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Common stock, $0.01 par value, 1,000,000,000 shares authorized, 655,330,601 and 648,549,165 shares issued at September 30, 2010 and December 31, 2009, respectively

$ 7

$ 6

Paid-in capital

12,138

12,146

Retained earnings (deficit)

(1,261)

Accumulated other comprehensive income, net of tax of ($16) million and ($62) million, respectively

102

Less: treasury stock, at cost; 1,049,382 and 877,205 common shares as of September 30, 2010 and December 31, 2009, respectively

(19)

(15)

Total Chesapeake Stockholders' Equity

15,273

11,444

Noncontrolling interest

897

Total Equity

15,273

12,341

TOTAL LIABILITIES AND EQUITY

34,333

29,914

5.75% Cumulative Convertible Preferred Stock

5.75% cumulative convertible preferred stock (series A)

1,500

4.50% cumulative convertible preferred stock

1,100

5.00% cumulative convertible preferred stock (series 2005B)

256

5.00% cumulative convertible preferred stock (series 2005)

$ 209

209

$ 1

[1]	In the Current Quarter, we recorded a $16 million impairment of certain other equity investments.

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2010	Dec. 31, 2009
Statement [Line Items]
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	655,330,601	648,549,165
Accumulated other comprehensive income, tax	$ (16)	$ (62)
Treasury stock, shares	1,049,382	877,205
Preferred Stock
Statement [Line Items]
Preferred Stock, par value	$ 0.01	$ 0.01
Preferred Stock, shares authorized	20,000,000	20,000,000
5.75% Cumulative Convertible Preferred Stock
Statement [Line Items]
Preferred stock, shares issued	1,500,000	0
Preferred stock, shares outstanding	1,500,000	0
Preferred stock amount entitled in liquidation	$ 1,500	$ 0
5.75% cumulative convertible preferred stock (series A)
Statement [Line Items]
Preferred stock, shares issued	1,100,000	0
Preferred stock, shares outstanding	1,100,000	0
Preferred stock amount entitled in liquidation	$ 1,100	$ 0
4.50% cumulative convertible preferred stock
Statement [Line Items]
Preferred stock, shares issued	2,558,900	2,558,900
Preferred stock, shares outstanding	2,558,900	2,558,900
Preferred stock amount entitled in liquidation	$ 256	$ 256
5.00% cumulative convertible preferred stock (series 2005B)
Statement [Line Items]
Preferred stock, shares issued	2,095,615	2,095,615
Preferred stock, shares outstanding	2,095,615	2,095,615
Preferred stock amount entitled in liquidation	$ 209	$ 209
5.00% cumulative convertible preferred stock (series 2005)
Statement [Line Items]
Preferred stock, shares issued	0	5,000
Preferred stock, shares outstanding	0	5,000
Preferred stock amount entitled in liquidation	$ 0	$ 1

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
REVENUES:
Natural gas and oil sales	$ 1,639	$ 1,187	$ 4,698	$ 3,681
Marketing, gathering and compression sales	883	575	2,520	1,660
Service operations revenue	59	49	173	139
Total Revenues	2,581	1,811	7,391	5,480
OPERATING COSTS:
Production expenses	231	218	652	670
Production taxes	34	25	119	71
General and administrative expenses	125	95	340	259
Marketing, gathering and compression expenses	851	546	2,429	1,569
Service operations expense	52	49	154	136
Natural gas and oil depreciation, depletion and amortization	378	295	1,025	1,037
Depreciation and amortization of other assets	56	62	159	177
Impairment or loss on sale of other property and equipment	37	124	37	159
Impairment of natural gas and oil properties				9,600
Restructuring costs			34	34
Total Operating Costs	1,764	1,414	4,915	13,712
INCOME (LOSS) FROM OPERATIONS	817	397	2,476	(8,232)
OTHER INCOME (EXPENSE):
Interest (expense) income	(3)	(43)	(12)	(52)
Loss on redemptions or exchanges of Chesapeake debt	(59)	(17)	(130)	(19)
Impairment of investments	(16)		(16)	(162)
Other income (expense)	168	(30)	202	(25)
Total Other Income (Expense)	90	(90)	44	(258)
INCOME (LOSS) BEFORE INCOME TAXES	907	307	2,520	(8,490)
INCOME TAX EXPENSE (BENEFIT):
Current income taxes	(1)		4	1
Deferred income taxes	350	115	966	(3,185)
Total Income Tax Expense (Benefit)	349	115	970	(3,184)
NET INCOME (LOSS)	558	192	1,550	(5,306)
Net (income) loss attributable to noncontrolling interest
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	558	192	1,550	(5,306)
Preferred stock dividends	(43)	(6)	(68)	(18)
NET INCOME (LOSS) AVAILABLE TO CHESAPEAKE COMMON STOCKHOLDERS	$ 515	$ 186	$ 1,482	$ (5,324)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$ 0.81	$ 0.30	$ 2.35	$ (8.78)
Diluted	0.75	0.30	2.24	(8.78)
CASH DIVIDEND DECLARED PER COMMON SHARE	$ 0.075	$ 0.075	$ 0.225	$ 0.225
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING
Basic	632	619	631	606
Diluted	744	626	692	606

