Edgar Filing: CHESAPEAKE ENERGY CORP

FORM 10-Q

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 June 30, 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 August 4, 2005, there were 323,113,841 shares of our $0.01 par value common stock outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

INDEX TO FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2005


		Page
PART I. Financial Information

Item 1.	Condensed Consolidated Financial Statements (Unaudited):

	Condensed Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004	3

	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2005 and 2004	4

	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2005 and 2004	5

	Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 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	18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32

Item 4.	Controls and Procedures	36

PART II. Other Information

Item 1.	Legal Proceedings	37

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37

Item 3.	Defaults Upon Senior Securities	37

Item 4.	Submission of Matters to a Vote of Security Holders	37

Item 5.	Other Information	38

Item 6.	Exhibits	38

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30, 2005			December 31, 2004
	($ in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	6,896
Accounts receivable:
Oil and gas sales		356,508			347,081
Joint interest, net of allowances of $4,765,000 and $4,648,000, respectively		73,704			68,220
Related parties		13,186			8,286
Other		29,237			35,781
Deferred income tax asset		51,184			18,068
Short-term derivative instruments		6,012			51,061
Inventory and other		42,175			32,147

Total Current Assets		572,006			567,540

PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties		11,736,088			9,451,413
Unevaluated properties		1,109,097			761,785
Less: accumulated depreciation, depletion and amortization of oil and gas properties		(3,445,403	)		(3,057,742	)

Total oil and gas properties, at cost based on full-cost accounting		9,399,782			7,155,456
Other property and equipment		428,523			324,495
Drilling rigs		78,629			49,375
Less: accumulated depreciation and amortization of other property and equipment		(103,577	)		(84,942	)

Total Property and Equipment		9,803,357			7,444,384

OTHER ASSETS:
Investment in Pioneer Drilling		117,531			65,950
Other investments		46,096			26,793
Long-term derivative instruments		39,934			44,169
Other assets		78,962			95,673

Total Other Assets		282,523			232,585

TOTAL ASSETS	$	10,657,886		$	8,244,509

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	534,723		$	367,176
Accrued interest		60,268			66,514
Short-term derivative instruments		131,997			91,414
Other accrued liabilities		214,949			222,029
Revenues and royalties due others		223,907			216,820

Total Current Liabilities		1,165,844			963,953

LONG-TERM LIABILITIES:
Long-term debt, net		4,125,929			3,075,109
Deferred income tax liability		1,361,259			933,873
Asset retirement obligation		82,938			73,718
Long-term derivative instruments		32,776			1,296
Revenues and royalties due others		19,233			17,007
Other liabilities		18,261			16,670

Total Long-Term Liabilities		5,640,396			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, 101,375 and 103,110 shares issued and outstanding as of June 30, 2005 and December 31, 2004, respectively, entitled in liquidation to $5,068,750 and $5,155,500		5,069			5,156
5.00% cumulative convertible preferred stock (series 2003), 1,725,000 shares issued and outstanding as of June 30, 2005 and December 31, 2004, entitled in liquidation to $172,500,000		172,500			172,500
4.125% cumulative convertible preferred stock, 268,250 and 313,250 shares issued and outstanding as of June 30, 2005 and December 31, 2004, respectively, entitled in liquidation to $268,250,000 and $313,250,000		268,250			313,250
5.00% cumulative convertible preferred stock (series 2005), 4,600,000 and 0 shares issued and outstanding as of June 30, 2005 and December 31, 2004, respectively, entitled in liquidation to $460,000,000		460,000			—
Common Stock, $.01 par value, 500,000,000 shares authorized, 323,872,133 and 316,940,784 shares issued at June 30, 2005 and December 31, 2004, respectively		3,239			3,169
Paid-in capital		2,521,395			2,440,105
Retained earnings		537,016			262,987
Accumulated other comprehensive income (loss), net of tax of $20,556,000 and ($11,489,000), respectively		(35,762	)		20,425
Unearned compensation		(53,970	)		(32,618	)
Less: treasury stock, at cost; 5,329,341 and 5,072,121 common shares as of June 30, 2005 and December 31, 2004, respectively		(26,091	)		(22,091	)

Total Stockholders’ Equity		3,851,646			3,162,883

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	10,657,886		$	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 June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	($ in thousands, except per share data)
REVENUES:
Oil and gas sales	$	772,401		$	399,665		$	1,311,343		$	819,458
Oil and gas marketing sales		275,617			174,627			520,125			317,963

Total Revenues		1,048,018			574,292			1,831,468			1,137,421

OPERATING COSTS:
Production expenses		72,333			49,595			141,895			94,398
Production taxes		47,253			22,751			83,211			37,687
General and administrative expenses:
General and administrative (excluding stock-based compensation)		9,282			7,420			18,932			15,586
Stock-based compensation		2,506			672			4,923			2,541
Oil and gas marketing expenses		270,003			171,115			507,279			310,779
Oil and gas depreciation, depletion and amortization		209,371			136,743			390,339			256,651
Depreciation and amortization of other assets		11,807			6,716			21,889			12,455

Total Operating Costs		622,555			395,012			1,168,468			730,097

INCOME FROM OPERATIONS		425,463			179,280			663,000			407,324

OTHER INCOME (EXPENSE):
Interest and other income		2,005			1,335			5,362			2,678
Interest expense		(53,902	)		(28,806	)		(97,030	)		(75,351	)
Loss on repurchases or exchanges of Chesapeake debt		(68,400	)		—			(69,300	)		(6,925	)

Total Other Income (Expense)		(120,297	)		(27,471	)		(160,968	)		(79,598	)

INCOME BEFORE INCOME TAX		305,166			151,809			502,032			327,726
INCOME TAX EXPENSE:
Current		—			—			—			—
Deferred		111,387			54,654			183,243			117,981

Total Income Tax Expense		111,387			54,654			183,243			117,981

NET INCOME		193,779			97,155			318,789			209,745
PREFERRED STOCK DIVIDENDS		(9,859	)		(11,344	)		(15,322	)		(19,512	)
LOSS ON CONVERSION/EXCHANGE OF PREFERRED STOCK		(4,743	)		—			(4,743	)		—

NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$	179,177		$	85,811		$	298,724		$	190,233

EARNINGS PER COMMON SHARE:
Basic	$	0.58		$	0.36		$	0.96		$	0.80
Assuming dilution	$	0.52		$	0.30		$	0.88		$	0.67

CASH DIVIDEND DECLARED PER COMMON SHARE	$	0.050		$	0.045		$	0.095		$	0.080

WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in thousands):
Basic		311,181			241,147			310,523			239,016
Assuming dilution		364,063			322,194			356,478			310,937

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)


	Six Months Ended June 30,
	2005			2004
	($ in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$	318,789		$	209,745
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization		408,084			266,715
Unrealized losses on derivatives		29,896			33,829
Deferred income taxes		183,243			117,729
Amortization of loan costs		4,144			2,390
Amortization of bond discount		2,765			2,098
Stock-based compensation		4,923			2,541
Income from equity investments		(2,169	)		(1,017	)
Loss on repurchases or exchanges of Chesapeake debt		69,300			6,925
Other		(229	)		772

Cash provided by operating activities before changes in assets and liabilities		1,018,746			641,727
Change in assets and liabilities		61,561			28,830

Cash provided by operating activities		1,080,307			670,557

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil and gas companies, proved properties and unproved properties, net of cash acquired		(1,352,458	)		(1,002,341	)
Exploration and development of oil and gas properties		(1,037,459	)		(535,059	)
Additions to buildings and other fixed assets		(98,389	)		(44,985	)
Additions to drilling rig equipment		(29,255	)		(7,683	)
Additions to investments		(22,422	)		(10,000	)
Divestitures of oil and gas properties		114			271
Other		(9	)		347

Cash used in investing activities		(2,539,878	)		(1,599,450	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings		2,419,000			767,000
Payments on long-term borrowings		(2,023,000	)		(611,000	)
Proceeds from issuance of preferred stock, net of offering costs		447,167			304,936
Proceeds from issuance of common stock, net of offering costs		—			298,028
Proceeds from issuance of senior notes, net of offering costs		1,180,766			288,557
Purchases or exchanges of Chesapeake senior notes, including redemption premiums		(608,074	)		(57,271	)
Common stock dividends		(27,901	)		(16,014	)
Preferred stock dividends		(10,928	)		(18,891	)
Financing costs of credit facility		(4,645	)		(8,291	)
Purchases of treasury shares		(4,000	)		—
Net increase in outstanding payments in excess of cash balance		75,164			11,125
Cash received from exercise of stock options and warrants		11,600			6,588
Other financing costs		(2,474	)		(218	)

Cash provided by financing activities		1,452,675			964,549

Net increase (decrease) in cash and cash equivalents		(6,896	)		35,656
Cash and cash equivalents, beginning of period		6,896			40,581

Cash and cash equivalents, end of period	$	—		$	76,237

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 June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	($ in thousands)
Net income	$	193,779		$	97,155		$	318,789		$	209,745
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments, net of income taxes of $18,778,000, ($25,758,000), ($44,563,000) and ($62,562,000)		32,668			(45,792	)		(77,527	)		(111,222	)
Reclassification of (gain) loss on settled contracts, net of income taxes of $10,964,000, $18,249,000, ($1,017,000) and $11,669,000		19,074			32,443			(1,769	)		20,744
Ineffective portion of derivatives qualifying for cash flow hedge accounting, net of income taxes of ($422,000), $2,891,000, ($215,000) and $5,483,000		(734	)		5,140			(374	)		9,747
Unrealized gain on marketable securities, net of income taxes of $4,183,000, $0, $13,498,000 and $0		7,278			—			23,483			—

Comprehensive income	$	252,065		$	88,946		$	262,602		$	129,014

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 and six months ended June 30, 2005 are not necessarily indicative of the results to be expected for the full year. This Form 10-Q relates to the three and six months ended June 30, 2005 (the “Current Quarter” and “Current Period”, respectively) and the three and six months ended June 30, 2004 (the “Prior Quarter” and “Prior Period”, respectively).

