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 September 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		73118
Oklahoma City, Oklahoma		(Zip Code)
(Address of principal executive offices)

(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 ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of October 31, 2005, there were 344,688,952 shares of our $0.01 par value common stock outstanding.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

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


		Page
PART I.
Financial Information

Item 1.	Condensed Consolidated Financial Statements (Unaudited):
	Condensed Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004	3
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2005 and 2004	4
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2005 and 2004	5
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 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	21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37

Item 4.	Controls and Procedures	43

PART II.
Other Information

Item 1.	Legal Proceedings	44

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44

Item 3.	Defaults Upon Senior Securities	44

Item 4.	Submission of Matters to a Vote of Security Holders	44

Item 5.	Other Information	45

Item 6.	Exhibits	45

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	September 30, 2005			December 31, 2004
	($ in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	127,102		$	6,896
Accounts receivable:
Oil and gas sales		509,071			347,081
Joint interest, net of allowances of $3,790,000 and $4,648,000, respectively		77,385			68,220
Related parties		13,276			8,286
Other		53,893			35,781
Deferred income tax asset		510,982			18,068
Short-term derivative instruments		—			51,061
Inventory and other		51,857			32,147

Total Current Assets		1,343,566			567,540

PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost accounting:
Evaluated oil and gas properties		12,616,358			9,451,413
Unevaluated properties		1,271,662			761,785
Less: accumulated depreciation, depletion and amortization of oil and gas properties		(3,674,895	)		(3,057,742	)

Total oil and gas properties, at cost based on full-cost accounting		10,213,125			7,155,456
Other property and equipment		487,241			324,495
Drilling rigs		91,431			49,375
Less: accumulated depreciation and amortization of other property and equipment and drilling rigs		(114,373	)		(84,942	)

Total Property and Equipment		10,677,424			7,444,384

OTHER ASSETS:
Investment in Pioneer Drilling		150,341			65,950
Other investments		59,746			26,793
Long-term derivative instruments		46,345			44,169
Other assets		88,207			95,673

Total Other Assets		344,639			232,585

TOTAL ASSETS	$	12,365,629		$	8,244,509

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	495,268		$	367,176
Short-term derivative instruments		957,756			91,414
Other accrued liabilities		223,700			222,029
Revenues and royalties due others		306,070			216,820
Accrued interest		59,684			66,514

Total Current Liabilities		2,042,478			963,953

LONG-TERM LIABILITIES:
Long-term debt, net		4,250,160			3,075,109
Deferred income tax liability		1,659,128			933,873
Asset retirement obligation		86,022			73,718
Long-term derivative instruments		79,788			1,296
Revenues and royalties due others		21,357			17,007
Other liabilities		20,376			16,670

Total Long-Term Liabilities		6,116,831			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, 101,275 and 103,110 shares issued and outstanding as of September 30, 2005 and December 31, 2004, respectively, entitled in liquidation to $5,063,750 and $5,155,500		5,064			5,156
5.00% cumulative convertible preferred stock (series 2003), 1,027,276 and 1,725,000 shares issued and outstanding as of September 30, 2005 and December 31, 2004, respectively, entitled in liquidation to $102,727,600 and $172,500,000		102,728			172,500
4.125% cumulative convertible preferred stock, 134,575 and 313,250 shares issued and outstanding as of September 30, 2005 and December 31, 2004, respectively, entitled in liquidation to $134,575,000 and $313,250,000		134,575			313,250
5.00% cumulative convertible preferred stock (series 2005), 4,600,000 and 0 shares issued and outstanding as of September 30, 2005 and December 31, 2004, respectively, entitled in liquidation to $460,000,000		460,000			—
4.50% cumulative convertible preferred stock, 3,450,000 and 0 shares issued and outstanding as of September 30, 2005 and December 31, 2004, respectively, entitled in liquidation to $345,000,000		345,000			—
Common Stock, $.01 par value, 500,000,000 shares authorized, 349,383,583 and 316,940,784 shares issued at September 30, 2005 and December 31, 2004, respectively		3,494			3,169
Paid-in capital		3,071,255			2,440,105
Retained earnings		686,426			262,987
Accumulated other comprehensive income (loss), net of tax of $276,733,000 and ($11,489,000), respectively		(481,440	)		20,425
Unearned compensation		(94,691	)		(32,618	)
Less: treasury stock, at cost; 5,324,374 and 5,072,121 common shares as of September 30, 2005 and December 31, 2004, respectively		(26,091	)		(22,091	)

Total Stockholders’ Equity		4,206,320			3,162,883

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	12,365,629		$	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 September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	($ in thousands, except per share data)
REVENUES:
Oil and gas sales	$	720,928		$	450,936		$	2,032,271		$	1,270,394
Oil and gas marketing sales		361,915			178,860			882,040			496,823

Total Revenues		1,082,843			629,796			2,914,311			1,767,217

OPERATING COSTS:
Production expenses		80,765			54,102			222,660			148,500
Production taxes		53,102			30,872			136,313			68,559
General and administrative expenses:
General and administrative (excluding stock-based compensation)		10,536			8,361			29,468			23,947
Stock-based compensation		5,249			584			10,172			3,125
Oil and gas marketing expenses		353,510			175,426			860,789			486,205
Oil and gas depreciation, depletion and amortization		231,145			153,586			621,484			410,237
Depreciation and amortization of other assets		12,902			7,700			34,791			20,155

Total Operating Costs		747,209			430,631			1,915,677			1,160,728

INCOME FROM OPERATIONS		335,634			199,165			998,634			606,489

OTHER INCOME (EXPENSE):
Interest and other income		2,428			885			7,790			3,563
Interest expense		(58,593	)		(48,689	)		(155,623	)		(124,040	)
Loss on repurchases or exchanges of Chesapeake debt		(747	)		—			(70,047	)		(6,925	)

Total Other Income (Expense)		(56,912	)		(47,804	)		(217,880	)		(127,402	)

INCOME BEFORE INCOME TAX		278,722			151,361			780,754			479,087
INCOME TAX EXPENSE:
Current		—			—			—			—
Deferred		101,734			54,489			284,977			172,470

Total Income Tax Expense		101,734			54,489			284,977			172,470

NET INCOME		176,988			96,872			495,777			306,617
PREFERRED STOCK DIVIDENDS		(10,204	)		(11,287	)		(25,526	)		(30,799	)
LOSS ON CONVERSION/EXCHANGE OF PREFERRED STOCK		(17,725	)		—			(22,468	)		—

NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$	149,059		$	85,585		$	447,783		$	275,818

EARNINGS PER COMMON SHARE:
Basic	$	0.46		$	0.33		$	1.42		$	1.13
Assuming dilution	$	0.43		$	0.29		$	1.32		$	0.96
CASH DIVIDEND DECLARED PER COMMON SHARE	$	0.050		$	0.045		$	0.145		$	0.125
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in thousands):
Basic		322,101			257,096			314,425			245,087
Assuming dilution		367,639			338,285			352,210			320,089

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)


	Nine Months Ended September 30,
	2005			2004
	($ in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$	495,777		$	306,617
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization		649,907			426,404
Unrealized losses on derivatives		135,175			72,512
Deferred income taxes		284,977			172,470
Amortization of loan costs		6,368			3,988
Amortization of bond discount		4,208			3,300
Stock-based compensation		10,172			3,125
Income from equity investments		(2,171	)		(786	)
Loss on repurchases or exchanges of Chesapeake debt		70,047			6,925
Other		(503	)		569

Cash provided by operating activities before changes in assets and liabilities		1,653,957			995,124
Change in assets and liabilities		(15,589	)		43,082

Cash provided by operating activities		1,638,368			1,038,206

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions of oil and gas companies, proved properties and unproved properties, net of cash acquired		(1,798,704	)		(1,657,481	)
Exploration and development of oil and gas properties		(1,622,375	)		(888,288	)
Additions to buildings and other fixed assets		(156,978	)		(77,073	)
Additions to drilling rig equipment		(42,056	)		(19,315	)
Additions to investments		(37,273	)		(26,740	)
Divestitures of oil and gas properties		1,881			271
Other		461			385

Cash used in investing activities		(3,655,044	)		(2,668,241	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings		3,561,000			1,413,000
Payments on long-term borrowings		(3,620,000	)		(1,261,000	)
Proceeds from issuance of preferred stock, net of offering costs		782,368			304,936
Proceeds from issuance of common stock, net of offering costs		289,391			624,187
Proceeds from issuance of senior notes, net of offering costs		1,765,383			582,889
Purchases or exchanges of Chesapeake senior notes, including redemption premiums		(617,430	)		(57,320	)
Common stock dividends		(45,771	)		(26,886	)
Preferred stock dividends		(17,315	)		(30,257	)
Financing costs of credit facility		(4,672	)		(8,737	)
Purchases of treasury shares		(4,000	)		—
Net increase in outstanding payments in excess of cash balance		33,751			89,321
Cash received from exercise of stock options and warrants		19,940			9,047
Other financing costs		(5,763	)		(653	)