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$ 1,550	$ (5,306)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	1,184	1,214
Deferred income tax expense (benefit)	966	(3,185)
Unrealized (gains) losses on derivatives	(45)	295
Realized gains on financing derivatives	(436)	(53)
Stock-based compensation	111	104
Accretion of discount on contingent convertible notes	58	60
(Gain) loss on equity investments	(120)	32
Loss on redemptions or exchanges of Chesapeake debt	29	19
Impairment or loss on sale of other property and equipment	37	159
Impairment of natural gas and oil properties		9,600
Impairment of investments	16	162
Restructuring costs		12
Other	12	8
Change in assets and liabilities	609	10
Cash provided by operating activities	3,971	3,131
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of natural gas and oil properties	(3,718)	(2,790)
Acquisitions of natural gas and oil proved and unproved properties	(4,217)	(1,348)
Additions to other property and equipment	(968)	(1,362)
Proceeds from divestitures of proved and unproved properties	3,107	1,729
Proceeds from sales of other assets	328	157
Additions to investments	(113)	(40)
Deposits on acquisitions	(95)
Other	11
Cash used in investing activities	(5,665)	(3,654)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	10,458	5,563
Payments on credit facilities borrowings	(9,863)	(7,866)
Proceeds from issuance of preferred stock, net of offering costs	2,562
Proceeds from issuance of senior notes, net of offering costs	1,967	1,346
Cash paid to redeem Chesapeake debt	(3,434)
Cash paid for common stock dividends	(142)	(135)
Cash paid for preferred stock dividends	(49)	(18)
Realized gains on financing derivatives	436	19
Proceeds from sale of noncontrolling interest in midstream joint venture		588
Proceeds from sale/leaseback of real estate surface assets		145
Proceeds from mortgage of building		54
Net increase (decrease) in outstanding payments in excess of cash balance	116	(305)
Other	(55)	(97)
Cash provided by (used in) financing activities	1,996	(706)
Net increase (decrease) in cash and cash equivalents	302	(1,229)
Cash and cash equivalents, beginning of period	307	1,749
Cash and cash equivalents, end of period	609	520
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION OF CASH PAYMENTS FOR:
Interest, net of capitalized interest	103	111
Income taxes, net of refunds received	$ (291)	$ 176

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Dividends payable on common and preferred stock	$ 90	$ 52
Natural gas and oil properties adjusted as a result of an increase (decrease) in accrued exploration and development costs	116	(72)
Other property and equipment adjusted as a result of an increase (decrease) in accrued costs	(8)	(31)
Non-cash asset additions (reductions) to natural gas and oil properties for asset retirement obligations	(2)	(3)
Non-cash asset additions (reductions) to natural gas gathering systems for asset retirement obligations	$ 2	$ 3
Common stock issued		24,822,832
5.00% cumulative convertible preferred stock (series 2005)
Statement [Line Items]
Cumulative Convertible Preferred Stock	5,000
Shares of common stock pursuant to mandatory conversion rights	20,774
6.25% mandatory convertible preferred stock
Statement [Line Items]
Cumulative Convertible Preferred Stock		143,768
Shares of common stock pursuant to mandatory conversion rights		1,239,538
4.125% Cumulative Convertible Preferred Stock
Statement [Line Items]
Cumulative Convertible Preferred Stock		3,033
Shares of common stock pursuant to mandatory conversion rights		182,887
Oil and Gas Proved and Unproved Properties
Statement [Line Items]
Common stock issued		24,822,832
Common stock value		$ 429
2.25% contingent convertible senior notes due 2038
Statement [Line Items]
Aggregate principal amount	$ 11	$ 238
Cumulative Convertible Preferred Stock	298,500	6,707,321

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Balance, beginning of period			$ 12,341
Net income (loss)	$ 558	$ 192	1,550	$ (5,306)
Cumulative effect of accounting change, net of income taxes of $89 million			142
Balance, end of period	15,273	12,829	15,273	12,829
PREFERRED STOCK:
Statement [Line Items]
Balance, beginning of period			466	505
Conversion or exchange of 5,000 and 146,801 shares of preferred stock for common stock			(1)	(39)
Balance, end of period	3,065	466	3,065	466
PREFERRED STOCK: \| 5.75% Cumulative Convertible Preferred Stock
Statement [Line Items]
Issuance of preferred stock			1,500
PREFERRED STOCK: \| 5.75% (Series A) Cumulative Convertible Preferred Stock
Statement [Line Items]
Issuance of preferred stock			1,100
COMMON STOCK:
Statement [Line Items]
Balance, beginning of period			6	6
Stock-based compensation			1
Balance, end of period	7	6	7	6
PAID-IN CAPITAL:
Statement [Line Items]
Balance, beginning of period			12,146	11,680
Issuance of 0 and 24,822,832 shares of common stock for the purchase of proved and unproved properties				420
Conversion or exchange of 5,000 and 146,801 shares of preferred stock for common stock			9	203
Stock-based compensation			174	143
Offering expenses			(39)
Dividends on common stock			(95)	(138)
Dividends on preferred stock			(44)	(17)
Allocation of joint venture capital to Global Infrastructure Partners				(263)
Tax benefit (reduction in tax benefit) from exercise of stock-based compensation			(13)	(47)
Balance, end of period	12,138	11,981	12,138	11,981
RETAINED EARNINGS (DEFICIT):
Statement [Line Items]
Balance, beginning of period			(1,261)	4,569
Net income (loss)			1,550	(5,306)
Cumulative effect of accounting change, net of income taxes of $89 million			(142)
Dividends on common stock			(47)
Dividends on preferred stock			(43)
Balance, end of period	57	(737)	57	(737)
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Statement [Line Items]
Balance, beginning of period			102	267
Hedging activity			(70)	(60)
Investment activity			(7)	67
Balance, end of period	25	274	25	274
TREASURY STOCK - COMMON:
Statement [Line Items]
Balance, beginning of period			(15)	(10)
Purchase of 179,140 and 115,430 shares for company benefit plans			(4)	(2)
Release of 6,963 and 6,152 shares for company benefit plans
Balance, end of period	(19)	(12)	(19)	(12)
TOTAL CHESAPEAKE STOCKHOLDERS' EQUITY
Statement [Line Items]
Balance, end of period	$ 15,273	11,978	15,273	11,978
NONCONTROLLING INTEREST:
Statement [Line Items]
Balance, beginning of period			897	588
Deconsolidation of investment in CMP			$ (897)	263
Balance, end of period		$ 851		$ 851

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Common stock issued for purchase of proved and unproved properties		24,822,832
PREFERRED STOCK:
Statement [Line Items]
Conversion or exchange of convertible notes and preferred stock for shares of common stock, shares	5,000	146,801
COMMON STOCK:
Statement [Line Items]
Common stock issued for purchase of proved and unproved properties	0	24,822,832
Conversion or exchange of convertible notes and preferred stock for shares of common stock, shares	319,274	8,129,746
PAID-IN CAPITAL:
Statement [Line Items]
Common stock issued for purchase of proved and unproved properties	0	24,822,832
Conversion or exchange of convertible notes and preferred stock for shares of common stock, shares	319,274	8,129,746
RETAINED EARNINGS (DEFICIT):
Statement [Line Items]
Cumulative effect of accounting change, income taxes	$ 89
TREASURY STOCK - COMMON:
Statement [Line Items]
Shares of treasury stock purchase for company benefit plans	123,579	115,430
Shares of treasury stock released for company benefit plans	6,818	6,152
5.75% Cumulative Convertible Preferred Stock
Statement [Line Items]
Issuance of preferred stock, shares	1,500,000
5.75% Cumulative Convertible Preferred Stock \| PREFERRED STOCK:
Statement [Line Items]
Issuance of preferred stock, shares	1,500,000	0
5.75% (Series A) Cumulative Convertible Preferred Stock
Statement [Line Items]
Issuance of preferred stock, shares	1,100,000
5.75% (Series A) Cumulative Convertible Preferred Stock \| PREFERRED STOCK:
Statement [Line Items]
Issuance of preferred stock, shares	1,100,000	0