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 $0.3 million, $0.2 million, $0.4 million and $0.2 million in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively.

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 periods presented: interest rates (zero-coupon U.S. government issues with a remaining life equal to the expected term of the options) ranging from 3.81% to 4.18%, dividend yields ranging from 0.82% to 1.22%, and volatility factors for the expected market price of our common stock ranging from 0.30 to 0.33. We used a weighted-average expected life of the options of five years for each of the periods presented.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	($ in thousands, except per share amounts)
Net Income:
As reported	$	193,779		$	97,155		$	318,789		$	209,745
Stock-based compensation expense included in net income, net of tax		1,591			430			3,126			1,626
Pro forma compensation expense, net of tax		(4,071	)		(3,256	)		(7,958	)		(7,495	)

Pro forma	$	191,299		$	94,329		$	313,957		$	203,876

Basic earnings per common share
As reported	$	0.58		$	0.36		$	0.96		$	0.80

Pro forma	$	0.57		$	0.34		$	0.95		$	0.77

Diluted earnings per common share
As reported	$	0.52		$	0.30		$	0.88		$	0.67

Pro forma	$	0.51		$	0.29		$	0.87		$	0.66

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 June 30, 2005, we do not believe the new accounting requirement will have a significant impact on future results of operations.

Restricted Stock. Chesapeake began issuing shares of restricted common stock to employees in January 2004. 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 (a sub-category of general and administrative costs).

Critical Accounting Policies

We consider accounting policies related to 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.

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 June 30, 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.

•

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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

•

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 June 30, 2005, the fair value of our basis protection swaps was $128.1 million. As of June 30, 2005, our basis protection swaps cover approximately 44% of our anticipated remaining gas production in 2005, 28% in 2006, 25% in 2007, 22% in 2008 and 16% in 2009.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 were $84.1 million, ($20.2) million, ($33.1) million and ($34.2) million, in the Current Quarter, Prior Quarter, Current Period and Prior Period, 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 $1.2 million, ($8.0) million, $0.6 million and ($15.2) million in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively.

The estimated fair values of our oil and gas derivative instruments as of June 30, 2005 and December 31, 2004 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.


	June 30, 2005			December 31, 2004
	($ in thousands)
Derivative assets (liabilities):
Fixed-price gas swaps	$	(77,690	)	$	57,073
Fixed-price gas locked swaps		(55,914	)		(77,299	)
Fixed-price gas cap-swaps		(97,487	)		(48,761	)
Fixed-price gas counter-swaps		17,537			4,654
Gas basis protection swaps		128,120			122,287
Gas call options^(a)		(5,940	)		(5,793	)
Fixed-price gas collars		(5,262	)		(5,573	)
Fixed-price oil swaps		(11,408	)		—
Fixed-price oil cap-swaps		(10,133	)		(8,238	)

Estimated fair value	$	(118,177	)	$	38,350

(a)	After adjusting for the remaining $1.6 million and $3.2 million premium paid to Chesapeake by the counterparty, the cumulative unrealized loss related to these call options as of June 30, 2005 and December 31, 2004 was $4.3 million and $2.6 million, respectively.

Based upon the market prices at June 30, 2005, we expect to transfer approximately $51.5 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 June 30, 2005 are expected to mature by December 31, 2007, with the exception of our basis protection swaps which extend through 2009.

We have two secured hedging facilities, each of which permits us to enter into cash-settled natural gas and oil commodity transactions, valued by the counterparty, for up to $500 million. The scheduled maturity date for these facilities is May 2010. Outstanding transactions under each facility are collateralized by certain of our oil and gas properties that do not secure any of our other obligations. One of the hedging facilities is subject to an annual fee of 0.30% of the maximum total capacity, and each of them has 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 June 30, 2005, the fair market value of the natural gas and oil hedging transactions was a liability of $42.8 million under one of the facilities and an asset of $45.9 million under the other facility. The hedging facilities contain the standard representations and default provisions that are typical of such agreements. The agreements also contain 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.

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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

As of June 30, 2005, the following interest rate swap was used to convert a portion of our long-term fixed-rate debt to floating-rate debt was 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	$	(714	)

Subsequent to June 30, 2005, we entered into the following interest rate swaps (which qualify as fair value hedges) to convert a portion of our long-term fixed-rate debt to floating-rate debt:


Term	Notional Amount		Fixed Rate		Floating Rate
July 2005 – January 2015	$	150,000,000	7.750	%	6 month LIBOR plus 289 basis points
July 2005 – June 2014	$	150,000,000	7.500	%	6 month LIBOR plus 282 basis points
August 2005 – August 2014	$	200,000,000	7.000	%	6 month LIBOR plus 205.5 basis points

In the Current Quarter and Current Period, we closed various interest rate swaps for gains totaling $4.3 million and $5.1 million, respectively. 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.

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.

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 or premiums related to interest rate derivatives, at June 30, 2005 and December 31, 2004 was $3,664.1 million and $3,014.1 million, respectively, compared to approximate fair values of $3,865.7 million and $3,281.1 million, respectively. The carrying amounts for our convertible preferred stock as of June 30, 2005 and December 31, 2004 were $905.8 million and $490.9 million, respectively, compared to approximate fair values of $994.8 million and $533.7 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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

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 July 1, 2005. The term of each agreement is automatically extended for one additional year on each January 31 unless the company 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 three times his base salary, the prior year’s bonus compensation and the value of benefits provided during the prior year, 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 salary and bonuses paid during the prior year.

Environmental Risk

Due to the nature of the oil and gas business, Chesapeake and its subsidiaries are exposed to possible environmental risks. Chesapeake has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. Chesapeake conducts periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a 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 June 30, 2005.

Other Commitments

Chesapeake’s wholly owned subsidiary, Nomac Drilling Company, has contracted to acquire 18 rigs to be constructed during 2005 and 2006. The total cost of the rigs will be approximately $150 million.

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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

•

For the Current Quarter, the Prior Quarter, Current Period and Prior Period, outstanding options to purchase 0.2 million, 0.1 million, 0.1 million and 0.2 million shares of common stock at a weighted-average exercise price of $26.53, $26.73, $27.88 and $19.93, 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.

•

For each of the Prior Quarter and the Prior Period, outstanding warrants to purchase 0.3 million shares of common stock at a weighted-average exercise price of $15.72 were antidilutive because the exercise prices of the warrants were greater than the average market price of the common stock during the period.

•

For the Current Quarter and Current Period, diluted shares do not include the common stock equivalent of 4.125% preferred stock outstanding prior to conversion (convertible into 2,613,403 and 2,657,704 shares, respectively) as the effect was antidilutive, and the preferred stock dividend adjustment to net income does not include $5.1 million and $5.5 million, respectively, of dividends and loss on conversion related to these preferred shares.

Reconciliations for the three months ended June 30, 2005 and 2004 and the six months ended June 30, 2005 and 2004 are as follows:


	Income (Numerator)		Shares (Denominator)	Per Share Amount
	($ in thousands, except per share data)
For the Three Months Ended June 30, 2005:
Basic EPS:
Income available to common shareholders	$	179,177	311,181	$	0.58

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		—	16,110
Common shares assumed issued for 5.00% convertible preferred stock (series 2003)		—	10,516
Common shares assumed issued for 6.00% convertible preferred stock		—	493
Common shares assumed issued for 5.00% convertible preferred stock (series 2005)		—	14,168
Common stock equivalent of 6.00% preferred stock outstanding prior to conversion		—	5
Preferred stock dividends		9,550	—
Employee stock options		—	10,408
Restricted stock		—	1,175
Warrants assumed in Gothic acquisition		—	7

Diluted EPS Income available to common shareholders and assumed conversions	$	188,727	364,063	$	0.52

For the Three Months Ended June 30, 2004:
Basic EPS:
Income available to common shareholders	$	85,811	241,147	$	0.36

Effect of Dilutive Securities
Assumed conversion as of the beginning of the period pf preferred shares outstanding during the period:
Common shares assumed issued for 4.125% convertible preferred stock		—	18,711
Common shares assumed issued for 5.00% convertible preferred stock (series 2003)		—	10,516
Common shares assumed issued for 6.00% convertible preferred stock		—	22,358
Common shares assumed issued for 6.75% convertible preferred stock		—	19,466
Preferred stock options		11,344	—
Employee stock options		—	9,838
Restricted stock		—	149
Warrants assumed in Gothic acquisition		—	9

Diluted EPS Income available to common shareholders and assumed conversions	$	97,155	322,194	$	0.30