Cash provided by financing activities		2,136,882			1,638,527

Net increase (decrease) in cash and cash equivalents		120,206			8,492
Cash and cash equivalents, beginning of period		6,896			40,581

Cash and cash equivalents, end of period	$	127,102		$	49,073

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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	($ in thousands)
Net income	$	176,988		$	96,872		$	495,777		$	306,617
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments, net of income taxes of ($345,346,000), ($20,586,000), ($389,909,000) and ($83,149,000)		(600,807	)		(36,598	)		(678,334	)		(147,820	)
Reclassification of (gain) loss on settled contracts, net of income taxes of $40,815,000, $7,917,000, $39,798,000 and $19,586,000		71,007			14,075			69,238			34,819
Ineffective portion of derivatives qualifying for cash flow hedge accounting, net of income taxes of $36,307,000, $643,000, $36,092,000 and $6,126,000		63,165			1,143			62,791			10,890
Unrealized gain on marketable securities, net of income taxes of $12,046,000, $0, $25,544,000 and $0		20,957			—			44,440			—

Comprehensive income (loss)	$	(268,690	)	$	75,492		$	(6,088	)	$	204,506

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 statement of the results for the interim periods have been reflected. The results for the three and nine months ended September 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 nine months ended September 30, 2005 (the “Current Quarter” and “Current Period”, respectively) and the three and nine months ended September 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 $2.3 million, $0.3 million, $2.7 million and $0.5 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 2.97% to 4.18%, dividend yields ranging from 0.52% to 1.22%, and volatility factors for the expected market price of our common stock ranging from 0.29 to 0.46. 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 September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	($ in thousands, except per share amounts)
Net Income:
As reported	$	176,988		$	96,872		$	495,777		$	306,617
Stock-based compensation expense included in net income, net of tax		3,333			374			6,459			2,000
Pro forma compensation expense, net of tax		(5,218	)		(3,152	)		(13,176	)		(10,647	)

Pro forma	$	175,103		$	94,094		$	489,060		$	297,970

Basic earnings per common share
As reported	$	0.46		$	0.33		$	1.42		$	1.13

Pro forma	$	0.46		$	0.32		$	1.40		$	1.09

Diluted earnings per common share
As reported	$	0.43		$	0.29		$	1.32		$	0.96

Pro forma	$	0.42		$	0.28		$	1.30		$	0.93

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 September 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 and to directors in July 2005. 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 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 expenses).

Chesapeake issued 2.0 million, 1.5 million, 3.8 million and 2.7 million shares of restricted stock to employees in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. Total stock-based compensation related to restricted stock was $8.0 million, $0.4 million, $16.1 million and $3.9 million in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively. Of this amount, $4.3 million, $0.3 million, $8.7 million and $2.6 million was reflected as stock-based compensation expense (a sub-category of general and administrative expenses) in the condensed consolidated statements of operations for the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively, and the remainder was capitalized to oil and gas properties.

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 September 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.

Chesapeake enters into derivatives from time to time for the purpose of converting a fixed price gas sales contract to a floating price. We refer to these contracts as floating-price swaps. For a floating-price swap, Chesapeake receives a floating market price from the counterparty and pays a fixed price.

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 September 30, 2005, the fair value of our basis protection swaps was $331.4 million. As of September 30, 2005,

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

our basis protection swaps cover approximately 44% of our anticipated remaining gas production in 2005, 25% in 2006, 23% in 2007, 20% in 2008 and 14% 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 ($122.6) million, ($38.0) million, ($126.6) million and ($67.6) 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 ($104.0) million, ($32.5) million, ($137.1) million and ($66.6) 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 ($99.5) million, ($1.8) million, ($98.9) million and ($17.0) 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 September 30, 2005 and December 31, 2004 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.


	September 30, 2005			December 31, 2004
	($ in thousands)
Derivative assets (liabilities):
Fixed-price gas swaps	$	(894,620	)	$	57,073
Gas basis protection swaps		331,361			122,287
Fixed-price gas cap-swaps		(342,884	)		(48,761	)
Fixed-price gas counter-swaps		44,603			4,654
Gas call options^(a)		(36,618	)		(5,793	)
Fixed-price gas collars		(9,771	)		(5,573	)
Fixed-price gas locked swaps		(45,041	)		(77,299	)
Floating-price gas swaps		20,763			—
Fixed-price oil swaps		(35,176	)		—
Fixed-price oil cap-swaps		(11,901	)		(8,238	)

Estimated fair value	$	(979,284	)	$	38,350

^(a)	After adjusting for the remaining $23.8 million and $3.2 million premium paid to Chesapeake by the counterparty, the cumulative unrealized loss related to these call options as of September 30, 2005 and December 31, 2004 was $12.8 million and $2.6 million, respectively.

Based upon the market prices at September 30, 2005, we expect to transfer approximately $473.3 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 September 30, 2005 are expected to mature by December 31, 2008, with the exception of our basis protection swaps which extend through 2009.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

average of the daily negative fair market value amounts, if any, during the quarter. As of September 30, 2005, the fair market value of the natural gas and oil hedging transactions was a liability of $228.0 million under one of the facilities and a liability of $116.5 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.

As of September 30, 2005, the following interest rate swaps used to convert a portion of our long-term fixed-rate debt to floating-rate debt were outstanding:


Term	Notional Amount		Fixed Rate		Floating Rate	Fair Value Gain (Loss)
						($ in thousands)
September 2004 – August 2012	$	75,000,000	9.000	%	6 month LIBOR plus 452 basis points	$	(2,129	)
July 2005 – January 2015	$	150,000,000	7.750	%	6 month LIBOR plus 289 basis points	$	(3,582	)
July 2005 – June 2014	$	150,000,000	7.500	%	6 month LIBOR plus 282 basis points	$	(3,734	)
September 2005 – August 2014	$	250,000,000	7.000	%	6 month LIBOR plus 205.5 basis points	$	(2,470	)

Subsequent to September 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
October 2005 – January 2018	$	250,000,000	6.250	%	6 month LIBOR plus 99 basis points
October 2005 – June 2015	$	200,000,000	6.375	%	6 month LIBOR plus 112 basis points
October 2005 – January 2016	$	200,000,000	6.625	%	6 month LIBOR plus 129 basis points

In the Current Quarter and Current Period, we closed various interest rate swaps for gains totaling $2.0 million and $7.1 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 amounts for such debt, excluding discounts or premiums related to interest rate derivatives, at September 30, 2005 and December 31, 2004 were $4.251 billion and $3.014 billion, respectively, compared to approximate fair values of $4.444 billion and $3.281 billion, respectively. The carrying amounts for our convertible preferred stock as of September 30, 2005 and December 31, 2004 were $1.047 billion and $490.9 million, respectively, compared to approximate fair values of $1.197 billion and $533.7 million, respectively.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Concentration of Credit Risk

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

3. Contingencies and Commitments

Litigation

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

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 the following 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 September 30, 2005.

Other Commitments

Chesapeake’s wholly owned subsidiary, Nomac Drilling Company, as of September 30, 2005, had contracted to acquire 26 rigs to be constructed during 2005 and 2006. The total cost of the rigs will be approximately $226 million.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

On September 16, 2005, Chesapeake executed a letter of intent to purchase approximately $75 million of new common shares from Gastar Exploration Ltd., acquire certain Gastar leasehold interests for $8.6 million and form an area of mutual interest with Gastar. This transaction is expected to close in the fourth quarter of 2005.

On September 30, 2005, we agreed to acquire Columbia Energy Resources, LLC and its subsidiaries, including Columbia Natural Resources, LLC (CNR) for $2.2 billion in cash, subject to closing adjustments, and the assumption of certain CNR liabilities. This pending transaction is described in more detail in Note 9.

4. Net Income Per Share

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

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

•

For the Current Quarter, the Prior Quarter, Current Period and Prior Period, outstanding options to purchase 0.1 million, 0.2 million, 0.1 million and 0.1 million shares of common stock at a weighted-average exercise price of $30.59, $22.72, $29.85 and $23.58, 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 the Current Quarter and the Current Period, diluted shares do not include the common stock equivalent of 4.125% preferred stock outstanding prior to conversion (convertible into 3,913,918 and 8,403,579 shares, respectively) as the effect was antidilutive, and the preferred stock adjustments to net income do not include $14.7 million and $22.9 million, respectively, of dividends and loss on conversion/exchange related to these preferred shares.