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Net income (loss)	$ 558	$ 192	$ 1,550	$ (5,306)
Other comprehensive income (loss), net of income tax:
Change in fair value of derivative instruments, net of income taxes of $39 million, $38 million, $153 million and $372 million	65	62	251	609
Reclassification of gain on settled contracts, net of income taxes of ($68) million, ($144) million, ($203) million and ($377) million	(112)	(236)	(333)	(617)
Ineffective portion of derivatives qualifying for cash flow hedge accounting, net of income taxes of ($2) million, $2 million, $8 million and ($31) million	(3)	5	12	(52)
Unrealized (gain) loss on marketable securities, net of income taxes of $1 million, $4 million, ($4) million and $14 million	1	6	(7)	24
Reclassification of loss on investments, net of income taxes of $0, $0, $0 and $26 million				43
Comprehensive income (loss)	509	29	1,473	(5,299)
(Income) loss attributable to noncontrolling interest
Comprehensive income (loss) available to Chesapeake	$ 509	$ 29	$ 1,473	$ (5,299)

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Change in fair value of derivative instruments, income taxes	$ 39	$ 38	$ 153	$ 372
Reclassification of gain on settled contracts, income taxes	(68)	(144)	(203)	(377)
Ineffective portion of derivatives qualifying for cash flow hedge accounting, income taxes	(2)	2	8	(31)
Unrealized (gain) loss on marketable securities, income taxes	1	4	(4)	14
Reclassification of loss on investments, income taxes	$ 0	$ 0	$ 0	$ 26

Basis of Presentation and Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2010

Basis of Presentation and Summary of Significant Accounting Policies

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 (SEC). Chesapeake’s annual report on Form 10-K for the year ended December 31, 2009 (2009 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, 2010 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, 2010 (the “Current Quarter” and the “Current Period”, respectively) and the three and nine months ended September 30, 2009 (the “Prior Quarter” and the “Prior Period”, respectively).

Cumulative Effect of Accounting Change

Effective January 1, 2010, in accordance with new authoritative guidance for variable interest entities, we ceased consolidating our 50/50 midstream joint venture with Global Infrastructure Partners within our financial statements and began to account for the joint venture under the equity method (see Note 9). Adoption of this new guidance resulted in an after-tax cumulative effect charge to retained earnings of $142 million, which is reflected in our condensed consolidated statement of equity for the Current Period. This charge reflects the difference between the carrying value of our initial investment in the joint venture, which was recorded at carryover basis as an entity under common control, and the fair value of our equity in the joint venture as of the formation date.

Critical Accounting Policies

We consider accounting policies related to hedging, natural gas and oil properties and income taxes to be critical policies. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2009 Form 10-K.

Financial Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2010

Financial Instruments and Hedging Activities

2.	Financial Instruments and Hedging Activities

Natural Gas and Oil Derivatives

Our results of operations and operating cash flows are impacted by changes in market prices for natural gas and oil. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. These instruments allow us to predict with greater certainty the effective natural gas and oil 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 our risk management objectives. As of September 30, 2010 and December 31, 2009, our natural gas and oil derivative instruments were comprised of the following types of instruments:

•

Swaps: Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity.

•

Collars: These instruments 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 put and the call strike price, no payments are due from either party. Three-way collars include an additional put option in exchange for a more favorable strike price on the collar. This eliminates the counterparty’s downside exposure below the second put option.

•

Call options: Chesapeake sells call options in exchange for a premium from the counterparty. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party.

•

Put options: Chesapeake receives a premium from the counterparty in exchange for the sale of a put option. At the time of settlement, if the market price falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall, and if the market price settles above the fixed price of the put option, no payment is due from either party.

•

Knockout swaps: Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout prices.

•

Basis protection swaps: These instruments are arrangements that guarantee a price differential to NYMEX for natural gas from a specified delivery point. For non-Appalachian Basin basis protection swaps, which typically have negative differentials to NYMEX, 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 Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

All of our derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty.

The estimated fair values of our natural gas and oil derivative instruments as of September 30, 2010 and December 31, 2009 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.


	September 30, 2010						December 31, 2009
	Volume			Fair Value			Volume			Fair Value
Natural gas (bbtu):				($ in millions)						($ in millions)
Fixed-price swaps		616,190		$	1,378			492,053		$	662
Fixed-price collars		10,980			37			74,240			92
Call options		1,333,619			(481	)		996,750			(541	)
Put options		(58,580	)		(75	)		(69,620	)		(50	)
Fixed-price knockout swaps		28,530			5			38,370			17
Basis protection swaps		154,502			(52	)		125,469			(50	)

Total natural gas		2,085,241			812			1,657,262			130


Oil (mbbl):
Fixed-price swaps		8,044			(28	)		5,475			3
Call options		42,259			(622	)		14,975			(144	)
Fixed-price knockout swaps		3,023			35			6,572			32

Total oil		53,326			(615	)		27,022			(109	)


Total estimated fair value				$	197					$	21

Pursuant to accounting guidance for derivatives and hedging, certain derivatives qualify for designation as cash flow hedges. Following this guidance, 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 accumulated other comprehensive income until the hedged item is recognized in earnings as the physical transactions being hedged occur. Any change in fair value resulting from ineffectiveness is currently recognized in natural gas and oil sales as unrealized gains (losses). Changes in the fair value of non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the condensed consolidated statements of operations as unrealized gains (losses) within natural gas and oil sales. Realized gains (losses) are included in natural gas and oil sales in the month of related production.