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	Income (Numerator)		Shares (Denominator)	Per Share Amount
	($ in thousands, except per share data)
For the Six Months Ended June 30, 2005:
Basic EPS:
Income available to common shareholders	$	298,724	310,523	$	0.96

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		—	16,110
Common shares assumed issued for 5.00% convertible preferred stock (series 2003)		—	10,516
Common shares assumed issued for 6.00% convertible preferred stock		—	493
Common shares assumed issued for 5.00% convertible preferred stock (series 2005)		—	7,123
Common stock equivalent of 6.00% preferred stock outstanding prior to conversion		—	7
Preferred stock dividends		14,549	—
Employee stock options		—	10,539
Restricted stock		—	1,151
Warrants assumed in Gothic acquisition		—	16

Diluted EPS Income available to common shareholders and assumed conversions	$	313,273	356,478	$	0.88

For the Six Months Ended June 30, 2004:
Basic EPS:
Income available to common shareholders	$	190,233	239,016	$	0.80

Effect of Dilutive Securities
Assumed conversion as of the beginning of the period pf preferred shares outstanding during the period:
Common shares assumed issued for 4.125% convertible preferred stock		—	9,537
Common shares assumed issued for 5.00% convertible preferred stock (series 2003)		—	10,516
Common shares assumed issued for 6.00% convertible preferred stock		—	22,358
Common shares assumed issued for 6.75% convertible preferred stock		—	19,466
Preferred stock options		19,512	—
Employee stock options		—	9,858
Restricted stock		—	180
Warrants assumed in Gothic acquisition		—	6

Diluted EPS Income available to common shareholders and assumed conversions	$	209,745	310,937	$	0.67

5. Senior Notes and Revolving Bank Credit Facility

Our long-term debt consisted of the following as of June 30, 2005 and December 31, 2004:


	June 30, 2005			December 31, 2004
	($ in thousands)
8.375% Senior Notes due 2008	$	7,990		$	18,990
8.125% Senior Notes due 2011		7,583			245,407
9.0% Senior Notes due 2012		1,140			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
6.625% Senior Notes due 2016		600,000			—
6.875% Senior Notes due 2016		670,437			670,437
6.25% Senior Notes due 2018		600,000			—
Revolving bank credit facility		455,000			59,000
Discount on senior notes		(87,272	)		(84,924	)
Premium for interest rate derivatives^(a)		6,820			1,968

Total senior notes and long-term debt	$	4,125,929		$	3,075,109

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

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

During the periods covered by this report, we repurchased or exchanged Chesapeake debt through various private and public transactions. The following table sets forth the losses we incurred in connection with these transactions ($ in millions):


	Notes Retired		Loss on Repurchases/Exchanges
	Notes Retired		Premium		Other^(a)		Total
For the Three Months Ended June 30, 2005:
8.125% Senior Notes due 2011	$	237.8	$	16.8	$	4.3	$	21.1
9.0% Senior Notes due 2012		298.9		41.3		6.0		47.3

	$	536.7	$	58.1	$	10.3	$	68.4

For the Six Months Ended June 30, 2005:
8.375% Senior Notes due 2008	$	11.0	$	0.8	$	0.1	$	0.9
8.125% Senior Notes due 2011		237.8		16.8		4.3		21.1
9.0% Senior Notes due 2012		298.9		41.3		6.0		47.3

	$	547.7	$	58.9	$	10.4	$	69.3

For the Six Months Ended June 30, 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.

There were no repurchases or exchanges of Chesapeake debt in the Prior Quarter.

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 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.

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 wholly owned subsidiaries.

We have a $1.25 billion syndicated revolving bank credit facility which matures in January 2010. As of June 30, 2005, we had $455.0 million of outstanding borrowings under our facility and utilized $53.1 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 June 30, 2005, our fixed charge coverage ratio was 5.79 to 1 and our indebtedness to EBITDA ratio was 2.25 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 ($50 million in the case of our 6.625% Senior Notes due 2016 and 6.25% Senior Notes due 2018), would constitute an event of default under our senior note indentures which could in turn result in the acceleration of a significant portion 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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Our subsidiary, Chesapeake Exploration Limited Partnership, is the borrower under our revolving bank credit facility. The facility is guaranteed by Chesapeake and all of our other wholly owned subsidiaries.

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 $463.9 million and $310.3 million for the Current Quarter and the Prior Quarter, respectively, and $869.1 million and $582.4 million for the Current Period and the Prior Period, respectively.

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


	Exploration and Production		Marketing		Consolidated
For the Three Months Ended June 30, 2005:
Revenues	$	772,401	$	275,617	$	1,048,018
Income (loss) before income taxes		301,188		3,978		305,166
For the Three Months Ended June 30, 2004:
Revenues	$	399,665	$	174,627	$	574,292
Income before income taxes		151,466		343		151,809
For the Six Months Ended June 30, 2005:
Revenues	$	1,311,343	$	520,125	$	1,831,468
Income before income taxes		492,375		9,657		502,032
For the Six Months Ended June 30, 2004:
Revenues	$	819,458	$	317,963	$	1,137,421
Income before income taxes		326,413		1,313		327,726
As of June 30, 2005:
Total assets	$	10,281,484	$	376,402	$	10,657,886
As of December 31, 2004:
Total assets	$	7,926,263	$	318,246	$	8,244,509

7. Acquisitions

The following table describes significant acquisitions that we completed in the Current Period ($ in millions):


Quarter	Acquisition	Location	Amount
First	BRG Petroleum Corporation	Mid-Continent and Ark-La-Tex	$	325	^(a)
	Laredo Energy II, L.L.C.	South Texas		228
	Other	Various		89	^(b)
Second	Houston-based oil and gas company	Texas Gulf Coast/South Texas		202
	Pecos Production Company	Permian		198
	Laredo II Partners	Texas Gulf Coast/South Texas		139
	Dallas-based oil and gas company	Ark-La-Tex		85
	Midland-based oil and gas company	Permian		38
	Other	Various		65

			$	1,369

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

(b)	During the Current Period, we paid the remaining $57 million of the purchase price related to an acquisition transaction with Hallwood Energy Corporation in the fourth quarter 2004.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

During the Current Period, we have recorded approximately $252 million of deferred tax liability to reflect the tax effect of the cost paid in excess of the tax basis acquired on certain 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 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

On July 6, 2005, we completed cash tender offers for our 8.125% Senior Notes due 2011 and 9.0% Senior Notes due 2012. Subsequent to June 30, 2005, approximately $0.3 million was used to purchase $0.1 million of 8.125% Senior Notes due 2011 and $0.2 million of 9.0% Senior Notes due 2012. Subsequent to the expiration of these tender offers, we notified the trustee of our intention to redeem the remaining 8.125% and 9.0% Senior Notes on August 17, 2005 based on the make-whole redemption provisions in the indentures.

In July 2005, we exchanged 2,225,111 shares of our common stock for 34,452 shares of our 4.125% cumulative convertible preferred stock.

On July 18, 2005, we purchased $249.5 million of Barnett Shale natural gas assets from Hallwood Energy III L.P. We used our revolving bank credit facility to fund this acquisition.

Subsequent to June 30, 2005, we obtained a 49% interest in Mountain Drilling Company, a newly formed venture with a New York-based investment banking firm in which Chesapeake and its partner have each invested $25 million to secure four specialty rigs for drilling in urban areas or in areas of special environmental sensitivity.

Subsequent to June 30, 2005, we have agreed to acquire $160 million of natural gas assets in the East Texas and Permian Basin regions in three transactions with three private companies.

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 and six months ended June 30, 2005 (the “Current Quarter” and the “Current Period”) and the three and six months ended June 30, 2004 (the “Prior Quarter” and the “Prior Period”):


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Net Production:
Oil (mbbl)		2,012			1,673			3,758			3,138
Gas (mmcf)		101,128			76,510			195,259			146,608
Gas equivalent (mmcfe)		113,200			86,548			217,807			165,436

Oil and Gas Sales ($ in thousands):
Oil sales	$	96,798		$	59,930		$	176,742		$	107,961
Oil derivatives – realized gains (losses)		(10,650	)		(12,878	)		(17,717	)		(21,208	)
Oil derivatives – unrealized gains (losses)		10,900			(1,470	)		(1,942	)		(7,489	)

Total oil sales		97,048			45,582			157,083			79,264

Gas sales		635,901			415,216			1,171,678			775,317
Gas derivatives – realized gains (losses)		(33,702	)		(42,453	)		13,713			(8,462	)
Gas derivatives – unrealized gains (losses)		73,154			(18,680	)		(31,131	)		(26,661	)

Total gas sales		675,353			354,083			1,154,260			740,194

Total oil and gas sales	$	772,401		$	399,665		$	1,311,343		$	819,458

Average Sales Price (excluding all gains (losses) on derivatives):
Oil ($ per bbl)	$	48.11		$	35.82		$	47.03		$	34.40
Gas ($ per mcf)	$	6.29		$	5.43		$	6.00		$	5.29
Gas equivalent ($ per mcfe)	$	6.47		$	5.49		$	6.19		$	5.34

Average Sales Price (excluding unrealized gains (losses) on derivatives):
Oil ($ per bbl)	$	42.82		$	28.12		$	42.32		$	27.65
Gas ($ per mcf)	$	5.95		$	4.87		$	6.07		$	5.23
Gas equivalent ($ per mcfe)	$	6.08		$	4.85		$	6.17		$	5.16

