, Simmons & Company International and Sterne Agee & Leach, Inc. (collectively, the “Initial Purchasers”), with respect to the 5.0% Cumulative Convertible Preferred Stock (Series 2005).

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

21		Subsidiaries of Chesapeake.

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

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

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

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

SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


CHESAPEAKE ENERGY CORPORATION
(Registrant)

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

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

Date: May 10, 2005

INDEX TO EXHIBITS


Exhibit Number		Description
3.1.1		Restated Certificate of Incorporation, as amended.

3.1.2		Certificate of Designation of Series A Preferred Stock, as amended.

3.1.3		Certificate of Designation of 6% Cumulative Convertible Preferred Stock, as amended.

3.1.4		Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2003).

3.1.5		Certificate of Designation of 4.125% Cumulative Convertible Preferred Stock.

3.1.6		Certificate of Designation of 5% Cumulative Convertible Preferred stock (Series 2005).

4.12		Indenture dated as of April 19, 2005 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York Trust Company, N.A., as Trustee, with respect to the 6.625% Senior Notes due 2016.

4.13		Registration Rights Agreement dated as of April 19, 2005 among Chesapeake Energy Corporation, as issuer, and Lehman Brothers Inc., Banc of America Securities LLC, Credit Suisse First Boston LLC, Deutsche Bank Securities Inc., UBS Securities LLC, Bear, Stearns & Co. Inc., BNP Paribas Securities Corp., Citigroup Global Markets Inc., Morgan Stanley & Co. Incorporated, ABN Amro Incorporated, BOSC, Inc., Calyon Securities (USA) Inc., Comerica Securities, Inc., Fortis Securities LLC, Harris Nesbitt Corp., Piper Jaffray & Co., RBC Capital Markets Corporation, Greenwich Capital Markets Inc., SunTrust Capital Markets, Inc., TD Securities (USA) LLC, Wachovia Capital Markets, LLC and Wells Fargo Securities, LLC (collectively, the “Initial Purchasers”), with respect to the 6.625% Senior Notes due 2016.

4.14		Registration Rights Agreement dated as of April 19, 2005 among Chesapeake Energy Corporation, as issuer, and Credit Suisse First Boston LLC, Banc of America Securities LLC, Bear, Stearns & Co. Inc., Lehman Brothers Inc., Morgan Stanley & Co. Incorporated, Citigroup Global Markets Inc., Deutsche Bank Securities Inc., Raymond James & Associates, Inc., RBC Capital Markets Corporation, UBS Securities LLC, Howard Weil Incorporated, Johnson Rice & Company L.L.C., Pritchard Capital Partners LLC, Simmons & Company International and Sterne Agee & Leach, Inc. (collectively, the “Initial Purchasers”), with respect to the 5.0% Cumulative Convertible Preferred Stock (Series 2005).

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

21		Subsidiaries of Chesapeake.

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

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

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

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

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