The components of natural gas and oil sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2010		2009			2010			2009
	($ in millions)
Natural gas and oil sales	$	1,074	$	785		$	3,243		$	2,280
Realized gains (losses) on natural gas and oil derivatives		512		687			1,484			1,802
Unrealized gains (losses) on non-qualifying natural gas and oil derivatives		48		(278	)		(9	)		(484	)
Unrealized gains (losses) on ineffectiveness of cash flow hedges		5		(7	)		(20	)		83

Total natural gas and oil sales	$	1,639	$	1,187		$	4,698		$	3,681

Based upon the market prices at September 30, 2010, we expect to transfer approximately $188 million (net of income taxes) of the gain included in the accumulated other comprehensive income balance to net income (loss) during the next 12 months in the related month of production. All transactions hedged as of September 30, 2010 are expected to mature by December 31, 2022.

We have a multi-counterparty hedge facility with 13 counterparties that have committed to provide approximately 5.6 tcfe of trading capacity and an aggregate mark-to-market capacity of $15.0 billion under the terms of the facility. As of September 30, 2010, we had hedged a total of 2.3 tcfe under the facility. The multi-counterparty facility allows us to enter into cash-settled natural gas and oil price and basis hedges with the counterparties. Our obligations under the multi-counterparty facility are secured by natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times, and guarantees by certain subsidiaries that also guarantee our corporate revolving bank credit facility and indentures. The counterparties’ obligations under the facility must be secured by cash or short-term U.S. Treasury instruments to the extent that any mark-to-market amounts they owe to Chesapeake exceed defined thresholds. The maximum volume-based trading capacity under the facility is governed by the expected production of the pledged reserve collateral, and volume-based trading limits are applied separately to price and basis hedges. In addition, there are volume-based sub-limits for natural gas and oil hedges. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain collateral coverage and other requirements are met. The facility does not have a maturity date. Counterparties to the agreement have the right to cease trading with the company on a prospective basis as long as obligations associated with any existing trades in the facility continue to be satisfied in accordance with the terms of the agreement.

Interest Rate Derivatives

To mitigate our exposure to volatility in interest rates related to our senior notes and bank credit facilities, we enter into interest rate derivatives. As of September 30, 2010 and December 31, 2009, our interest rate derivative instruments were comprised of the following types of instruments:

•

Swaps: Chesapeake enters into fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes. We enter into floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our bank credit facilities borrowings.

•

Collars: These instruments contain a fixed floor rate (floor) and a ceiling rate (cap). If the floating rate is above the cap, we have a net receivable from the counterparty and if the floating rate is below the floor, we have a net payable to the counterparty. If the floating rate is between the floor and the cap, there is no payment due from either party. Collars are used to manage our interest rate exposure related to our bank credit facilities borrowings.

•

Call options: Occasionally we sell call options for a premium when we think it is more likely that the option will expire unexercised. The option allows the counterparty to terminate an open swap on a specific date.

•

Swaptions: Occasionally we sell an option to a counterparty for a premium which allows the counterparty to enter into a swap with us on a specific date.

The notional amount of debt hedged and the estimated fair value of our interest rate derivatives outstanding as of September 30, 2010 and December 31, 2009 are provided below.


	September 30, 2010					December 31, 2009
	Notional Amount		Fair Value			Notional Amount		Fair Value
	($ in millions)
Interest rate:
Swaps	$	1,300	$	(13	)	$	2,925	$	(113	)
Collars		—		—			250		(6	)
Call options		250		(26	)		250		(2	)
Swaptions		250		—			500		(11	)

Totals	$	1,800	$	(39	)	$	3,925	$	(132	)

For interest rate derivative instruments designated as fair value hedges, the fair values of the hedges are recorded on the condensed consolidated balance sheets as assets or liabilities, with corresponding offsetting adjustments to the debt’s carrying value. Changes in the fair value of non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are currently reported in the condensed consolidated statements of operations as unrealized gains (losses) within interest expense.

Realized gains or losses from interest rate derivative transactions are reflected as adjustments to interest expense in the condensed consolidated statements of operations. The components of interest expense for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	($ in millions)

Interest expense on senior notes	$	167		$	195		$	550		$	572
Interest expense on credit facilities		18			18			42			47
Capitalized interest		(185	)		(153	)		(525	)		(467	)
Realized (gains) losses on interest rate derivatives		(2	)		(7	)		(6	)		(19	)
Unrealized (gains) losses on interest rate derivatives		2			(20	)		(75	)		(106	)
Amortization of loan discount and other		3			10			26			25

Total interest expense	$	3		$	43		$	12		$	52

Our qualifying interest rate swaps are considered 100% effective and therefore no ineffectiveness was recorded for the periods presented above.

Gains and losses related to terminated qualifying interest rate derivative transactions will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next ten years, we will recognize $36 million in gains related to such transactions.

Foreign Currency Derivatives

On December 6, 2006, we issued €600 million of 6.25% Euro-denominated Senior Notes due 2017. Concurrent with the issuance of the euro-denominated senior notes, we entered into a cross currency swap to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. Under the terms of the cross currency swap, on each semi-annual interest payment date, the counterparties pay Chesapeake €19 million and Chesapeake pays the counterparties $30 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay Chesapeake €600 million and Chesapeake will pay the counterparties $800 million. The terms of the cross currency swap were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Through the cross currency swap, we have eliminated any potential variability in Chesapeake’s expected cash flows related to changes in foreign exchange rates and therefore the swap qualifies as a cash flow hedge. The fair value of the cross currency swap is recorded on the condensed consolidated balance sheet as a liability of $35 million at September 30, 2010. The euro-denominated debt in long-term debt has been adjusted to $816 million at September 30, 2010 using an exchange rate of $1.3601 to €1.00.

Additional Disclosures Regarding Derivative Instruments and Hedging Activities

In accordance with accounting guidance for derivatives and hedging, to the extent that a legal right of set-off exists, Chesapeake nets the value of its derivative arrangements with the same counterparty in the accompanying condensed consolidated balance sheets. Derivative instruments reflected as current in the condensed consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the balance sheet date. The derivative settlement amounts are not due until the month in which the related underlying hedged transaction occurs. Cash settlements of our derivative arrangements are generally classified as operating cash flows unless the derivative contains a significant financing element at contract inception, in which case, all cash settlements are classified as financing cash flows in the accompanying condensed consolidated statements of cash flows.