Expenses ($ per mcfe):
Production expenses	$	0.64		$	0.57		$	0.65		$	0.57
Production taxes^(a)	$	0.42		$	0.26		$	0.38		$	0.23
General and administrative expenses:
General and administrative expenses (excluding stock-based compensation)	$	0.08		$	0.09		$	0.09		$	0.09
Stock-based compensation	$	0.02		$	0.01		$	0.02		$	0.02
Oil and gas depreciation, depletion and amortization	$	1.85		$	1.58		$	1.79		$	1.55
Depreciation and amortization of other assets	$	0.10		$	0.08		$	0.10		$	0.08
Interest expense^(b)	$	0.48		$	0.44		$	0.46		$	0.46

Interest Expense ($ in thousands):
Interest expense	$	54,710		$	37,513		$	102,003		$	76,077
Interest rate derivatives – realized (gains) losses		(675	)		353			(1,796	)		(405	)
Interest rate derivatives – unrealized (gains) losses		(133	)		(9,060	)		(3,177	)		(321	)

Total interest expense	$	53,902		$	28,806		$	97,030		$	75,351

Net Wells Drilled		196			131			365			240
Net Producing Wells as of the End of the Period		9,054			7,348			9,054			7,348

(a)	The Prior Period includes a pre-tax benefit of $6.8 million, or $0.04 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 third largest independent producer of natural gas in the U.S. and owns interests in approximately 21,500 producing oil and gas wells. Our primary operating area is the Mid-Continent region of the United States, which includes Oklahoma, Arkansas, 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, the Barnett Shale area of north-central Texas and the Ark-La-Tex areas of 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 among the largest onshore U.S. inventory of leasehold and 3-D seismic data (approximately 4.1 million and 10.8 million net acres, respectively) with a nine year drilling backlog of approximately 14,000 locations.

Oil and natural gas production for the Current Quarter was 113.2 bcfe, an increase of 26.7 bcfe, or 31%, over the 86.5 bcfe produced in the Prior Quarter. We have increased our production for 16 consecutive quarters. During these 16 quarters, Chesapeake’s U.S. production has increased 214%, for an average compound quarterly growth rate of 7.4% and an average compound annual growth rate of 33.1%.

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 $6.08 per mcfe in the Current Quarter compared to $4.85 per mcfe in the Prior Quarter. The increase in prices resulted in an increase in revenue of $139.2 million, and increased production resulted in an increase in revenue of $129.3 million, for a total increase in revenue of $268.5 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 for our production.

Chesapeake began 2005 with estimated proved reserves of 4,902 bcfe and ended the Current Quarter with 5,850 bcfe, an increase of 948 bcfe, or 19%. During the 2005 first half, we replaced 218 bcfe of production with an estimated 1,166 bcfe of new proved reserves, for a reserve replacement rate of 535%. Reserve replacement through the drillbit was 583 bcfe, or 268% of production (including 43 bcfe from positive performance revisions and 25 bcfe from oil and natural gas price increases), or 50% of the total increase. Reserve replacement through acquisitions was 583 bcfe, or 267% of production, or 50% of the total increase.

During the Current Quarter, Chesapeake drilled 224 (162 net) operated wells and participated in another 296 (34 net) wells operated by other companies. The company’s drilling success rate was 97% for operated wells and 98% for non-operated wells. During the quarter, Chesapeake invested $400 million in operated wells (using an average of 73 operated rigs), $77 million in non-operated wells (using an average of approximately 65 non-operated rigs) and $52 million in acquiring new 3-D seismic data and new leasehold (excluding leasehold acquired through acquisitions). Our acquisition expenditures totaled $778 million during the Current Quarter (including amounts paid for unproved leasehold and excluding $132 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 14 rigs dedicated to drilling Chesapeake-operated wells and we have an additional 18 rigs on order for delivery over the next year. In addition, we have entered into drilling contracts for the use of 20 rigs currently being built or refurbished by private drilling companies, to be available to us in 2005 and 2006. We also have invested approximately $43 million in the common stock of publicly held Pioneer Drilling Company over the past two years, and now hold approximately 17% of its outstanding common stock. At June 30, 2005, our Pioneer shares had a market value of $117.5 million. We also have invested $15 million in the common stock of DHS Drilling Company, a Casper, Wyoming-based drilling company which has four rigs operating in the Rocky Mountains and which will expand to ten rigs over the next several months. At June 30, 2005, our ownership percentage was approximately 45%. Subsequent to June 30, 2005, we obtained a 49% interest in Mountain Drilling Company, a newly formed venture with a New York-based investment banking firm in which Chesapeake and its partner have each invested $25 million to secure four specialty rigs for drilling in urban areas or in areas of special environmental sensitivity.

As of June 30, 2005, the company’s debt as a percentage of total capitalization (total capitalization is the sum of debt and stockholders’ equity) was 52%, compared to 49% as of December 31, 2004. During the Current Period, we received net proceeds of $1,627.9 million through issuances of $460 million of preferred equity (series 2005

5.0% convertible preferred stock), $600 million principal amount of 6.625% Senior Notes due 2016 and $600 million principal amount of 6.25% Senior Notes due 2018. We exchanged 45,000 shares of our outstanding 4.125% preferred stock for 2,911,250 shares of common stock, and holders of our 6.0% preferred stock converted 1,735 shares into 8,432 shares of common stock. Additionally, we purchased and retired $11.0 million principal amount of 8.375% Senior Notes due 2008, $237.8 million principal amount of 8.125% Senior Notes due 2011 and $298.9 million principal amount of 9.0% Senior Notes due 2012 which resulted in an aggregate loss on repurchases or exchanges of Chesapeake debt of $69.3 million for the Current Period. As a result of our debt transactions during the Current Period, we have extended the average maturity of our long-term debt to over ten years and have lowered our average interest rate to approximately 6.9%.

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 $1.9 billion and $2.1 billion. 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). However, 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 $1,018.7 million in the Current Period compared to $641.7 million in the Prior Period. The $377.0 million increase 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 the remainder of 2005 would significantly affect the amount of cash flow that would be generated from operations, we have 47% of our expected oil production for the remainder of 2005 hedged at an average NYMEX price of $52.22 per barrel of oil and 59% of our expected natural gas production for the remainder of 2005 hedged at an average NYMEX price of $6.65 per mcf. This level of hedging provides greater certainty of the cash flow we will receive for a substantial portion of our remaining 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 June 30, 2005 and August 4, 2005, we had issued $50 million and $51 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 four of our counterparties. All of our existing commodity hedges that are not under our secured hedge facilities (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 $180 million.

A significant source of liquidity is our $1.25 billion syndicated revolving bank credit facility which matures in January 2010. At August 4, 2005, there was $264.9 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 $2,419 million and repaid $2,023 million in the Current Period, and we borrowed $767.0 million and repaid $611.0 million in the Prior Period under our bank credit facility. We incurred $4.6 million and $8.3 million of financing costs related to our revolving credit facility in the Current Period and the Prior Period, respectively, as a result of amendments 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 facilities do not contain material adverse change 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, the bank facility and the secured hedge facilities do not contain 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 Current Period and the Prior Period ($ in millions):


	For the Six Months Ended June 30,
	2005				2004
	Total Proceeds		Net Proceeds		Total Proceeds		Net Proceeds
Convertible preferred stock	$	460.0	$	447.2	$	313.3	$	304.9
Common stock		—		—		310.7		298.0
Unsecured senior notes guaranteed by subsidiaries		1,200.0		1,180.7		300.0		288.6

Total	$	1,660.0	$	1,627.9	$	924.0	$	891.5

We have an effective $600 million universal shelf registration statement on file with the Securities and Exchange Commission. 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 $27.9 million and $16.0 million in the Current Period and the Prior Period, respectively. The Board of Directors voted on June 10, 2005 to increase the annual dividend per common share by 11%, from $0.18 to $0.20. The first dividend at this higher rate was paid on July 15, 2005 to common shareholders of record on July 1, 2005. We paid dividends on our preferred stock of $10.9 million and $18.9 million in the Current Period and the Prior Period, respectively. We received $11.6 million and $6.6 million from the exercise of employee and director stock options and warrants in the Current Period and the Prior Period, respectively.