•

For the Current Quarter and the Current Period, diluted shares do not include the common stock equivalent of 5.0% preferred stock (Series 2003) outstanding prior to conversion (convertible into 3,603,567 and 4,034,450 shares, respectively) as the effect was antidilutive, and the preferred stock adjustments to net income do not include $4.0 million and $5.8 million, respectively, of dividends and loss on conversion/exchange related to these preferred shares.

•

For the Current Quarter and the Current Period, diluted shares do not include the common stock equivalent of 4.5% preferred stock (convertible into 1,443,236 and 486,365 shares, respectively) as the effect was antidilutive, and the preferred stock adjustments to net income do not include $0.7 million and $0.7 million, respectively, of dividends related to these preferred shares.

During the Current Period, holders of our 4.125% preferred stock converted 178,675 shares into 11,441,008 shares of common stock. During the fourth quarter, holders will be permitted to surrender shares of our 4.125% preferred stock for conversion into shares of our common stock because the closing sale price of our common stock for at least 20 trading days in the period of 30 consecutive trading days ending on September 30, 2005 was more than 130% of the conversion price on such trading day.

Also, during the Current Period, we exchanged 697,724 shares of our outstanding 5.0% (Series 2003) preferred stock for 4,354,439 shares of common stock and holders of our 6.0% preferred stock converted 1,835 shares into 8,918 shares of common stock.

In April 2005, we issued 4,600,000 shares of 5.00% (Series 2005) cumulative convertible preferred stock, par value $0.01 per share and liquidation preference $100 per share, in a private offering for net proceeds of $447.2 million.

In September 2005, we issued 3,450,000 shares of 4.50% cumulative convertible preferred stock, par value $0.01 per share and liquidation preference $100 per share, in a public offering for net proceeds of $335.2 million.

In September 2005, we issued 9,200,000 shares of Chesapeake common stock at $32.72 per share in a public offering for net proceeds of $289.4 million.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Reconciliations for the three months ended September 30, 2005 and 2004 and the nine months ended September 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 September 30, 2005:
Basic EPS:
Income available to common shareholders	$	149,059	322,101	$	0.46

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		—	8,082
Common shares assumed issued for 5.00% convertible preferred stock (series 2003)		—	6,262
Common shares assumed issued for 6.00% convertible preferred stock		—	492
Common shares assumed issued for 5.00% convertible preferred stock (series 2005)		—	17,853
Preferred stock dividends		8,498	—
Employee stock options		—	11,006
Restricted stock		—	1,843

Diluted EPS Income available to common shareholders and assumed conversions	$	157,557	367,639	$	0.43

For the Three Months Ended September 30, 2004:
Basic EPS:
Income available to common shareholders	$	85,585	257,096	$	0.33

Effect of Dilutive Securities
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 5.00% convertible preferred stock (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		—	17,625
Common shares assumed issued for 4.125% convertible preferred stock		—	18,812
Common stock equivalent of preferred stock outstanding prior to conversion, 6.75% convertible preferred stock		—	1,621
Preferred stock dividends		11,287	—
Employee stock options		—	9,992
Restricted stock		—	249
Warrants assumed in Gothic acquisition		—	16

Diluted EPS Income available to common shareholders and assumed conversions	$	96,872	338,285	$	0.29

For the Nine Months Ended September 30, 2005:
Basic EPS:
Income available to common shareholders	$	447,783	314,425	$	1.42

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		—	8,082
Common shares assumed issued for 5.00% convertible preferred stock (series 2003)		—	6,262
Common shares assumed issued for 6.00% convertible preferred stock		—	492
Common shares assumed issued for 5.00% convertible preferred stock (series 2005)		—	10,739
Common stock equivalent of preferred stock outstanding prior to conversion, 6.00% convertible preferred stock		—	5
Preferred stock dividends		18,546	—
Employee stock options		—	10,810
Restricted stock		—	1,382
Warrants assumed in Gothic acquisition		—	13

Diluted EPS Income available to common shareholders and assumed conversions	$	466,329	352,210	$	1.32

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 Nine Months Ended September 30, 2004:
Basic EPS:
Income available to common shareholders	$	275,818	245,087	$	1.13

Effect of Dilutive Securities
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 5.00% convertible preferred stock (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		—	17,625
Common shares assumed issued for 4.125% convertible preferred stock		—	12,651
Common stock equivalent of preferred stock outstanding prior to conversion, 6.75% convertible preferred stock		—	1,774
Preferred stock dividends		30,799	—
Employee stock options		—	9,927
Restricted stock		—	142
Warrants assumed in Gothic acquisition		—	9

Diluted EPS Income available to common shareholders and assumed conversions	$	306,617	320,089	$	0.96

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

5. Senior Notes and Revolving Bank Credit Facility

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


	September 30, 2005			December 31, 2004
	($ in thousands)
8.375% Senior Notes due 2008	$	7,990		$	18,990
8.125% Senior Notes due 2011		—			245,407
9.0% Senior Notes due 2012		—			300,000
7.5% Senior Notes due 2013		363,823			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
6.5% Senior Notes due 2017		600,000			—
6.25% Senior Notes due 2018		600,000			—
Revolving bank credit facility		—			59,000
Discount on senior notes		(91,357	)		(84,924	)
Premium (discount) for interest rate derivatives^(a)		(1,141	)		1,968

Total senior notes and long-term debt	$	4,250,160		$	3,075,109

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

On November 1, 2005, we redeemed the 8.375% Senior Notes due 2008 for $8.3 million. No scheduled principal payments are required until 2013 when $363.8 million is due.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

During the periods covered by this report, we redeemed, 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 September 30, 2005:
8.125% Senior Notes due 2011	$	7.6	$	0.5	$	0.1	$	0.6
9.0% Senior Notes due 2012		1.1		0.1		0.0		0.1

	$	8.7	$	0.6	$	0.1	$	0.7

For the Nine Months Ended September 30, 2005:
8.375% Senior Notes due 2008	$	11.0	$	0.8	$	0.1	$	0.9
8.125% Senior Notes due 2011		245.4		17.3		4.4		21.7
9.0% Senior Notes due 2012		300.0		41.4		6.0		47.4

	$	556.4	$	59.5	$	10.5	$	70.0

For the Nine Months Ended September 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 (other than the indenture governing the 6.5% Senior Notes due 2017) 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 September 30, 2005, we had no outstanding borrowings under our facility and utilized $80.1 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

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

least 2.5 to 1 and an indebtedness to EBITDA ratio (as defined) not to exceed 3.5 to 1. At September 30, 2005, our fixed charge coverage ratio was 6.24 to 1 and our indebtedness to EBITDA ratio was 2.03 to 1. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million ($50 million in the case of our 6.625% Senior Notes due 2016, 6.25% Senior Notes due 2018 and 6.5% Senior Notes due 2017), 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.

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 $617.4 million and $349.6 million for the Current Quarter and the Prior Quarter, respectively, and $1.487 billion and $932.0 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 September 30, 2005:
Revenues	$	720,928	$	361,915		$	1,082,843
Income before income taxes		271,835		6,887			278,722
For the Three Months Ended September 30, 2004:
Revenues	$	450,936	$	178,860		$	629,796
Income (loss) before income taxes		151,714		(353	)		151,361
For the Nine Months Ended September 30, 2005:
Revenues	$	2,032,271	$	882,040		$	2,914,311
Income before income taxes		764,200		16,554			780,754
For the Nine Months Ended September 30, 2004:
Revenues	$	1,270,394	$	496,823		$	1,767,217
Income before income taxes		478,127		960			479,087
As of September 30, 2005:
Total assets	$	11,813,195	$	552,434		$	12,365,629
As of December 31, 2004:
Total assets	$	7,926,263	$	318,246		$	8,244,509

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

Third	Hallwood Energy III, L.P.	Barnett Shale		250	^(c)
	Corpus Christi-based oil and gas company	Ark-La-Tex		95
	Other	Various		116

			$	1,830

^(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 of 2004.

^(c)	Includes $15 million related to gathering systems which was allocated to other property and equipment.

During the Current Period, we have recorded approximately $253 million of deferred tax liability to reflect the tax effect of the cost paid in excess of the tax basis acquired on certain corporate acquisitions.

8. Recently Issued Accounting Standards

The Financial Accounting Standards Board 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.