The following table sets forth the fair value of each classification of derivative instrument as of September 30, 2010 and December 31, 2009, on a gross basis without regard to same-counterparty netting:


		Fair Value
	Balance Sheet Location	September 30, 2010			December 31, 2009
		($ in millions)
Asset Derivatives:
Derivatives designated as hedging instruments:
Commodity contracts	Short-term derivative instruments	$	438		$	417
Commodity contracts	Long-term derivative instruments		41			36
Foreign currency contracts	Long-term derivative instruments		—			43

Total			479			496


Derivatives not designated as hedging instruments:
Commodity contracts	Short-term derivative instruments		794			318
Commodity contracts	Long-term derivative instruments		367			66
Interest rate contracts	Long-term derivative instruments		29			—

Total			1,190			384


Liability Derivatives:
Derivatives designated as hedging instruments:
Commodity contracts	Short-term derivative instruments		—			(1	)
Interest rate contracts	Long-term derivative instruments		—			(11	)
Foreign currency contracts	Long-term derivative instruments		(35	)		—

Total			(35	)		(12	)


Derivatives not designated as hedging instruments:
Commodity contracts	Short-term derivative instruments		(145	)		(42	)
Commodity contracts	Long-term derivative instruments		(1,298	)		(768	)
Interest rate contracts	Short-term derivative instruments		(26	)		(27	)
Interest rate contracts	Long-term derivative instruments		(42	)		(94	)

Total			(1,511	)		(931	)


Total derivative instruments		$	123		$	(63	)

A consolidated summary of the effect of derivative instruments on the condensed consolidated statements of operations for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is provided below, separating fair value, cash flow and non-qualifying derivatives.

The following table presents the gain (loss) recognized in net income (loss) for instruments designated as fair value derivatives:


		Three Months Ended September 30,				Nine Months Ended September 30,
Fair Value Derivatives	Location of Gain (Loss)	2010		2009		2010		2009
		($ in millions)

Interest rate contracts	Interest expense^(a)	$	3	$	13	$	16	$	31

(a)	Interest expense on items hedged during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period was $0, $33 million, $15 million and $66 million, respectively, which is included in interest expense on the condensed consolidated statements of operations.

The following table presents the pre-tax gain (loss) recognized in, and reclassified from, accumulated other comprehensive income (AOCI) and recognized in net income (loss), including any hedge ineffectiveness, for derivative instruments designated as cash flow derivatives:


		Three Months Ended September 30,					Nine Months Ended September 30,
Cash Flow Derivatives	Location of Gain (Loss)	2010		2009			2010			2009
		($ in millions)

Gain (Loss) Recognized in AOCI (Effective Portion)
Commodity contracts	AOCI	$	94	$	107		$	458		$	819
Foreign exchange contracts	AOCI		5		1			(34	)		79

		$	99	$	108		$	424		$	898


Gain (Loss) Reclassified from AOCI (Effective Portion)
Commodity contracts	Natural gas and oil sales	$	179	$	381		$	535		$	994

		$	179	$	381		$	535		$	994


Gain (Loss) Recognized (Ineffective Portion and Amount Excluded from Effectiveness Testing)^(a)
Commodity contracts	Natural gas and oil sales	$	2	$	(7	)	$	(95	)	$	83

		$	2	$	(7	)	$	(95	)	$	83

(a)

In the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, the amount of gain (loss) recognized in net income (loss) represents $5 million, ($7) million, ($20) million and $83 million related to the ineffective portion of our cash flow derivatives and ($3) million, $0, ($75) million and $0, respectively, related to the amount excluded from the assessment of hedge effectiveness.

The following table presents the gain (loss) recognized in net income (loss) for instruments not qualifying as cash flow or fair value derivatives:


		Three Months Ended September 30,					Nine Months Ended September 30,
Non-Qualifying Derivatives	Location of Gain (Loss)	2010			2009		2010		2009
		($ in millions)

Commodity contracts	Natural gas and oil sales	$	384		$	28	$	1,015	$	324
Interest rate contracts	Interest expense		(3	)		14		65		94

	Total	$	381		$	42	$	1,080	$	418

Concentration of Credit Risk

A significant portion of our credit risk is concentrated in derivative instruments that enable us to hedge a portion of our exposure to natural gas and oil prices, interest rate volatility and exchange rate exposure. These arrangements expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. On September 30, 2010, our derivative instruments were spread among 14 counterparties. Additionally, our multi-counterparty secured hedging facility described previously includes 13 of our counterparties which are required to secure their natural gas and oil hedging obligations in excess of defined thresholds. We use this facility for all of our commodity hedging.

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 natural gas and oil 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 monitor the creditworthiness of all our counterparties. 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. During the Current Quarter, the Prior Quarter and the Current Period, we recognized nominal amounts of bad debt expense related to potentially uncollectible receivables. During the Prior Period, we recognized $13 million of bad debt expense related to potentially uncollectible receivables.

Contingencies and Commitments

9 Months Ended

Sep. 30, 2010

Contingencies and Commitments

3.	Contingencies and Commitments

Litigation

On February 25, 2009, a putative class action was filed in the U.S. District Court for the Southern District of New York against the company and certain of its officers and directors along with certain underwriters of the company’s July 2008 common stock offering. Following the appointment of a lead plaintiff and counsel, the plaintiff filed an amended complaint on September 11, 2009 alleging that the registration statement for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. The action was transferred to the U.S. District Court for the Western District of Oklahoma on October 13, 2009. The defendants’ motion to dismiss was denied on September 2, 2010. A derivative action was also filed in the District Court of Oklahoma County, Oklahoma on March 10, 2009 against the company’s directors and certain of its officers alleging breaches of fiduciary duties relating to the disclosure matters alleged in the securities case. The derivative action is stayed pursuant to stipulation.

On March 26, 2009, a shareholder filed a petition in the District Court of Oklahoma County, Oklahoma seeking to compel inspection of company books and records relating to compensation of the company’s CEO. On August 20, 2009, the court denied the inspection demand, dismissed the petition and entered judgment in favor of Chesapeake. The shareholder is appealing the court’s ruling in the Court of Civil Appeals of the State of Oklahoma.