Outstanding payments from certain disbursement accounts in excess of funded cash balances where no legal right of set-off exists increased by $75.2 million and $11.1 million in the Current Period and the Prior Period, 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 Six Months Ended June 30, 2005:
8.375% Senior Notes due 2008	$	11.0	$	0.8	$	—	$	—	$	11.8
8.125% Senior Notes due 2011		237.8		16.8		0.7		—		255.3
9.0% Senior Notes due 2012		298.9		41.3		0.8		—		341.0

	$	547.7	$	58.9	$	1.5	$	—	$	608.1


	Senior Notes Activity
	Retired		Premium		Other^(a)		Issued^(b)			Cash Paid
For the Six Months Ended June 30, 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 $2,539.9 million during the Current Period, compared to $1,599.5 million during the Prior Period. The following table shows our capital expenditures during these periods ($ in millions):


	Six Months Ended June 30,
	2005			2004
Acquisitions of oil and gas companies, proved and unproved properties, net of cash acquired	$	1,352.4		$	1,002.3
Exploration and development of oil and gas properties		1,037.5			535.1
Additions to buildings and other fixed assets		98.4			45.0
Additions to drilling rig equipment		29.3			7.7
Additions to investments		22.4			10.0
Divestitures of oil and gas properties		(0.1	)		(0.3	)
Other		—			(0.3	)

Total	$	2,539.9		$	1,599.5

Our accounts receivable are primarily from purchasers of oil and natural gas ($356.5 million at June 30, 2005) and exploration and production companies which own interests in properties we operate ($73.7 million at June 30, 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 Period ($ in millions):


Quarter	Acquisition	Location	Amount
First	BRG Petroleum Corporation	Mid-Continent and Ark-La-Tex	$	325	^(a)
	Laredo Energy II, L.L.C.	South Texas		228
	Other	Various		89	^(b)
Second	Houston-based oil and gas company	Texas Gulf Coast/South Texas		202
	Pecos Production Company	Permian		198
	Laredo II Partners	Texas Gulf Coast/South Texas		139
	Dallas-based oil and gas company	Ark-La-Tex		85
	Midland-based oil and gas company	Permian		38
	Other	Various		65

			$	1,369

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

(b)	During the Current Period, we paid the remaining $57 million of the purchase price related to an acquisition transaction with Hallwood Energy Corporation in the fourth quarter 2004.

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 ten years with an average interest rate of approximately 6.9%. 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.

We completed the following significant financing transactions in the Current Period:

First Quarter 2005

•

Amended our revolving bank credit facility to increase the committed borrowing base to $1.25 billion and extended 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 a premium of $0.8 million).

Second Quarter 2005

•

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 first quarter.

•

Completed a private placement of $600 million of 6.25% Senior Notes due 2018. Net proceeds of approximately $596.4 million were used to fund our purchases in June 2005 of $237.8 million of our 8.125% Senior Notes due 2011 for $255.3 million (including a premium of $16.8 million and transaction costs of $0.7 million) and $298.9 million of our 9.0% Senior Notes due 2012 for $341.0 million (including a premium of $41.3 million and transaction costs of $0.8 million) pursuant to tender offers for the 8.125% and 9.0% Senior Notes. We acquired a total of $237.9 million principal amount of 8.125% Senior Notes due 2011 and $299.1 million, principal amount of 9.00% senior notes due 2012, representing 96.9% and 99.7%, respectively, of the amounts outstanding, in the tender offers, which expired on July 6, 2005. Subsequent to the expiration of these tender offers, we notified the trustee of our intention to redeem the remaining 8.125% and 9.0% Senior Notes on August 17, 2005 based on the make-whole redemption provisions in the indentures.

•

Completed a private exchange of 45,000 shares of our outstanding 4.125% preferred stock for 2,911,250 shares of common stock. No cash was received or paid in connection with this transaction.

Contractual Obligations

We currently have a $1.25 billion syndicated 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 June 30, 2005, we had $455.0 million of outstanding borrowings under this facility and had utilized $53.1 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 June 30, 2005, our fixed charge coverage ratio was 5.79 to 1 and our indebtedness to EBITDA ratio was 2.25 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 ($50 million in the case of our 6.625% Senior Notes due 2016 and 6.25% Senior Notes due 2018), would constitute an event of default under our senior note indentures which could in turn result in the acceleration of a significant portion 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.

As of June 30, 2005, we owned 14 rigs dedicated to drilling wells operated by Chesapeake and have contracted to acquire 18 additional rigs to be constructed in 2005 and 2006. We expect to spend approximately $150 million to complete the rigs under construction.

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 June 30, 2005, we were required to post $50 million of collateral in the form of letters of credit with respect to such derivative transactions. These collateral requirements were $51 million as of August 4, 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 four of our counterparties which limit the amount of collateral that we would be required to post with them to no more than $180 million in the aggregate.

We have two secured hedging facilities, each of which permits us to enter into cash-settled natural gas and oil commodity transactions, valued by the counterparty, for up to $500 million. The scheduled maturity date for these facilities is May 2010. Outstanding transactions under each facility are collateralized by certain of our oil and gas properties that do not secure any of our other obligations. One of the hedging facilities is subject to an annual fee of 0.30% of the maximum total capacity and each of them has 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 June 30, 2005, the fair market value of the natural gas and oil hedging transactions was a liability of $42.8 million under one of the facilities and an asset of $45.9 million under the other facility. The hedging facilities contain the standard representations and default provisions that are typical of such agreements. The agreements also contain 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.

Our subsidiary, Chesapeake Exploration Limited Partnership, is the borrower under our revolving bank credit facility and is the named party to our hedging facilities. The facilities are guaranteed by Chesapeake and all its other subsidiaries. Our revolving bank credit facility and secured hedge facilities do not contain material adverse change 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, the bank facility and the secured hedge facilities do not contain 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 June 30, 2005, our senior notes represented approximately $3.7 billion of our long-term debt and consisted of the following ($ in thousands):


8.375% Senior Notes due 2008	$	7,990
8.125% Senior Notes due 2011		7,583
9.0% Senior Notes due 2012		1,140
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
6.625% Senior Notes due 2016		600,000
6.875% Senior Notes due 2016		670,437
6.25% Senior Notes due 2018		600,000
Discount on senior notes		(87,272	)
Premium for interest rate derivatives		6,820

	$	3,670,929

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 June 30, 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 June 30, 2005 vs. June 30, 2004

General. For the Current Quarter, Chesapeake had net income of $193.8 million, or $0.52 per diluted common share, on total revenues of $1,048.0 million. This compares to net income of $97.2 million, or $0.30 per diluted common share, on total revenues of $574.3 million during the Prior Quarter. The Current Quarter net income includes, on a pre-tax basis, $84.2 million in net unrealized gains on oil and gas and interest rate derivatives and a $68.4 million loss on repurchases or exchanges of debt. The Prior Quarter net income included, on a pre-tax basis, $11.1 million in net unrealized losses on oil and gas and interest rate derivatives.

Oil and Gas Sales. During the Current Quarter, oil and gas sales were $772.4 million compared to $399.7 million in the Prior Quarter. In the Current Quarter, Chesapeake produced 113.2 bcfe at a weighted average price of $6.08 per mcfe, compared to 86.5 bcfe produced in the Prior Quarter at a weighted average price of $4.85 per mcfe (weighted average prices exclude the effect of unrealized gains or (losses) on derivatives of $84.1 million and ($20.2) million in the Current Quarter and Prior Quarter, respectively). In the Current Quarter, the increase in prices resulted in an increase in revenue of $139.2 million and increased production resulted in a $129.3 million increase, for a total increase in revenues of $268.5 million (excluding unrealized gains or losses on oil and gas derivatives). The increase in production from the Prior Quarter to the Current Quarter is due to the combination of production growth generated from drilling as well as acquisitions completed in 2004 and 2005.

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 $10.1 million and $9.4 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 $2.0 million and $1.9 million, respectively, without considering the effect of derivative activities.

For the Current Quarter, we realized an average price per barrel of oil of $42.82, compared to $28.12 in the Prior Quarter (weighted average prices for both quarters discussed exclude the effect of unrealized gains or losses on derivatives). Natural gas prices realized per mcf (excluding unrealized gains or losses on derivatives) were $5.95 and $4.87 in the Current Quarter and Prior Quarter, respectively. Realized gains or losses from our oil and gas derivatives resulted in a net decrease in oil and gas revenues of $44.4 million, or $0.39 per mcfe, in the Current Quarter and a net decrease of $55.3 million, or $0.64 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 June 30,
	2005			2004
	Mmcfe	Percent		Mmcfe	Percent
Mid-Continent	74,569	66	%	64,064	74	%
South Texas and Texas Gulf Coast	16,142	14		10,494	12
Ark-La-Tex (including Barnett Shale)	12,491	11		3,307	4
Permian Basin	9,325	8		8,042	9
Other	673	1		641	1

Total Production	113,200	100	%	86,548	100	%

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

Oil and Gas Marketing Sales and Expenses. Chesapeake realized $275.6 million in oil and gas marketing sales to third parties in the Current Quarter, with corresponding oil and gas marketing expenses of $270.0 million, for a net margin of $5.6 million. Marketing activities are substantially for third parties that are owners in Chesapeake-operated wells. This compares to sales of $174.6 million, expenses of $171.1 million and a net margin of $3.5 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 $72.3 million in the Current Quarter compared to $49.6 million in the Prior Quarter. On a unit-of-production basis, production expenses were $0.64 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 for the remainder of 2005 will range from $0.68 to $0.72 per mcfe produced.

Production Taxes. Production taxes were $47.3 million and $22.8 million in the Current Quarter and the Prior Quarter, respectively. On a unit-of-production basis, production taxes were $0.42 per mcfe in the Current Quarter compared to $0.26 per mcfe in the Prior Quarter. The $24.5 million increase in production taxes in the Current Quarter is due primarily to approximately 26.7 bcfe of increased production and the increase in sales prices (excluding gains or losses on derivatives). In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil and gas prices are higher. We expect production taxes for the remainder of 2005 to range from $0.43 to $0.48 per mcfe based on NYMEX prices of $50 per barrel of oil and natural gas wellhead prices ranging from $5.75 to $8.00 per mcf.