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

9. Subsequent Events

On September 30, 2005, Chesapeake agreed to acquire Columbia Energy Resources, LLC and its subsidiaries, including Columbia Natural Resources, LLC, (CNR) for $2.2 billion in cash, subject to closing adjustments. Chesapeake will assume certain CNR liabilities, the final calculation of which is dependent upon natural gas prices on the day of the closing, among other things. CNR’s primary assets are Appalachian Basin proved natural gas reserves, unevaluated oil and gas leasehold interests and natural gas gathering systems. The closing is expected to occur by December 1, 2005. Chesapeake plans to finance the acquisition through proceeds from debt and equity offerings, borrowings under its revolving bank credit facility and, if needed, a bridge loan.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Net Production:
Oil (mbbl)		1,926			1,834			5,684			4,972
Gas (mmcf)		108,801			83,219			304,060			229,827
Gas equivalent (mmcfe)		120,357			94,223			338,164			259,659
Oil and Gas Sales ($ in thousands):
Oil sales	$	113,590		$	73,921		$	290,332		$	181,882
Oil derivatives – realized gains (losses)		(10,937	)		(20,464	)		(28,654	)		(41,672	)
Oil derivatives – unrealized gains (losses)		(4,009	)		(14,436	)		(5,951	)		(21,925	)

Total oil sales		98,644			39,021			255,727			118,285

Gas sales		833,992			447,466			2,005,670			1,222,783
Gas derivatives – realized gains (losses)		(111,668	)		(17,514	)		(97,955	)		(25,976	)
Gas derivatives – unrealized gains (losses)		(100,040	)		(18,037	)		(131,171	)		(44,698	)

Total gas sales		622,284			411,915			1,776,544			1,152,109

Total oil and gas sales	$	720,928		$	450,936		$	2,032,271		$	1,270,394

Average Sales Price (excluding all gains (losses) on derivatives):
Oil ($ per bbl)	$	58.98		$	40.31		$	51.08		$	36.58
Gas ($ per mcf)	$	7.67		$	5.38		$	6.60		$	5.32
Gas equivalent ($ per mcfe)	$	7.87		$	5.53		$	6.79		$	5.41
Average Sales Price (excluding unrealized gains (losses) on derivatives):
Oil ($ per bbl)	$	53.30		$	29.15		$	46.04		$	28.20
Gas ($ per mcf)	$	6.64		$	5.17		$	6.27		$	5.21
Gas equivalent ($ per mcfe)	$	6.85		$	5.13		$	6.42		$	5.15
Expenses ($ per mcfe):
Production expenses	$	0.67		$	0.57		$	0.66		$	0.57
Production taxes^(a)	$	0.44		$	0.33		$	0.40		$	0.26
General and administrative expenses:
General and administrative expenses (excluding stock-based compensation)	$	0.09		$	0.09		$	0.09		$	0.09
Stock-based compensation	$	0.04		$	0.01		$	0.03		$	0.01
Oil and gas depreciation, depletion and amortization	$	1.92		$	1.63		$	1.84		$	1.58
Depreciation and amortization of other assets	$	0.11		$	0.08		$	0.10		$	0.08
Interest expense^(b)	$	0.48		$	0.45		$	0.47		$	0.46
Interest Expense ($ in thousands):
Interest expense	$	58,206		$	42,258		$	160,209		$	118,335
Interest rate derivatives – realized (gains) losses		(843	)		221			(2,639	)		(184	)
Interest rate derivatives – unrealized (gains) losses		1,230			6,210			(1,947	)		5,889

Total interest expense	$	58,593		$	48,689		$	155,623		$	124,040

Net Wells Drilled		218			181			583			420
Net Producing Wells as of the End of the Period		9,313			7,838			9,313			7,838

^(a)	The Prior Period includes a pre-tax benefit of $6.8 million, or $0.03 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 we own interests in approximately 22,000 producing oil and gas wells. Our strategy is focused on discovering, developing and acquiring onshore natural gas reserves in the southwestern U.S. and in the Appalachian Basin in the eastern U.S. Specific areas of operating focus include the Mid-Continent region of the United States, which includes Oklahoma, Arkansas, Kansas and the Texas Panhandle, the South Texas and Texas Gulf Coast regions, the Permian Basin of West Texas and eastern New Mexico, the Barnett Shale area of north-central Texas and the Ark-La-Tex area of East Texas and northern Louisiana. Following our pending acquisition of Columbia Energy Resources, LLC and its subsidiaries, including Columbia Natural Resources, LLC (CNR) as described below, we will also have a significant presence in the Appalachian Basin, principally in West Virginia, eastern Kentucky, eastern Ohio and southern New York.

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. Chesapeake has built what it believes to be the largest inventories of onshore leasehold (8.0 million net acres) and 3-D seismic (11.0 million net acres) in the U.S. (pro forma for the pending CNR acquisition). On this leasehold, we have identified more than a 10-year inventory of approximately 25,000 drillsites on which we believe we can develop approximately 2.6 tcfe of proved undeveloped reserves.

Oil and natural gas production for the Current Quarter was 120.4 bcfe, an increase of 26.2 bcfe, or 28%, over the 94.2 bcfe produced in the Prior Quarter. We have increased our production for 17 consecutive quarters. During these 17 quarters, Chesapeake’s U.S. production has increased 234%, for an average compound quarterly growth rate of 7.4% and an average compound annual growth rate of 32.8%.

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 $6.85 per mcfe in the Current Quarter compared to $5.13 per mcfe in the Prior Quarter. The increase in prices resulted in an increase in revenue of $207.5 million, and increased production resulted in an increase in revenue of $134.1 million, for a total increase in revenue of $341.6 million (excluding the effect of unrealized gains or losses on derivatives). In each of the 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.

During the Current Quarter, Chesapeake drilled 241 (186 net) operated wells and participated in another 278 (32 net) wells operated by other companies. The company’s drilling success rate was 97% for both operated wells and non-operated wells. During the Current Quarter, Chesapeake invested $390.2 million in operated wells (using an average of 72 operated rigs), $74.3 million in non-operated wells (using an average of approximately 65 non-operated rigs) and $91.3 million in acquiring new 3-D seismic data and new leasehold (excluding leasehold acquired through acquisitions). Our acquisition expenditures totaled $489.1 million during the Current Quarter (including amounts paid for unproved leasehold and excluding $1.5 million of deferred taxes in connection with certain corporate acquisitions).

Chesapeake began 2005 with estimated proved reserves of 4,902 bcfe and, based on internal estimates, ended the Current Quarter with 6,213 bcfe, an increase of 1,311 bcfe, or 27%. During the Current Period, we replaced 338 bcfe of production with an estimated 1,649 bcfe of new proved reserves, for a reserve replacement rate of 488%. Reserve replacement through the drillbit was 929 bcfe, or 275% of production (including a negative 19 bcfe from performance revisions and a positive 94 bcfe from oil and natural gas price increases), or 56% of the total increase. Reserve replacement through acquisitions was 720 bcfe, or 213% of production, or 44% of the total increase.

On September 30, 2005, we agreed to acquire CNR for $2.2 billion in cash, plus assumed liabilities, the final calculation of which are subject to closing adjustments and natural gas prices on the day of closing. With the CNR acquisition, we will add approximately 1.1 tcfe of proved reserves, based on our internal estimates, and 3.5 million net oil and gas leasehold acres in the Appalachian Basin. The CNR proved reserves are 99% natural gas and 70% proved developed. We expect to finance the acquisition through the issuance of a combination of debt and equity securities and borrowings under our revolving credit facility and, if needed, a bridge loan. The closing is expected to occur before December 1, 2005 although there is no assurance that the acquisition will close, or close without material adjustment.

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 26 rigs on order for delivery over the next year. In addition, we have entered into drilling contracts for the use of approximately 20 rigs that have been or are 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 September 30, 2005, our Pioneer shares had a market value of $150.3 million. During the Current Period, we invested $15 million in the common stock of DHS Drilling Company, Inc., a Wyoming-based drilling company which has 8 rigs operating in the Rocky Mountains and which will expand to 11 rigs over the next several months. At September 30, 2005, our ownership percentage was approximately 45%. During the Current Period, we also acquired 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 September 30, 2005, the company’s debt as a percentage of total capitalization (total capitalization is the sum of debt and stockholders’ equity) was 50%, compared to 49% as of December 31, 2004. During the Current Period, we received net proceeds of $2.837 billion through issuances of $805 million of preferred equity, $301 million of common equity, and $1.800 billion principal amount of senior notes. We issued 15,804,365 shares of common stock in exchange for outstanding shares of our 4.125% and 5.0% (Series 2003) preferred stock and upon conversions of our 6.0% preferred stock. Additionally, we purchased and retired $556.4 million principal amount of outstanding senior notes during 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 6.8%.

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 $2.0 billion and $2.2 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 $1.654 billion in the Current Period compared to $995.1 million in the Prior Period. The $658.9 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 55% of our expected oil production for the fourth quarter of 2005 hedged at an average NYMEX price of $54.97 per barrel of oil and 73% of our expected natural gas production for the fourth quarter of 2005 hedged at an average NYMEX price of $8.14 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 September 30, 2005 and October 31, 2005, we had issued $77.0 million and $68.0 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 them no more than $230 million in the aggregate.