Three derivative actions were filed in the District Court of Oklahoma County, Oklahoma on April 28, May 7, and May 20, 2009 against the company’s directors alleging breaches of fiduciary duties relating to compensation of the company’s CEO and alleged insider trading, among other things, and seeking unspecified damages, equitable relief and disgorgement. These three derivative actions were consolidated and a Consolidated Derivative Shareholder Petition was filed on June 23, 2009. Chesapeake is named as a nominal defendant. Chesapeake’s motion to dismiss was granted on February 28, 2010 and plaintiffs were given leave to amend. Plaintiffs chose not to amend and on April 9, 2010, at plaintiffs’ request, the court entered an order certifying that the February 28, 2010 dismissal was a final, appealable order. Plaintiffs are appealing the dismissal in the Oklahoma Court of Civil Appeals.

We are currently unable to assess the probability of loss or estimate a range of potential loss associated with the foregoing cases. It is inherently difficult to predict the outcome of any litigation, and these proceedings are at an early stage.

Chesapeake is also involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, claims for underpayment of royalties, property damage claims and contract actions. With regard to the latter, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their oil and natural gas interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The company has satisfactorily resolved most of these suits but a few are pending, either at the trial court or appellate level. The company believes that it has substantial defenses to the claims made in all these cases.

The company records an associated liability when a loss is probable and the amount is reasonably estimable. Although the outcome of litigation cannot be predicted with certainty, management is of the opinion that no pending or threatened lawsuit or dispute incidental to its business operations is likely to have a material adverse effect on the company’s consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

Environmental Risk

Due to the nature of the natural gas and oil 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, 2010.

Rig Leases

In a series of transactions since 2006, our drilling subsidiaries have sold 85 drilling rigs and related equipment for $704 million and entered into a master lease agreement under which we agreed to lease the rigs from the buyer for initial terms of seven to ten years for lease payments of approximately $97 million annually. The lease obligations are guaranteed by Chesapeake and certain of its subsidiaries. These transactions were recorded as sales and operating leasebacks and any related gain or loss is being amortized to service operations expense over the lease term. Under the rig leases, we can exercise an early purchase option after five and one-half to seven years or on the expiration of the lease term for a purchase price equal to the then fair market value of the rigs. Additionally, we have the option to renew the rig lease for a negotiated renewal term at a periodic lease payment equal to the fair market rental value of the rigs as determined at the time of renewal. Commitments related to rig lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2010, the minimum aggregate undiscounted future rig lease payments were approximately $478 million.

Compressor Leases

Through various transactions since 2007, our compression subsidiary has sold 2,234 compressors, a significant portion of its compressor fleet, for $517 million and entered into a master lease agreement. The term of the agreement varies by buyer ranging from four to ten years for aggregate lease payments of approximately $77 million annually. The lease obligations are guaranteed by Chesapeake and certain of its subsidiaries. These transactions were recorded as sales and operating leasebacks and any related gain or loss is being amortized to marketing, gathering and compression expenses over the lease term. Under the leases, we can exercise an early purchase option or we can purchase the compressors at expiration of the lease for the fair market value at the time. In addition, we have the option to renew the lease for negotiated new terms at the expiration of the lease. Commitments related to compressor lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2010, the minimum aggregate undiscounted future compressor lease payments were approximately $441 million.

Transportation Contracts

Chesapeake has various firm pipeline transportation service agreements with expiration dates ranging from 2010 to 2099. These commitments are not recorded in the accompanying condensed consolidated balance sheets. Under the terms of these contracts, we are obligated to pay demand charges as set forth in the transporter’s Federal Energy Regulatory Commission (FERC) gas tariff. In exchange, the company receives rights to flow natural gas production through pipelines located in highly competitive markets. The aggregate undiscounted amounts of such required demand payments are presented below:


	September 30, 2010
	($ in millions)

2010		$	82
2011			378
2012			378
2013			364
2014			344
2015 – 2099			2,449

Total		$	3,995

Drilling and Rig Purchase Contracts

Currently, Chesapeake has contracts with various drilling contractors to lease approximately 46 rigs with terms of four months to four years. These commitments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2010, the aggregate undiscounted drilling rig commitment was approximately $204 million.

In September 2010, Chesapeake entered into a contract to purchase 7 rigs for $85 million. As of September 30, 2010, we had made a $9 million deposit and have a remaining commitment of $76 million. The transaction is expected to close in December 2010.

Natural Gas and Oil Purchase Obligations

Our marketing segment regularly commits to purchase natural gas from other owners in our properties and such commitments typically are short-term in nature. We have also committed to purchase any natural gas and oil associated with certain volumetric production payment transactions. The purchase commitments are based on market prices at the time of production, and the purchased natural gas and oil is resold.

Minimum Volume Commitments

We are a party to a gas gathering agreement with a subsidiary of Chesapeake Midstream Partners, L.P. (see Note 9), pursuant to which we have committed to deliver specified minimum volumes of natural gas from our Barnett Shale production annually through December 31, 2018 and for the six-month period ending June 30, 2019. At the end of the term or annually, Chesapeake will be invoiced for any shortfalls in such volume commitments at the rate specified in the agreement. Volume commitments remaining as of September 30, 2010 were as follows:


	Bcf

2010		129
2011		313
2012		325
2013		338
2014		351
After 2014		1,686

Total		3,142

In addition, Chesapeake has entered into commitments to deliver approximately 530 bcf through September 2021 to third-party midstream companies.

Net Acreage Maintenance Commitments

Under the terms of our joint development agreements with our joint venture partners, Statoil and Total (see Note 8), we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas.

Other Commitments

As of September 30, 2010, we had made commitments to acquire additional leasehold in various transactions during the next twelve months for approximately $1.7 billion, including the acquisition of a significant additional position in the Appalachian Basin from privately-held Anschutz Corporation which is expected to close in November 2010.

Net Income Per Share

9 Months Ended

Sep. 30, 2010

Net Income Per Share

4.	Net Income Per Share

Accounting guidance for earnings per share (EPS) requires presentation of “basic” and “diluted” earnings per share on the face of the statements of operations for all entities with complex capital structures as well as a reconciliation of the numerator and denominator of the basic and diluted EPS computations.