General and Administrative Expenses (excluding stock-based compensation). General and administrative expenses, which are net of internal payroll and non-payroll general and administrative costs capitalized in our oil and gas properties, were $9.3 million, or $0.08 per mcfe, in the Current Quarter and $7.4 million, or $0.09 per mcfe, in the Prior Quarter. The $1.9 million increase in the Current Quarter was the result of the company’s growth related to various acquisitions completed in the Current Period 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 $23.5 million and $12.4 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 $2.5 million in the Current Quarter and $0.7 million in the Prior Quarter. During the Current Quarter, a nominal number of 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 $4.1 million 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 $1.9 million was capitalized to oil and gas properties. We also recognized $0.3 million in stock-based compensation expense in the Current Quarter as a result of modifications made to previously issued stock options. Stock-based compensation was $0.02 per mcfe for the Current Quarter and $0.01 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.

Oil and Gas Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of oil and gas properties was $209.4 million and $136.7 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 $1.85 and $1.58 in the Current Quarter and in the Prior Quarter, respectively. The $0.27 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 $1.85 and $1.95 per mcfe produced.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $11.8 million in the Current Quarter compared to $6.7 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 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 for the remainder of 2005 to be between $0.09 and $0.11 per mcfe produced.

Interest and Other Income. Interest and other income was $2.0 million in the Current Quarter compared to $1.3 million in the Prior Quarter. The Current Quarter income consisted of $0.4 million of interest income, $1.1 million related to earnings of equity investees and $0.5 million of miscellaneous income. The Prior Quarter income consisted of $0.5 million of interest income, $0.6 million related to earnings of equity investees and $0.2 million of miscellaneous income.

Interest Expense. Interest expense increased from $28.8 million in the Prior Quarter to $53.9 million in the Current Quarter as follows:


	Three Months Ended June 30,
	2005			2004
	($ in millions)
Interest expense on senior notes and revolving bank credit facility	$	71.2		$	43.8
Capitalized interest		(17.9	)		(7.4	)
Amortization of loan discount		1.4			1.1
Unrealized (gain) loss on interest rate derivatives		(0.1	)		(9.1	)
Realized (gain) loss on interest rate derivatives		(0.7	)		0.4

Total interest expense	$	53.9		$	28.8

Average long-term borrowings	$	3,554		$	2,240

The $27.4 million increase in interest expense on senior notes ($21.7 million increase) and revolving bank credit facility ($5.7 million increase) is due to a higher average balance of senior notes outstanding, $3.6 billion in the Current Quarter compared to $2.2 billion in the Prior Quarter, partially offset by a decrease in the average interest rate, 7.2% in the Current Quarter compared to 7.7% in the Prior Quarter. The increase in the credit facility interest expense is the result of higher borrowings and an increase in interest rates.

The $10.5 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.

Interest expense, excluding unrealized gains or losses on derivatives, was $0.48 per mcfe in the Current Quarter compared to $0.44 per mcfe in the Prior Quarter. We expect interest expense (before considering the effect of interest rate derivatives) for the remainder of 2005 to be between $0.45 and $0.49 per mcfe produced.

Loss on Repurchases or Exchanges of Chesapeake Debt. We repurchased or exchanged Chesapeake debt in the Current Quarter 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 Three Months Ended June 30, 2005:
8.125% Senior Notes due 2011	$	237.8	$	16.8	$	4.3	$	21.1
9.0% Senior Notes due 2012		298.9		41.3		6.0		47.3

	$	536.7	$	58.1	$	10.3	$	68.4

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

There were no losses on repurchases or exchanges of Chesapeake debt in the Prior Quarter.

Income Tax Expense. Chesapeake recorded income tax expense of $111.4 million in the Current Quarter, compared to income tax expense of $54.7 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.

Results of Operations — Six Months Ended June 30, 2005 vs. June 30, 2004

General. For the Current Period, Chesapeake had net income of $318.8 million, or $0.88 per diluted common share, on total revenues of $1,831.5 million. This compares to net income of $209.7 million, or $0.67 per diluted common share, on total revenues of $1,137.4 million during the Prior Period. The Current Period net income includes, on a pre-tax basis, $29.9 million in net unrealized losses on oil and gas and interest rate derivatives and a $69.3 million loss on repurchases or exchanges of debt. The Prior Period net income included, on a pre-tax basis, $33.8 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 Period, oil and gas sales were $1,311.3 million compared to $819.5 million in the Prior Period. In the Current Period, Chesapeake produced 217.8 bcfe at a weighted average price of $6.17 per mcfe, compared to 165.4 bcfe produced in the Prior Period at a weighted average price of $5.16 per mcfe (weighted average prices exclude the effect of unrealized gains or (losses) on derivatives of ($33.1) million and ($34.2) million in the Current Period and Prior Period, respectively). In the Current Period, the increase in prices resulted in an increase in revenue of $220.0 million and increased production resulted in a $270.8 million increase, for a total increase in revenues of $490.8 million (excluding unrealized gains or losses on oil and gas derivatives). The increase in production from the Prior Period to the Current Period is due to the combination of production growth generated from drilling as well as acquisitions completed in 2004 and 2005.

The change in oil and gas prices has a significant impact on our oil and gas revenues and cash flows. Assuming the Current Period 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 $19.5 million and $18.3 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 $3.8 million and $3.5 million, respectively, without considering the effect of derivative activities.

For the Current Period, we realized an average price per barrel of oil of $42.32, compared to $27.65 in the Prior Period (weighted average prices for both periods 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 $6.07 and $5.23 in the Current Period and Prior Period, respectively. Realized gains or losses from our oil and gas derivatives resulted in a net decrease in oil and gas revenues of $4.0 million, or $0.02 per mcfe, in the Current Period and a net decrease of $29.7 million, or $0.18 per mcfe, in the Prior Period.

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


	For the Six Months Ended June 30,
	2005			2004
	Mmcfe	Percent		Mmcfe	Percent
Mid-Continent	147,381	67	%	126,640	77	%
South Texas and Texas Gulf Coast	28,078	13		18,728	11
Ark-La-Tex (including Barnett Shale)	23,914	11		5,299	3
Permian Basin	17,112	8		13,463	8
Other	1,322	1		1,306	1

Total Production	217,807	100	%	165,436	100	%

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

Oil and Gas Marketing Sales and Expenses. Chesapeake realized $520.1 million in oil and gas marketing sales to third parties in the Current Period, with corresponding oil and gas marketing expenses of $507.3 million, for a net margin of $12.8 million. Marketing activities are substantially for third parties that are owners in Chesapeake- operated wells. This compares to sales of $318.0 million, expenses of $310.8 million and a net margin of $7.2 million in the Prior Period. In the Current Period, 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 $141.9 million in the Current Period compared to $94.4 million in the Prior Period. On a unit-of-production basis, production expenses were $0.65 per mcfe in the Current Period compared to $0.57 per mcfe in the Prior Period. The increase in the Current Period was primarily due to higher field service costs and ad valorem taxes on oil and gas properties. We expect that production expenses for the remainder of 2005 will range from $0.68 to $0.72 per mcfe.

Production Taxes. Production taxes were $83.2 million and $37.7 million in the Current Period and the Prior Period, respectively. On a unit-of-production basis, production taxes were $0.38 per mcfe in the Current Period compared to $0.23 per mcfe in the Prior Period. The $45.5 million increase in production taxes in the Current Period is due primarily to approximately 52.4 bcfe of increased production and the increase in sales price (excluding gains or losses on derivatives). Also included in the Prior Period was a credit of $6.8 million, or $0.04 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 for the remainder of 2005 will range from $0.43 to $0.48 per mcfe based on NYMEX prices of $50 per barrel of oil and natural gas wellhead prices ranging from $5.75 to $8.00 per mcf.

General and Administrative Expenses (excluding stock-based compensation). General and administrative expenses, which are net of internal payroll and non-payroll general and administrative costs capitalized in our oil and gas properties, were $18.9 million, or $0.09 per mcfe, in the Current Period and $15.6 million, or $0.09 per mcfe, in the Prior Period. The $3.3 million increase in the Current Period was the result of the company’s growth related to various acquisitions completed in the Current Period 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 Period.

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 $45.8 million and $23.3 million of internal costs in the Current Period and the Prior Period, respectively, directly related to our oil and gas exploration and development efforts.

Stock-Based Compensation. Stock-based compensation was $4.9 million in the Current Period and $2.5 million in the Prior Period. During the Current Period, 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 $8.1 million during the Current Period. Of this amount, $4.4 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 $3.7 million was capitalized to oil and gas properties. We also recognized $0.4 million in stock-based compensation expense in the Current Period 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 Period and $0.02 per mcfe for the Prior Period. We anticipate that stock-based compensation expense for the remainder of 2005 will be between $0.03 and $0.05 per mcfe produced.

Oil and Gas Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of oil and gas properties was $390.3 million and $256.7 million during the Current Period and the Prior Period, 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 $1.79 and $1.55 in the Current Period and in the Prior Period, respectively. The $0.24 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 $1.85 and $1.95 per mcfe produced.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $21.9 million in the Current Period compared to $12.5 million in the Prior Period. The increase in the Current Period 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 in 2004 and the Current Period. 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 for the remainder of 2005 to be between $0.09 and $0.11 per mcfe produced.