A significant source of liquidity is our $1.25 billion syndicated revolving bank credit facility which matures in January 2010. At October 31, 2005, there was $1.2 billion 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 $3.561 billion and repaid $3.620 billion in the Current Period, and we borrowed $1.413 billion and repaid $1.261 billion in the Prior Period under our revolving bank credit facility. We incurred $4.7 million and $8.7 million of financing costs related to our revolving bank 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, general and administrative expenses, our capital expenditure budget, our short-term contractual obligations and dividend payments at current levels for the foreseeable future. We intend to finance the CNR acquisition with proceeds from debt and equity offerings, borrowings from our revolving bank credit facility and, if needed, a bridge loan.

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 Nine Months Ended September 30,
	2005				2004
	Total Proceeds		Net Proceeds		Total Proceeds		Net Proceeds
Convertible preferred stock	$	805.0	$	782.4	$	313.3	$	304.9
Common stock		301.0		289.4		650.0		624.2
Unsecured senior notes guaranteed by subsidiaries		1,800.0		1,765.4		600.0		582.9

Total	$	2,906.0	$	2,837.2	$	1,563.3	$	1,512.0

We expect to utilize the automatic shelf registration, which will become available beginning December 1, 2005, to register future debt and equity issuances with the Securities and Exchange Commission. A prospectus supplement will be prepared at the time of an offering and will contain a description of the security issued, the plan of distribution and other information. We believe this new form of registration will provide us additional flexibility in responding to our capital needs.

We paid dividends on our common stock of $45.8 million and $26.9 million in the Current Period and the Prior Period, respectively. We paid dividends on our preferred stock of $17.3 million and $30.3 million in the Current Period and the Prior Period, respectively. We received $19.9 million and $9.0 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 $33.8 million and $89.3 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 revolving bank credit facility.

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


	Senior Notes Activity
	Retired		Premium		Other^(a)		Issued^(b)			Cash Paid
For the Nine Months Ended September 30, 2005:
8.375% Senior Notes due 2008	$	11.0	$	0.8	$	—	$	—		$	11.8
8.125% Senior Notes due 2011		245.4		17.3		0.7		—			263.4
9.0% Senior Notes due 2012		300.0		41.4		0.8		—			342.2

	$	556.4	$	59.5	$	1.5	$	—		$	617.4


For the Nine Months Ended September 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 $3.655 billion during the Current Period, compared to $2.668 billion during the Prior Period. The following table shows our capital expenditures during these periods ($ in millions):


	Nine Months Ended September 30,
	2005			2004
Acquisitions of oil and gas companies, proved and unproved properties, net of cash acquired	$	1,798.7		$	1,657.5
Exploration and development of oil and gas properties		1,622.4			888.3
Additions to buildings and other fixed assets		157.0			77.1
Additions to drilling rig equipment		42.1			19.3
Additions to investments		37.3			26.7
Divestitures of oil and gas properties		(1.9	)		(0.3	)
Other		(0.6	)		(0.4	)

Total	$	3,655.0		$	2,668.2

Our accounts receivable are primarily from purchasers of oil and natural gas ($509.1 million at September 30, 2005) and exploration and production companies which own interests in properties we operate ($77.4 million at September 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

Third	Hallwood Energy, III L.P.	Barnett Shale		250	^(c)
	Corpus Christi-based oil and gas company	Ark-La-Tex		95
	Other	Various		116

			$	1,830

^(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 of 2004.

^(c)	Includes $15 million related to gathering systems which was allocated to other property and equipment.

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 6.8%. 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% cumulative convertible preferred stock having a liquidation preference of $100 per share. Net proceeds of $1.032 billion 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 revolving bank 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.

•

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

Third Quarter 2005

•

Completed cash tender offers for our 8.125% Senior Notes due 2011 and 9.0% Senior Notes due 2012. 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. Together with the amounts acquired in June 2005, we acquired a total of $237.9 million principal amount of 8.125% Senior Notes due 2011 and $299.1 million principal amount of 9.0% 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. We redeemed the remaining $7.5 million of 8.125% and $0.9 million of 9.0% Senior Notes for $9.1 million (including a premium of $0.6 million) on August 17, 2005 based on the make-whole redemption provisions in the indentures.

•

Completed a number of transactions whereby we exchanged 133,675 shares of our 4.125% cumulative convertible preferred stock for 8,529,758 shares of our common stock. No cash was received or paid in connection with these transactions.

•

Completed a number of transactions whereby we exchanged 697,724 shares of our 5.0% (Series 2003) cumulative convertible preferred stock for 4,354,439 shares of our common stock. No cash was received or paid in connection with these transactions.

•

Completed a private placement of $600 million of 6.5% Senior Notes due 2017. Net proceeds of approximately $584.6 million were used to repay amounts outstanding under our revolving bank credit facility which resulted from acquisitions completed in the Current Quarter.

•

Completed public offerings of 3,450,000 shares of 4.5% cumulative convertible preferred stock having a liquidation preference of $100 per share and 9,200,000 shares of common stock at $32.72 per share. Net proceeds from both offerings of approximately $624.6 million were used to repay amounts outstanding under our revolving bank credit facility which resulted from acquisitions completed in the Current Quarter.

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 September 30, 2005, we had no outstanding borrowings under this facility and had utilized $80.1 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 September 30, 2005, our fixed charge coverage ratio was 6.24 to 1 and our indebtedness to EBITDA ratio was 2.03 to 1. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million ($50 million in the case of our 6.625% Senior Notes due 2016, 6.25% Senior Notes due 2018 and 6.5% Senior Notes due 2017), 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 September 30, 2005, we owned 14 rigs dedicated to drilling wells operated by Chesapeake and have contracted to acquire 26 additional rigs to be constructed in 2005 and 2006. We expect to spend approximately $226 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 September 30, 2005, we were required to post $77.0 million of collateral in the form of letters of credit with respect to such derivative transactions. These collateral requirements were $68.0 million as of October 31, 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 $230 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 September 30, 2005, the fair market value of the natural gas and oil hedging transactions was a liability of $228.0 million under one of the facilities and a liability of $116.5 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.

As of September 30, 2005, our senior notes represented approximately $4.3 billion of our long-term debt and consisted of the following ($ in thousands):


8.375% Senior Notes due 2008	$	7,990
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
6.5% Senior Notes due 2017		600,000
6.25% Senior Notes due 2018		600,000
Discount on senior notes		(91,357	)
Discount for interest rate derivatives		(1,141	)

	$	4,250,160

On November 1, 2005, we redeemed the 8.375 % Senior Notes due 2008 for $8.3 million. No scheduled principal payments are required until 2013, when $363.8 million is due.

As of September 30, 2005 and currently, debt ratings for the senior notes are Ba2 by Moody’s Investor Service (stable outlook), BB by Standard & Poor’s Ratings Services (stable 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 (other than the indenture governing the 6.5% Senior Notes due 2017) 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 September 30, 2005, we estimate that secured commercial bank indebtedness of approximately $2.4 billion could have been incurred under the most restrictive indenture covenant.

On September 30, 2005, Chesapeake agreed to acquire Columbia Energy Resources, LLC and its subsidiaries, including Columbia Natural Resources, LLC, (CNR) for $2.2 billion in cash, subject to closing adjustments related to outstanding debt, title defects and satisfaction of certain conditions prior to closing. CNR’s primary assets are Appalachian Basin proved natural gas reserves, unevaluated oil and gas leasehold interests and natural gas gathering systems. Chesapeake will acquire CNR subject to liabilities related to a prepaid sales agreement and hedging arrangements. As part of the acquisition, we expect to record a mark-to-market liability on those obligations, the final calculation of which is dependent upon natural gas prices on the day of the closing. We plan to finance the acquisition through the issuance of a combination of debt and equity securities, borrowings under our revolving bank credit facility and, if needed, a bridge loan. We expect to close the CNR acquisition by December 1 2005, although there is no assurance that the acquisition will close or close without material adjustment.

We recently received a commitment for up to a $1.5 billion bridge loan to provide us with an additional funding source to complete the CNR acquisition. The bridge loan commitment is limited to $1.5 billion less the gross proceeds of any debt or equity offering made by us prior to the closing of the acquisition. The maturity for the bridge loan would be the earlier of January 31, 2007 or the closing date of permanent financing for the CNR acquisition. The bridge loan would bear interest, reset quarterly, at the greater of the rate of the three-month LIBOR plus 2.25% per year or the bid side yield on our 6.625% Senior Notes due 2016 quoted at market close on the quarterly interest reset date.