For the Current Quarter and the Current Period, no securities were antidilutive in the calculation of diluted EPS. The following securities and associated adjustments to net income comprised of dividends and losses on conversions/exchanges were not included in the calculation of diluted EPS for the Prior Quarter and the Prior Period, as the effect was antidilutive.


	Shares		Net Income Adjustments
	(in millions)		($ in millions)
Three Months Ended September 30, 2009:
Common stock equivalent of our preferred stock outstanding:
5.00% cumulative convertible preferred stock (series 2005B)		5	$	3
4.50% cumulative convertible preferred stock		6	$	3

Nine Months Ended September 30, 2009:
Common stock equivalent of our preferred stock outstanding:
5.00% cumulative convertible preferred stock (series 2005B)		5	$	8
4.50% cumulative convertible preferred stock		6	$	9
Common stock equivalent of our preferred stock outstanding prior to conversion:
6.25% mandatory convertible preferred stock		1	$	1

Outstanding stock options		1	$	—
Unvested restricted stock		5	$	—

For the Prior Period, as a result of the net loss to Chesapeake common stockholders, there was no difference between basic weighted average shares outstanding, which are used in computing basic EPS, and diluted weighted average shares, which are used in computing EPS assuming dilution.

A reconciliation of basic EPS and diluted EPS for the Current Quarter, the Prior Quarter and the Current Period is as follows:


	Income (Numerator)		Weighted Average Shares (Denominator)		Per Share Amount
	(in millions, except per share data)
Three Months Ended September 30, 2010:
Basic EPS	$	515		632	$	0.81


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 5.75% cumulative convertible preferred stock		21		56
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)		16		40
Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)		2		5
Common shares assumed issued for 4.50% cumulative convertible preferred stock		3		6
Outstanding stock options		—		1
Unvested restricted stock		—		4


Diluted EPS	$	557		744	$	0.75


Three Months Ended September 30, 2009:
Basic EPS	$	186		619	$	0.30


Effect of Dilutive Securities:
Outstanding stock options		—		1
Unvested restricted stock		—		6


Diluted EPS	$	186		626	$	0.30


Nine Months Ended September 30, 2010:
Basic EPS	$	1,482		631	$	2.35


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 5.75% cumulative convertible preferred stock		28		24
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)		23		20
Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)		8		5
Common shares assumed issued for 4.50% cumulative convertible preferred stock		9		6
Outstanding stock options		—		1
Unvested restricted stock		—		5


Diluted EPS	$	1,550		692	$	2.24

Stockholders' Equity, Restricted Stock and Stock Options

9 Months Ended

Sep. 30, 2010

Stockholders' Equity, Restricted Stock and Stock Options

5.	Stockholders’ Equity, Restricted Stock and Stock Options

Common Stock

The following is a summary of the changes in our common shares issued for the nine months ended September 30, 2010 and 2009:


	2010		2009
	(in thousands)

Shares issued at January 1		648,549		607,953
Restricted stock issuances (net of forfeitures)		6,108		3,940
Stock option exercises		354		429
Convertible note exchanges		299		6,707
Preferred stock conversions/exchanges		21		1,422
Common stock issued for the purchase of proved and unproved properties		—		24,823

Shares issued at September 30		655,331		645,274

In the Current Period, we privately exchanged approximately $11 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 298,500 shares of our common stock valued at approximately $9 million. Through these transactions, we were able to retire this debt for common stock valued at approximately 80% of the face value of the notes. In connection with accounting guidance for debt with conversion and other options, we are required to account for the liability and equity components of our convertible debt instruments separately. Of the $11 million principal amount of convertible notes exchanged in the Current Period, $7 million was allocated to the debt component of the notes and the remaining $4 million was allocated to the equity conversion feature of the notes and was recorded as an adjustment to paid-in-capital. The difference between the debt component and value of the common stock exchanged in these transactions resulted in a $2 million loss (including a nominal amount of deferred charges associated with the exchanges).

In the Prior Period, we privately exchanged approximately $238 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 6,707,321 shares of our common stock valued at approximately $164 million. Through these transactions, we were able to retire this debt for common stock valued at approximately 70% of the face value of the notes. Of the $238 million principal amount of convertible notes exchanged in the Prior Period, $148 million was allocated to the debt component of the notes and the remaining $90 million was allocated to the equity conversion feature of the notes and was recorded as an adjustment to paid-in-capital. The difference between the debt component and value of the common stock exchanged in these transactions resulted in a $19 million loss (including $3 million of deferred charges associated with the exchanges that were written off).

In the Prior Period, pursuant to an acquisition shelf registration statement, we issued 24,822,832 shares of common stock valued at $429 million for the purchase of proved and unproved properties.

Preferred Shares

The following is a summary of the changes in our preferred shares outstanding for the nine months ended September 30, 2010 and 2009:


	5.75%		5.75%(A)		4.50%		5.00% (2005B)		5.00% (2005)			6.25%			4.125%
	(in thousands)

Shares outstanding at January 1, 2010		—		—		2,559		2,096		5			—			—
Preferred stock issuances		1,500		1,100		—		—		—			—			—
Conversion of preferred into common stock		—		—		—		—		(5	)		—			—

Shares outstanding at September 30, 2010		1,500		1,100		2,559		2,096		—			—			—


Shares outstanding at January 1, 2009		—		—		2,559		2,096		5			144			3
Conversion of preferred into common stock		—		—		—		—		—			(144	)		(3	)

Shares outstanding at September 30, 2009		—		—		2,559		2,096		5			—			—

On May 17, 2010, we issued 600,000 shares of 5.75% Cumulative Convertible Non-Voting Preferred Stock, par value $0.01 per share and liquidation preference $1,000 per share, in a private placement for net proceeds of approximately $594 million. We also granted an option to such purchasers to place additional shares of the preferred stock. Upon the exercise of the placement option, we issued an additional 900,000 shares of 5.75% Cumulative Convertible Non-Voting Preferred Stock on June 18, 2010 for net proceeds of approximately $877 million.

On May 17, 2010, we issued 1,100,000 shares of 5.75% Cumulative Convertible Non-Voting Preferred Stock (Series A), par value $0.01 per share and liquidation preference $1,000 per share, in a private placement for net proceeds of approximately $1.091 billion.