Interest and Other Income. Interest and other income was $5.4 million in the Current Period compared to $2.7 million in the Prior Period. The Current Period income consisted of $3.1 million of interest income, $1.2 million related to earnings of equity investees and $1.1 million of miscellaneous income. The Prior Period income consisted of $0.9 million of interest income, $1.1 million related to earnings of equity investees and $0.7 million of miscellaneous income.

Interest Expense. Interest expense increased from $75.4 million in the Prior Period to $97.0 million in the Current Period as follows:


	Six Months Ended June 30,
	2005			2004
	($ in millions)
Interest expense on senior notes and revolving bank credit facility	$	133.1		$	86.7
Capitalized interest		(33.9	)		(12.7	)
Amortization of loan discount		2.8			2.1
Unrealized gain on interest rate derivatives		(3.2	)		(0.3	)
Realized gain on interest rate derivatives		(1.8	)		(0.4	)

Total interest expense	$	97.0		$	75.4

Average long-term borrowings	$	3,356		$	2,188

The $46.4 million increase in interest expense on senior notes ($37.1 million increase) and revolving bank credit facility ($9.3 million increase) is due to a higher average balance of senior notes outstanding, $3.4 billion in the Current Period compared to $2.2 billion in the Prior Period, partially offset by a decrease in the average interest rate, 7.2% in the Current Period compared to 7.8% in the Prior Period. The increase in the credit facility interest expense is the result of higher borrowings and an increase in interest rates.

The $21.2 million increase in capitalized interest is the direct result of interest capitalized on our additional investments in unevaluated properties acquired since the Prior Period. 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.

Interest expense, excluding unrealized gains or losses on derivatives, was $0.46 per mcfe in the Current Period and Prior Period. We expect interest expense (before considering the effect of interest rate derivatives) for the remainder of 2005 to be between $0.45 and $0.49 per mcfe produced.

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 Six Months Ended June 30, 2005:
8.375% Senior Notes due 2008	$	11.0	$	0.8	$	0.1	$	0.9
8.125% Senior Notes due 2011		237.8		16.8		4.3		21.1
9.0% Senior Notes due 2012		298.9		41.3		6.0		47.3

	$	547.7	$	58.9	$	10.4	$	69.3

For the Six Months Ended June 30, 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 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 $183.2 million in the Current Period, compared to income tax expense of $118.0 million in the Prior Period. Our effective income tax rate increased to 36.5% in the Current Period compared to 36% in the Prior Period. The increase in the Current Period 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 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. This statement is effective as of the beginning of the annual reporting period that begins after June 15, 2005.

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 June 30, 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.

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. Implementation of FIN 47 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 and expected future expenses. 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 filings with the Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect our business.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Oil and Gas Hedging Activities

•

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.

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 June 30, 2005, the fair value of our basis protection swaps was $128.1 million. As of June 30, 2005, our basis protection swaps cover approximately 44% of our anticipated gas production remaining in 2005, 28% in 2006, 25% in 2007, 22% in 2008 and 16% in 2009.

Gains or losses from derivative transactions are reflected as adjustments to oil and gas sales on the condensed consolidated statements of operations. Realized gains (losses) included in oil and gas sales were ($44.4) million, ($55.3) million, ($4.0) million and ($29.7) million in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. 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 were $84.1 million, ($20.2) million, ($33.1) million and ($34.2) million, in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively.

As of June 30, 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 June 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 June 30, 2005 ($ in thousands)
Natural Gas (mmbtu):
Swaps:
2005 Remaining	82,490,000		$	7.02		$	—	$	—	$	—		Yes	$	—	$	(21,032	)
2006	90,235,000			7.45			—		—		—		Yes		—		(53,142	)
2007	9,900,000			8.24			—		—		—		Yes		—		(3,516	)

Basis Protection Swaps:
2005 Remaining	96,280,000			—			—		—		(0.27	)	No		—		25,520
2006	130,140,000			—			—		—		(0.32	)	No		—		26,564
2007	126,495,000			—			—		—		(0.28	)	No		—		31,138
2008	118,610,000			—			—		—		(0.27	)	No		—		28,121
2009	86,600,000			—			—		—		(0.29	)	No		—		16,777

Cap-Swaps:
2005 Remaining	42,640,000			6.30			4.66		—		—		No		—		(46,129	)
2006	42,950,000			6.90			5.12		—		—		No		—		(51,358	)

Counter Swaps:
2006	(7,300,000	)		(5.59	)		—		—		—		No		—		17,537

Call Options:
2005 Remaining	3,680,000			—			—		5.79		—		No		1,638		(5,940	)

Collars:
2005 Remaining	2,968,000			—			3.59		5.37		—		Yes		—		(5,262	)
2006	180,000			—			6.00		9.70		—		Yes		—		—

Locked Swaps:
2005 Remaining	16,560,000			—			—		—		—		No		—		(21,687	)
2006	25,550,000			—			—		—		—		No		—		(22,601	)
2007	25,550,000			—			—		—		—		No		—		(11,626	)

Total Natural Gas															1,638		(96,636	)

Oil (bbls):
Swaps:
2005 Remaining	1,272,000			55.63			—		—		—		Yes		—		(3,618	)
2006	2,341,000			56.58			—		—		—		Yes		—		(5,264	)
2007	590,000			53.33			—		—		—		Yes		—		(2,526	)

Cap-Swaps:
2005 Remaining	552,000			44.35			33.33		—		—		No		—		(7,897	)
2006	501,500			57.58			40.54		—		—		No		—		(2,236	)

Total Oil															—		(21,541	)

Total Natural Gas and Oil														$	1,638	$	(118,177	)

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 June 30, 2005.

Based upon the market prices at June 30, 2005, we expect to transfer approximately $51.5 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 June 30, 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		(160,532	)
Contracts realized or otherwise settled during the period		4,005

Fair value of contracts outstanding, as of June 30	$	(118,177	)

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 June 30, 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
Liabilities:
Long-term debt — fixed-rate^(a)	$	—	$	—	$	—	$	8.0		$	—	$	3,743.4		$	3,751.4		$	3,865.7
Average interest rate		—		—		—		8.4	%		—		6.9	%		6.9	%		6.9	%

Long-term debt — variable rate	$	—	$	—	$	—	$	—		$	—	$	455.0		$	455.0		$	455.0
Average interest rate		—		—		—		—			—		4.6	%		4.6	%		4.6	%

(a)	This amount does not include the discount included in long-term debt of ($87.3) million and the premium for interest rate swaps of $6.8 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

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.

As of June 30, 2005, the following interest rate swap was used to convert a portion of our long-term fixed-rate debt to floating-rate debt was 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	$	(714	)

Subsequent to June 30, 2005, we entered into the following interest rate swaps (which qualify as fair value hedges) to convert a portion of our long-term fixed-rate debt to floating-rate debt:


Term	Notional Amount		Fixed Rate		Floating Rate
July 2005 – January 2015	$	150,000,000	7.750	%	6 month LIBOR plus 289 basis points
July 2005 – June 2014	$	150,000,000	7.500	%	6 month LIBOR plus 282 basis points
August 2005 – August 2014	$	200,000,000	7.000	%	6 month LIBOR plus 205.5 basis points

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 June 30, 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)
April 1, 2005 through April 30, 2005	27,174	$	19.654	—	—
May 1, 2005 through May 31, 2005	56,089		19.231	—	—
June 1, 2005 through June 30, 2005	16,764		22.559	—	—

Total	100,027	$	19.904	—	—

(a)	Includes 97,089 shares purchased in the open market for the matching contributions we make to our 401(k) plans and the surrender to the company of 2,938 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.

Item

3. Defaults Upon Senior Securities

Not applicable.

Item

4. Submission of Matters to a Vote of Security Holders

Three matters were submitted to a vote of the shareholders at Chesapeake’s annual meeting of shareholders held on June 10, 2005: the election of directors for three year terms expiring in 2008, approval of the company’s Long Term Incentive Plan covering awards of stock-based compensation to its employees, consultants and non-employee directors and approval of the Founder Well Participation Program which permits the company’s two founders, Aubrey K. McClendon and Tom L. Ward, to continue participating as working interest owners in the wells that the company drills in the future.

In the election of directors, Aubrey K. McClendon received 275,023,161 votes for election and 14,536,458 votes were withheld from voting for Mr. McClendon; and Donald L. Nickles received 282,469,884 votes for election and 7,089,735 votes were withheld from voting for Mr. Nickles. There were no broker non-votes for the election of directors. The other directors whose terms continue after the meeting are Breene M. Kerr and Charles T. Maxwell, whose terms expire in 2006, and Tom L. Ward, Frank A. Keating and Frederick B. Whittemore, whose terms expire in 2007. Shannon Self, a director of the Company since 1993, advised the Board of Directors on April 21, 2005 that he would not stand for re-election at the expiration of his term at the meeting.

On the proposal to adopt the Long Term Incentive Plan, 159,556,528 votes were received for approval of the plan, 47,734,116 votes were received against approval of the plan and holders of 3,671,650 shares abstained from voting on this proposal. There were 78,597,325 broker non-votes on this proposal.

On the proposal to approve the Founder Well Participation Program, 214,568,187 votes were received for approval of the program, 70,724,971 votes were received against approval of the program and holders of 4,266,460 shares abstained from voting on this proposal. There was one broker non-vote on this proposal.

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. Incorporated herein by reference to Exhibit 3.1.1 to Chesapeake’s Form 10-Q for the quarter ended March 31, 2005.