Results of Operations — Three Months Ended September 30, 2005 vs. September 30, 2004

General. For the Current Quarter, Chesapeake had net income of $177.0 million, or $0.43 per diluted common share, on total revenues of $1.083 billion. This compares to net income of $96.9 million, or $0.29 per diluted common share, on total revenues of $629.8 million during the Prior Quarter. Net income included, on a pre-tax basis, net unrealized losses on oil and gas and interest rate derivatives of $105.3 million in the Current Quarter and $38.7 million in the Prior Quarter.

Oil and Gas Sales. During the Current Quarter, oil and gas sales were $720.9 million compared to $450.9 million in the Prior Quarter. In the Current Quarter, Chesapeake produced 120.4 bcfe at a weighted average price of $6.85 per mcfe, compared to 94.2 bcfe produced in the Prior Quarter at a weighted average price of $5.13 per mcfe (weighted average prices exclude the effect of unrealized gains or (losses) on derivatives of ($104.0) million and ($32.5) million in the Current Quarter and Prior Quarter, respectively). In the Current Quarter, the increase in prices resulted in an increase in revenue of $207.5 million and increased production resulted in a $134.1 million increase, for a total increase in revenues of $341.6 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 $10.9 million and $10.2 million, respectively, and a change of $1.00 per barrel of oil sold would have resulted in an increase or decrease in revenues and cash flow of approximately $1.9 million and $1.8 million, respectively, without considering the effect of derivative activities.

For the Current Quarter, we realized an average price per barrel of oil of $53.30, compared to $29.15 in the Prior Quarter (weighted average prices for both quarters discussed exclude the effect of unrealized gains or losses on derivatives). Natural gas prices realized per mcf (excluding unrealized gains or losses on derivatives) were $6.64 and $5.17 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 $122.6 million, or $1.02 per mcfe, in the Current Quarter and a net decrease of $38.0 million, or $0.40 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 September 30,
	2005			2004
	Mmcfe	Percent		Mmcfe	Percent
Mid-Continent	74,910	62	%	68,236	72	%
South Texas and Texas Gulf Coast	17,018	14		10,954	12
Ark-La-Tex and Barnett Shale	15,843	13		6,364	7
Permian Basin	11,843	10		7,995	8
Other	743	1		674	1

Total Production	120,357	100	%	94,223	100	%

Natural gas production represented approximately 90% 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 $361.9 million in oil and gas marketing sales to third parties in the Current Quarter, with corresponding oil and gas marketing expenses of $353.5 million, for a net margin of $8.4 million. Marketing activities are substantially for third parties that are owners in Chesapeake-operated wells. This compares to sales of $178.9 million, expenses of $175.4 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 $80.8 million in the Current Quarter compared to $54.1 million in the Prior Quarter. On a unit-of-production basis, production expenses were $0.67 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 $0.70 to $0.74 per mcfe produced.

Production Taxes. Production taxes were $53.1 million and $30.9 million in the Current Quarter and the Prior Quarter, respectively. On a unit-of-production basis, production taxes were $0.44 per mcfe in the Current Quarter compared to $0.33 per mcfe in the Prior Quarter. The $22.2 million increase in production taxes in the Current Quarter is due primarily to 26.2 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 $0.60 to $0.64 per mcfe based on NYMEX prices of $60 per barrel of oil and natural gas wellhead prices ranging from $9.00 to $11.30 per mcf.

General and Administrative Expenses (excluding stock-based compensation). Excluding stock-based compensation and internal payroll and non-payroll general and administrative costs capitalized in our oil and gas properties, general and administrative expenses were $10.5 million, or $0.09 per mcfe, in the Current Quarter and $8.4 million, or $0.09 per mcfe, in the Prior Quarter. The $2.1 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.

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 $29.5 million and $12.0 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 $5.2 million in the Current Quarter and $0.6 million in the Prior Quarter. During the Current Quarter, 2.0 million shares of restricted stock were issued to employees and directors. The cost of all outstanding restricted shares is amortized over a four-year period except for grants to directors which are amortized over a three-year period. This resulted in the recognition of $8.0 million of expense during the Current Quarter. Of this amount, $4.3 million was

reflected as stock-based compensation expense (a sub-category of general and administrative expenses) and the remaining $3.7 million was capitalized to oil and gas properties. We also recognized $2.3 million in stock-based compensation expense in the Current Quarter as a result of an increase in the market value of certain stock options which were previously modified. Of this amount $1.4 million was capitalized to oil and gas properties. Stock-based compensation was $0.04 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 $231.1 million and $153.6 million during the Current Quarter and the Prior Quarter, respectively. The average DD&A rate per mcfe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $1.92 and $1.63 in the Current Quarter and in the Prior Quarter, respectively. The $0.29 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 $2.05 and $2.10 per mcfe produced.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $12.9 million in the Current Quarter compared to $7.7 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 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 $0.10 and $0.12 per mcfe produced.

Interest and Other Income. Interest and other income was $2.4 million in the Current Quarter compared to $0.9 million in the Prior Quarter. The Current Quarter income consisted of $0.4 million of interest income, a $0.1 million loss related to our equity investments and $2.1 million of miscellaneous income. The Prior Quarter income consisted of $0.6 million of interest income, a $0.3 million gain related to our equity investments and $0.6 million of miscellaneous income.

Interest Expense. Interest expense increased from $48.7 million in the Prior Quarter to $58.6 million in the Current Quarter as follows:


	Three Months Ended September 30,
	2005			2004
	($ in millions)
Interest expense on senior notes and revolving bank credit facility	$	77.6		$	51.6
Capitalized interest		(20.8	)		(10.5	)
Amortization of loan discount		1.4			1.2
Unrealized (gain) loss on interest rate derivatives		1.2			6.2
Realized (gain) loss on interest rate derivatives		(0.8	)		0.2

Total interest expense	$	58.6		$	48.7

Average long-term borrowings	$	4,047		$	2,540

Interest expense on senior notes increased $20.0 million due to a higher average balance of senior notes outstanding, $4.0 billion in the Current Quarter compared to $2.5 billion in the Prior Quarter, and was partially offset by a decrease in the average interest rate, 6.8% in the Current Quarter compared to 7.7% in the Prior Quarter. The revolving bank credit facility interest expense increased $6.0 million which is the result of higher borrowings and an increase in interest rates.

The $10.3 million increase in capitalized interest is the 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 $0.45 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 $0.48 and $0.52 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 September 30, 2005:
8.125% Senior Notes due 2011	$	7.6	$	0.5	$	0.1	$	0.6
9.0% Senior Notes due 2012		1.1		0.1		0.0		0.1

	$	8.7	$	0.6	$	0.1	$	0.7

^(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 $101.7 million in the Current Quarter, compared to income tax expense of $54.5 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 all of our 2005 income tax expense to be deferred.

Results of Operations — Nine Months Ended September 30, 2005 vs. September 30, 2004

General. For the Current Period, Chesapeake had net income of $495.8 million, or $1.32 per diluted common share, on total revenues of $2.914 billion. This compares to net income of $306.6 million, or $0.96 per diluted common share, on total revenues of $1.767 billion during the Prior Period. The Current Period net income included, on a pre-tax basis, $135.2 million in net unrealized losses on oil and gas and interest rate derivatives and a $70.0 million loss on repurchases or exchanges of debt. The Prior Period net income included, on a pre-tax basis, $72.5 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 $2.032 billion compared to $1.270 billion in the Prior Period. In the Current Period, Chesapeake produced 338.2 bcfe at a weighted average price of $6.42 per mcfe, compared to 259.7 bcfe produced in the Prior Period at a weighted average price of $5.15 per mcfe (weighted average prices exclude the effect of unrealized gains or (losses) on derivatives of ($137.1) million and ($66.6) million in the Current Period and Prior Period, respectively). In the Current Period, the increase in prices resulted in an increase in revenue of $428.1 million and increased production resulted in a $404.3 million increase, for a total increase in revenues of $832.4 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 $30.4 million and $28.5 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 $5.7 million and $5.3 million, respectively, without considering the effect of derivative activities.

For the Current Period, we realized an average price per barrel of oil of $46.04, compared to $28.20 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 $6.27 and $5.21 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 $126.6 million, or $0.37 per mcfe, in the Current Period and a net decrease of $67.6 million, or $0.26 per mcfe, in the Prior Period.

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


	For the Nine Months Ended September 30,
	2005			2004
	Mmcfe	Percent		Mmcfe	Percent
Mid-Continent	222,290	65	%	194,875	75	%
South Texas and Texas Gulf Coast	45,082	13		29,682	11
Ark-La-Tex and Barnett Shale	39,772	12		11,663	5
Permian Basin	28,955	9		21,459	8
Other	2,065	1		1,980	1

Total Production	338,164	100	%	259,659	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 $882.0 million in oil and gas marketing sales to third parties in the Current Period, with corresponding oil and gas marketing expenses of $860.8 million, for a net margin of $21.2 million. Marketing activities are substantially for third parties that are owners in Chesapeake- operated wells. This compares to sales of $496.8 million, expenses of $486.2 million and a net margin of $10.6 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 $222.7 million in the Current Period compared to $148.5 million in the Prior Period. On a unit-of-production basis, production expenses were $0.66 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 $0.70 to $0.74 per mcfe.