3.1.2		Certificate of Designation of Series A Junior Participating Preferred Stock, as amended. Incorporated herein by reference to Exhibit 3.1.2 to Chesapeake’s Form 10-Q for the quarter ended March 31, 2005.

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), as amended. Incorporated herein by reference to Exhibit 3.1.4 to Chesapeake’s Form 10-Q for the quarter ended March 31, 2005.

3.1.5*		Certificate of Designation of 4.125% Cumulative Convertible Preferred Stock, as amended.

3.1.6		Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005), as amended. Incorporated herein by reference to Exhibit 3.1.6 to Chesapeake’s Form 10-Q for the quarter ended March 31, 2005.

4.1.1*		Fourth Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of May 27, 2004 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.50% Senior Notes due 2014.

4.2.1*		Fourth Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of August 2, 2004 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.00% Senior Notes due 2014.

4.3.1		Fourteenth Supplemental Indenture dated as of June 21, 2005 to Indenture dated as of April 6, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York (formerly United States Trust Company of New York), as Trustee, with respect to 8.125% Senior Notes due 2011. Incorporated herein by reference to Exhibit 4.2 to Chesapeake’s Form 8-K filed June 23, 2005.

4.4.1*		Twelfth Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of November 5, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 8.375% Senior Notes due 2008.

4.5.1		Eighth Supplemental Indenture dated as of June 21, 2005 to Indenture dated as of August 12, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 9.0% Senior Notes due 2012. Incorporated herein by reference to Exhibit 4.3 to Chesapeake’s Form 8-K filed June 23, 2005.

4.6.1*		Eighth Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of December 20, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.75% Senior Notes due 2015.



4.9.1*		Seventh Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of March 5, 2003 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.50% Senior Notes due 2013.

4.10.1*		Fifth Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of November 26, 2003 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 6.875% Senior Notes due 2016.

4.11.1		Second Supplemental Indenture dated as of May 13, 2005 to Indenture dated as of December 8, 2004 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 6.375% Senior Notes due 2015. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeake’s registration statement on Form S-4/A (No. 333-123634) filed May 23, 2005.

4.11.2*		Third Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of December 8, 2004 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 6.375% Senior Notes due 2015.

4.12.1*		First Supplemental Indenture dated as of July 15, 2005 to 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 6.625% Senior Notes due 2016.

4.13*		Indenture dated as of June 20, 2005 among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Trust Company, N.A., as Trustee, with respect to 6.25% Senior Notes due 2018.

4.14		Registration Rights Agreement dated June 20, 2005 between Chesapeake and Wachovia Capital Markets, LLC, with respect to 6.25% Senior Notes due 2018. Incorporated herein by reference to Exhibit 4.2 to Chesapeake’s registration statement on Form S-4 (No. 333-126476) filed July 8, 2005.

10.1.18		Long Term Incentive Plan. Incorporated herein by reference to Exhibit A to Chesapeake’s definitive proxy statement for its 2005 annual meeting of shareholders filed April 29, 2005.

10.1.18.1		Form of Non-Employee Director Stock Option Agreement for the Long Term Incentive Plan. Incorporated herein by reference to Exhibit 10.1.18.1 to Chesapeake’s Form 8-K filed June 16, 2005.

10.1.18.2		Form of Restricted Stock Award Agreement for the Long Term Incentive Plan. Incorporated herein by reference to Exhibit 10.1.18.2 to Chesapeake’s Form 8-K filed June 16, 2005.

10.1.18.3		Form of Non-Employee Director Restricted Stock Award Agreement for the Long Term Incentive Plan. Incorporated herein by reference to Exhibit 10.1.18.3 to Chesapeake’s Form 8-K filed June 16, 2005.

10.1.19		Founder Well Participation Program. Incorporated herein by reference to Exhibit B to Chesapeake’s definitive proxy statement for its 2005 annual meeting of shareholders filed April 29, 2005.

10.2.1		Fourth Amended and Restated Employment Agreement dated as of July 1, 2005, between Aubrey K. McClendon and Chesapeake. Incorporated herein by reference to Exhibit 10.2.1 to Chesapeake’s Form 8-K filed June 16, 2005.



10.2.2		Fourth Amended and Restated Employment Agreement dated as of July 1, 2005, between Tom L. Ward and Chesapeake. Incorporated herein by reference to Exhibit 10.2.2 to Chesapeake’s Form 8-K filed June 16, 2005.

10.4*		Non-Employee Director Compensation

10.5*		Named Executive Officer Compensation

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.

*	Filed herewith.

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

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: August 8, 2005

INDEX TO EXHIBITS


Exhibit Number		Description
3.1.1		Restated Certificate of Incorporation, as amended. Incorporated herein by reference to Exhibit 3.1.1 to Chesapeake’s Form 10-Q for the quarter ended March 31, 2005.

3.1.2		Certificate of Designation of Series A Junior Participating Preferred Stock, as amended. Incorporated herein by reference to Exhibit 3.1.2 to Chesapeake’s Form 10-Q for the quarter ended March 31, 2005.

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), as amended. Incorporated herein by reference to Exhibit 3.1.4 to Chesapeake’s Form 10-Q for the quarter ended March 31, 2005.

3.1.5*		Certificate of Designation of 4.125% Cumulative Convertible Preferred Stock, as amended.

3.1.6		Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2005), as amended. Incorporated herein by reference to Exhibit 3.1.6 to Chesapeake’s Form 10-Q for the quarter ended March 31, 2005.

4.1.1*		Fourth Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of May 27, 2004 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.50% Senior Notes due 2014.

4.2.1*		Fourth Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of August 2, 2004 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.00% Senior Notes due 2014.

4.3.1		Fourteenth Supplemental Indenture dated as of June 21, 2005 to Indenture dated as of April 6, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York (formerly United States Trust Company of New York), as Trustee, with respect to 8.125% Senior Notes due 2011. Incorporated herein by reference to Exhibit 4.2 to Chesapeake’s Form 8-K filed June 23, 2005.

4.4.1*		Twelfth Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of November 5, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 8.375% Senior Notes due 2008.

4.5.1		Eighth Supplemental Indenture dated as of June 21, 2005 to Indenture dated as of August 12, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 9.0% Senior Notes due 2012. Incorporated herein by reference to Exhibit 4.3 to Chesapeake’s Form 8-K filed June 23, 2005.

4.6.1*		Eighth Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of December 20, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.75% Senior Notes due 2015.

4.9.1*		Seventh Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of March 5, 2003 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.50% Senior Notes due 2013.


4.10.1*		Fifth Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of November 26, 2003 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 6.875% Senior Notes due 2016.

4.11.1		Second Supplemental Indenture dated as of May 13, 2005 to Indenture dated as of December 8, 2004 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 6.375% Senior Notes due 2015. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeake’s registration statement on Form S-4/A (No. 333-123634) filed May 23, 2005.

4.11.2*		Third Supplemental Indenture dated as of July 15, 2005 to Indenture dated as of December 8, 2004 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 6.375% Senior Notes due 2015.

4.12.1*		First Supplemental Indenture dated as of July 15, 2005 to 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 6.625% Senior Notes due 2016.

4.13*		Indenture dated as of June 20, 2005 among Chesapeake, as Issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York Trust Company, N.A., as Trustee, with respect to 6.25% Senior Notes due 2018.

4.14		Registration Rights Agreement dated June 20, 2005 between Chesapeake and Wachovia Capital Markets, LLC, with respect to 6.25% Senior Notes due 2018. Incorporated herein by reference to Exhibit 4.2 to Chesapeake’s registration statement on Form S-4 (No. 333-126476) filed July 8, 2005.

10.1.18		Long Term Incentive Plan. Incorporated herein by reference to Exhibit A to Chesapeake’s definitive proxy statement for its 2005 annual meeting of shareholders filed April 29, 2005.

10.1.18.1		Form of Non-Employee Director Stock Option Agreement for the Long Term Incentive Plan. Incorporated herein by reference to Exhibit 10.1.18.1 to Chesapeake’s Form 8-K filed June 16, 2005.

10.1.18.2		Form of Restricted Stock Award Agreement for the Long Term Incentive Plan. Incorporated herein by reference to Exhibit 10.1.18.2 to Chesapeake’s Form 8-K filed June 16, 2005.

10.1.18.3		Form of Non-Employee Director Restricted Stock Award Agreement for the Long Term Incentive Plan. Incorporated herein by reference to Exhibit 10.1.18.3 to Chesapeake’s Form 8-K filed June 16, 2005.

10.1.19		Founder Well Participation Program. Incorporated herein by reference to Exhibit B to Chesapeake’s definitive proxy statement for its 2005 annual meeting of shareholders filed April 29, 2005.

10.2.1		Fourth Amended and Restated Employment Agreement dated as of July 1, 2005, between Aubrey K. McClendon and Chesapeake. Incorporated herein by reference to Exhibit 10.2.1 to Chesapeake’s Form 8-K filed June 16, 2005.

10.2.2		Fourth Amended and Restated Employment Agreement dated as of July 1, 2005, between Tom L. Ward and Chesapeake. Incorporated herein by reference to Exhibit 10.2.2 to Chesapeake’s Form 8-K filed June 16, 2005.

10.4*		Non-Employee Director Compensation

10.5*		Named Executive Officer Compensation

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.

*	Filed herewith.

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