Production Taxes. Production taxes were $136.3 million and $68.6 million in the Current Period and the Prior Period, respectively. On a unit-of-production basis, production taxes were $0.40 per mcfe in the Current Period compared to $0.26 per mcfe in the Prior Period. The $67.7 million increase in production taxes in the Current Period is due primarily to approximately 78.5 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 $0.03 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 $0.60 to $0.64 per mcfe based on NYMEX prices of $60 per barrel of oil and natural gas wellhead prices ranging from $9.00 to $11.30 per mcf.

General and Administrative Expenses (excluding stock-based compensation). Excluding stock-based compensation and internal payroll and non-payroll general and administrative costs capitalized in our oil and gas properties, general and administrative expenses were $29.5 million, or $0.09 per mcfe, in the Current Period and $23.9 million, or $0.09 per mcfe, in the Prior Period. The $5.6 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.

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 $75.3 million and $35.3 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 $10.2 million in the Current Period and $3.1 million in the Prior Period. During the Current Period, 3.8 million shares of restricted stock were issued to employees and directors. The cost of all outstanding restricted shares is amortized over a four-year period except for grants to directors which are amortized over a three-year period. This resulted in the recognition of $16.1 million of expense during the Current Period. Of this amount, $8.7 million was reflected as

stock-based compensation expense (a sub-category of general and administrative expenses), and the remaining $7.4 million was capitalized to oil and gas properties. We also recognized $2.7 million in stock-based compensation expense in the Current Period as a result of an increase in the market value of certain stock options which were previously modified. Of this amount $1.4 million was capitalized to oil and gas properties and an additional $0.1 million was related to the issuance of common stock to a director. Stock-based compensation was $0.03 per mcfe for the Current Period and $0.01 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 $621.5 million and $410.2 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 $1.84 and $1.58 in the Current Period and in the Prior Period, respectively. The $0.26 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 $2.05 and $2.10 per mcfe produced.

Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $34.8 million in the Current Period compared to $20.2 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 $0.10 and $0.12 per mcfe produced.

Interest and Other Income. Interest and other income was $7.8 million in the Current Period compared to $3.6 million in the Prior Period. The Current Period income consisted of $3.5 million of interest income, a $1.1 million gain related to our equity investments and $3.2 million of miscellaneous income. The Prior Period income consisted of $1.5 million of interest income, a $0.8 million gain related to our equity investments and $1.3 million of miscellaneous income.

Interest Expense. Interest expense increased from $124.0 million in the Prior Period to $155.6 million in the Current Period as follows:


	Nine Months Ended September 30,
	2005			2004
	($ in millions)
Interest expense on senior notes and revolving bank credit facility	$	210.7		$	138.2
Capitalized interest		(54.8	)		(23.2	)
Amortization of loan discount		4.2			3.3
Unrealized gain on interest rate derivatives		(1.9	)		5.9
Realized gain on interest rate derivatives		(2.6	)		(0.2	)

Total interest expense	$	155.6		$	124.0

Average long-term borrowings	$	3,593		$	2,309

Interest expense on senior notes increased $57.1 million due to a higher average balance of senior notes outstanding, $3.6 billion in the Current Quarter compared to $2.3 billion in the Prior Quarter, and was partially offset by a decrease in the average interest rate, 7.1% in the Current Quarter compared to 7.7% in the Prior Quarter. The revolving bank credit facility interest expense increased $15.4 million which is the result of higher borrowings and an increase in interest rates.

The $31.6 million increase in capitalized interest is the 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 $0.47 per mcfe in the Current Period compared to $0.46 per mcfe in the Prior Period. We expect interest expense (before considering the effect of interest rate derivatives) for the remainder of 2005 to be between $0.48 and $0.52 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 Nine Months Ended September 30, 2005:
8.375% Senior Notes due 2008	$	11.0	$	0.8	$	0.1	$	0.9
8.125% Senior Notes due 2011		245.4		17.3		4.4		21.7
9.0% Senior Notes due 2012		300.0		41.4		6.0		47.4

	$	556.4	$	59.5	$	10.5	$	70.0

For the Nine Months Ended September 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 $285.0 million in the Current Period, compared to income tax expense of $172.5 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 all of our 2005 income tax expense to be deferred.

Critical Accounting Policies

Recently Issued Accounting Standards

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

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 September 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, including the pending CNR acquisition,

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.

In addition, there are uncertainties associated with closing our pending acquisition of CNR and the integration and operation of its properties after closing.

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

•

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 derivatives from time to time for the purpose of converting a fixed price gas sales contract to a floating price. We refer to these contracts as floating price swaps. For a floating price swap, Chesapeake receives a floating market price from the counterparty and pays a fixed price.

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 ($104.0) million, ($32.5) million, ($137.1) million and ($66.6) million, in the Current Quarter, Prior Quarter, Current Period and Prior Period, respectively.

As of September 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 September 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	Net Premiums Received		Fair Value at September 30, 2005 ($ in thousands)
Natural Gas (mmbtu):
Swaps:
4Q 2005	59,355,000		$	8.65		$	—	$	—	$	—		Yes	$	—	$	(322,465	)
1Q 2006	53,100,000			9.57			—		—		—		Yes		—		(258,689	)
2Q 2006	34,580,000			7.89			—		—		—		Yes		—		(98,462	)
3Q 2006	34,960,000			7.89			—		—		—		Yes		—		(95,131	)
4Q 2006	28,235,000			8.06			—		—		—		Yes		—		(83,683	)
1Q 2007	14,400,000			9.09			—		—		—		Yes		—		(36,190	)
Basis Protection Swaps:
4Q 2005	49,360,000			—			—		—		(0.27	)	No		—		99,046
1Q 2006	34,200,000			—			—		—		(0.33	)	No		—		29,809
2Q 2006	30,940,000			—			—		—		(0.31	)	No		—		19,090
3Q 2006	31,280,000			—			—		—		(0.31	)	No		—		14,247
4Q 2006	33,720,000			—			—		—		(0.32	)	No		—		17,991
1Q 2007	32,850,000			—			—		—		(0.29	)	No		—		20,805
2Q 2007	29,575,000			—			—		—		(0.27	)	No		—		17,149
3Q 2007	29,900,000			—			—		—		(0.27	)	No		—		12,728
4Q 2007	34,170,000			—			—		—		(0.29	)	No		—		16,040
1Q 2008	33,215,000			—			—		—		(0.29	)	No		—		17,352
2Q 2008	26,845,000			—			—		—		(0.25	)	No		—		14,323
3Q 2008	27,140,000			—			—		—		(0.25	)	No		—		10,494
4Q 2008	31,410,000			—			—		—		(0.28	)	No		—		12,262
1Q 2009	26,100,000			—			—		—		(0.32	)	No		—		10,187
2Q 2009	20,020,000			—			—		—		(0.28	)	No		—		8,013
3Q 2009	20,240,000			—			—		—		(0.28	)	No		—		5,288
4Q 2009	20,240,000			—			—		—		(0.28	)	No		—		6,537
Cap-Swaps:
4Q 2005	20,100,000			6.31			4.61		—		—		No		—		(148,836	)
1Q 2006	7,200,000			7.11			5.06		—		—		No		—		(52,470	)
2Q 2006	11,830,000			6.84			5.13		—		—		No		—		(46,038	)
3Q 2006	11,960,000			6.85			5.13		—		—		No		—		(45,321	)
4Q 2006	11,960,000			6.89			5.13		—		—		No		—		(50,219	)
Counter Swaps:
1Q 2006	(1,800,000	)		(6.19	)		—		—		—		No		—		14,840
2Q 2006	(1,820,000	)		(5.35	)		—		—		—		No		—		9,816
3Q 2006	(1,840,000	)		(5.33	)		—		—		—		No		—		9,726
4Q 2006	(1,840,000	)		(5.50	)		—		—		—		No		—		10,221
Call Options:
4Q 2005	1,840,000			—			—		5.86		—		No		819		(14,304	)
1Q 2006	1,800,000			—			—		12.50		—		No		1,890		(5,164	)
2Q 2006	1,820,000			—			—		12.50		—		No		1,911		(1,700	)
3Q 2006	1,840,000			—			—		12.50		—		No		1,932		(1,454	)
4Q 2006	1,840,000			—			—		12.50		—		No		1,932		(2,376	)
1Q 2007	1,800,000			—			—		12.50		—		No		1,890		(3,431	)
2Q 2007	1,820,000			—			—		12.50		—		No		1,911		(1,118	)
3Q 2007	1,840,000			—			—		12.50		—		No		1,932		(1,091	)
4Q 2007	1,840,000			—			—		12.50		—		No		1,932		(1,635	)
1Q 2008	1,820,000			—			—		12.50		—		No		1,911		(2,014	)
2Q 2008	1,820,000			—			—		12.50		—		No		1,911		(573	)
3Q 2008	1,840,000			—			—		12.50		—		No		1,932		(607	)
4Q 2008	1,840,000			—			—		12.50		—		No		1,932		(1,151	)
Collars:
4Q 2005	1,384,000			—			3.49		5.27		—		Yes		—		(8,918	)
1Q 2006	180,000			—			6.00		9.70		—		Yes		—		(853	)


	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 September 30, 2005 ($ in thousands)
Locked Swaps:
4Q 2005	8,280,000		—		—	—	—	No		—		(10,812	)
1Q 2006	6,300,000		—		—	—	—	No		—		(7,598	)
2Q 2006	6,370,000		—		—	—	—	No		—		(5,199	)
3Q 2006	6,440,000		—		—	—	—	No		—		(5,099	)
4Q 2006	6,440,000		—		—	—	—	No		—		(4,706	)
1Q 2007	6,300,000		—		—	—	—	No		—		(4,789	)
2Q 2007	6,370,000		—		—	—	—	No		—		(2,517	)
3Q 2007	6,440,000		—		—	—	—	No		—		(2,049	)
4Q 2007	6,440,000		—		—	—	—	No		—		(2,272	)
Floating-Price Swaps:
4Q 2005	(1,830,000	)	(7.96	)	—	—	—	No		—		7,443
1Q 2006	(2,700,000	)	(7.96	)	—	—	—	No		—		13,320

Total Natural Gas										23,835		(932,207	)

Oil (bbls):
Swaps:
4Q 2005	797,500		58.69		—	—	—	Yes		—		(6,120	)
1Q 2006	900,000		60.00		—	—	—	Yes		—		(6,272	)
2Q 2006	880,000		59.88		—	—	—	Yes		—		(6,239	)
3Q 2006	828,000		60.16		—	—	—	Yes		—		(5,361	)
4Q 2006	828,000		59.78		—	—	—	Yes		—		(5,205	)
1Q 2007	360,000		57.13		—	—	—	Yes		—		(2,139	)
2Q 2007	91,000		51.04		—	—	—	Yes		—		(1,282	)
3Q 2007	92,000		50.56		—	—	—	Yes		—		(1,285	)
4Q 2007	92,000		50.11		—	—	—	Yes		—		(1,273	)
Cap-Swaps:
4Q 2005	276,000		44.22		33.33	—	—	No		—		(6,117	)
1Q 2006	135,000		57.82		40.67	—	—	No		—		(1,372	)
2Q 2006	136,500		57.82		40.67	—	—	No		—		(1,540	)
3Q 2006	138,000		57.82		40.67	—	—	No		—		(1,644	)
4Q 2006	92,000		56.53		40.00	—	—	No		—		(1,228	)

Total Oil										—		(47,077	)

Total Natural Gas and Oil									$	23,835	$	(979,284	)

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 September 30, 2005.

Based upon the market prices at September 30, 2005, we expect to transfer approximately $473.3 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 September 30, 2005 are expected to mature by December 31, 2008, 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		(1,121,228	)
Fair value of contracts when entered into during the period		(23,016	)
Contracts realized or otherwise settled during the period		126,610

Fair value of contracts outstanding, as of September 30	$	(979,284	)

The change in the fair value of our derivative instruments since January 1, 2005 resulted from the settlement of derivatives for a realized loss 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 September 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	$	—	$	4,334.7		$	4,342.7		$	4,443.7
Average interest rate		—		—		—		8.4		—		6.8	%		6.8	%		6.8	%

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

^(a)	This amount does not include the discount included in long-term debt of ($91.4) million and the discount for interest rate swaps of ($1.1) 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 September 30, 2005, the following interest rate swaps used to convert a portion of our long-term fixed-rate debt to floating-rate debt were outstanding:


Term	Notional Amount		Fixed Rate		Floating Rate	Fair Value Gain (Loss)
						($ in thousands)
September 2004 – August 2012	$	75,000,000	9.000	%	6 month LIBOR plus 452 basis points	$	(2,129	)
July 2005 – January 2015	$	150,000,000	7.750	%	6 month LIBOR plus 289 basis points	$	(3,582	)
July 2005 – June 2014	$	150,000,000	7.500	%	6 month LIBOR plus 282 basis points	$	(3,734	)
September 2005 – August 2014	$	250,000,000	7.000	%	6 month LIBOR plus 205.5 basis points	$	(2,470	)

Subsequent to September 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
October 2005 – January 2018	$	250,000,000	6.250	%	6 month LIBOR plus 99 basis points
October 2005 – June 2005	$	200,000,000	6.375	%	6 month LIBOR plus 112 basis points
October 2005 – January 2016	$	200,000,000	6.625	%	6 month LIBOR plus 129 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, results of operations or cash flows.

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 September 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)
July 1, 2005 through July 31, 2005	136,450	$	24.787	—	—
August 1, 2005 through August 31, 2005	44,529		28.703	—	—
September 1, 2005 through September 30, 2005	22,782		33.314	—	—

Total	203,761	$	26.596	—	—

^(a)

Includes 103,907 shares purchased in the open market for the matching contributions we make to our 401(k) plans, the deemed surrender to the company of 6,078 shares of common stock to pay the exercise price in connection with the exercise of employee stock options and the surrender to the company of 93,776 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

Not applicable.

Item 5.

Other Information

Not applicable.

Item 6.

Exhibits

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


Exhibit Number		Description

2		Purchase Agreement dated as of September 30, 2005 between Chesapeake and Triana Energy Holdings, LLC relating to the purchase and sale of Columbia Energy Resources, LLC. Incorporated herein by reference to Exhibit 2 to Chesapeake’s current report on Form 8-K filed November 1, 2005.

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. Incorporated herein by reference to Exhibit 3 to Chesapeake’s Form 8-A filed October 11, 2005.

3.1.4		Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2003), as amended. Incorporated herein by reference to Exhibit 4 to Chesapeake’s Form 8-A filed October 11, 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.

3.1.7		Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock. Incorporated herein by reference to Exhibit 3.1 to Chesapeake’s current report on Form 8-K filed September 15, 2005.

4.13		Indenture dated as of August 16, 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 6.5% Senior Notes due 2017. Incorporated herein by reference to Exhibit 4.1 to Chesapeake’s current report on Form 8-K filed August 16, 2005.

4.14		Registration Rights Agreement dated August 16, 2005 between Chesapeake and Banc of America Securities LLC, Bear, Stearns & Co. Inc., Credit Suisse First Boston LLC, Lehman Brothers Inc. and UBS Securities LLC as representatives of the several purchasers, with respect to 6.5% Senior Notes due 2017. Incorporated herein by reference to Exhibit 4.2 to Chesapeake’s registration statement on Form S-4 (No. 333-128453) filed September 20, 2005.

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

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: November 1, 2005

INDEX TO EXHIBITS


Exhibit Number		Description

2		Purchase Agreement dated as of September 30, 2005 between Chesapeake and Triana Energy Holdings, LLC relating to the purchase and sale of Columbia Energy Resources, LLC. Incorporated herein by reference to Exhibit 2 to Chesapeake’s current report on Form 8-K filed November 1, 2005.

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. Incorporated herein by reference to Exhibit 3 to Chesapeake’s Form 8-A filed October 11, 2005.

3.1.4		Certificate of Designation of 5% Cumulative Convertible Preferred Stock (Series 2003), as amended. Incorporated herein by reference to Exhibit 4 to Chesapeake’s Form 8-A filed October 11, 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.

3.1.7		Certificate of Designation of 4.5% Cumulative Convertible Preferred Stock. Incorporated herein by reference to Exhibit 3.1 to Chesapeake’s current report on Form 8-K filed September 15, 2005.

4.13		Indenture dated as of August 16, 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 6.5% Senior Notes due 2017. Incorporated herein by reference to Exhibit 4.1 to Chesapeake’s current report on Form 8-K filed August 16, 2005.

4.14		Registration Rights Agreement dated August 16, 2005 between Chesapeake and Banc of America Securities LLC, Bear, Stearns & Co. Inc., Credit Suisse First Boston LLC, Lehman Brothers Inc. and UBS Securities LLC as representatives of the several purchasers, with respect to 6.5% Senior Notes due 2017. Incorporated herein by reference to Exhibit 4.2 to Chesapeake’s registration statement on Form S-4 (No. 333-128453) filed September 20, 2005.

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

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.