On May 3, 2010, we converted all 5,000 shares of our outstanding 5.00% Cumulative Convertible Preferred Stock (Series 2005) into 20,774 shares of common stock pursuant to the company’s mandatory conversion rights.

On June 15, 2009, we converted all 143,768 shares of our outstanding 6.25% Mandatory Convertible Preferred Stock into 1,239,538 shares of common stock pursuant to the company's mandatory conversion rights.

On March 31, 2009, we converted all 3,033 shares of our outstanding 4.125% Cumulative Convertible Preferred Stock into 182,887 shares of common stock pursuant to the company’s mandatory conversion rights.

Dividends

Dividends declared on our common stock and preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings will exist after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, such payments constitute a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.

Stock-Based Compensation

Chesapeake’s stock-based compensation programs consist of restricted stock issued to employees and non-employee directors. To the extent compensation cost relates to employees directly involved in natural gas and oil exploration and development activities, such amounts are capitalized to natural gas and oil properties. Amounts not capitalized are recognized as general and administrative expenses, production expenses, marketing, gathering and compression expenses, service operations expense or restructuring costs. We recorded the following stock-based compensation during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	($ in millions)

Natural gas and oil properties	$	30	$	27	$	95	$	85
General and administrative expenses		21		22		63		60
Production expenses		9		8		27		26
Marketing, gathering and compression expenses		5		4		13		12
Service operations expense		2		2		7		6
Restructuring costs		—		—		—		9

Total	$	67	$	63	$	205	$	198

Restricted Stock. Chesapeake regularly issues shares of restricted common stock to employees and to non-employee directors. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. This value is amortized over the vesting period, which is generally four or five years from the date of grant for employees and three years for non-employee directors.

A summary of the changes in unvested shares of restricted stock for the nine months ended September 30, 2010 is presented below:


	Number of Unvested Restricted Shares			Weighted-Average Grant-Date Fair Value
	(in thousands)
Unvested shares as of January 1, 2010		19,225		$ 31.89
Granted		8,901		$ 24.21
Vested		(5,332	)	$ 32.49
Forfeited		(885	)	$ 30.49

Unvested shares as of September 30, 2010		21,909		$ 28.68

The aggregate intrinsic value of restricted stock vested during the Current Period was approximately $124 million based on the stock price at the time of vesting.

As of September 30, 2010, there was $425 million of total unrecognized compensation cost related to unvested restricted stock. The cost is expected to be recognized over a weighted average period of 2.4 years.

The vesting of certain restricted stock grants results in state and federal income tax benefits related to the difference between the market price of the common stock at the date of vesting and the date of grant. During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we recognized a reduction in tax benefits related to restricted stock of $14 million, $36 million, $15 million and $48 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes.

Stock Options. We granted stock options prior to 2006 under several stock compensation plans. Outstanding options expire ten years from the date of grant and vested over a four-year period. All stock options outstanding are fully vested and exercisable.

The following table provides information related to stock option activity for the nine months ended September 30, 2010:


	Number of Shares Underlying Options			Weighted Average Exercise Price Per Share		Weighted Average Contract Life in Years	Aggregate Intrinsic Value^(a)
	(in thousands)						($ in millions)

Outstanding at January 1, 2010		2,283		$	8.36	2.75	$ 40
Exercised		(366	)	$	6.15
Expired		—		$	—

Outstanding at September 30, 2010		1,917		$	8.78	2.22	$ 27


Exercisable at September 30, 2010		1,917		$	8.78	2.22	$ 27

(a)	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period we recognized excess tax benefits related to stock options of $1 million, $1 million, $2 million and $1 million which were recorded as adjustments to additional paid-in capital and deferred income taxes.

Debt

9 Months Ended

Sep. 30, 2010

Debt

Debt

Our total debt consisted of the following at September 30, 2010 and December 31, 2009:


	September 30, 2010			December 31, 2009
	($ in millions)

7.5% senior notes due 2013	$	—		$	364
7.625% senior notes due 2013		500			500
7.0% senior notes due 2014		—			300
7.5% senior notes due 2014		—			300
6.375% senior notes due 2015		—			600
9.5% senior notes due 2015		1,425			1,425
6.625% senior notes due 2016		—			600
6.875% senior notes due 2016		—			670
6.25% euro-denominated senior notes due 2017^(a)		816			860
6.5% senior notes due 2017		1,100			1,100
6.25% senior notes due 2018		—			600
6.875% senior notes due 2018		600			—
7.25% senior notes due 2018		800			800
6.625% senior notes due 2020		1,400			—
6.875% senior notes due 2020		500			500
2.75% contingent convertible senior notes due 2035^(b)		451			451
2.5% contingent convertible senior notes due 2037^(b)		1,378			1,378
2.25% contingent convertible senior notes due 2038^(b)		752			763
Corporate revolving bank credit facility		2,237			1,892
Midstream revolving bank credit facility		250			—
Midstream joint venture revolving bank credit facility^(c)		—			44
Discount on senior notes^(d)		(800	)		(921	)
Interest rate derivatives^(e)		36			69

Total notes payable and long-term debt	$	11,445		$	12,295

(a)	The principal amount shown is based on the dollar/euro exchange rate of $1.3601 to €1.00 and $1.4332 to €1.00 as of September 30, 2010 and December 31, 2009, respectively. See Note 2 for information on our related foreign currency derivatives.

(b)

The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date. The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process. One such triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarter by quarter. In the third quarter of 2010, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes during the specified period and, as a result, the holders do not have the option to convert their notes into cash and common stock in the fourth quarter of 2010 under this provision. The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of such principal amount. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years, under certain conditions. We may redeem the convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash. The optional repurchase dates, the common stock price conversion threshold amounts and the ending date of the first six-month period contingent interest may be payable for the contingent convertible senior notes are as follows:


Contingent Convertible Senior Notes	Repurchase Dates	Common Stock Price Conversion Thresholds	Contingent Interest First Payable (if applicable)

2.75% due 2035	November 15, 2015, 2020, 2025, 2030	$ 48.71	May 14, 2016
2.5% due 2037	May 15, 2017, 2022, 2027, 2032	$ 64.26	November 14, 2017
2.25% due 2038	December 15, 2018, 2023, 2028, 2033	$ 107.36	June 14, 2019

(c)	Effective January 1, 2010, our midstream joint venture was no longer consolidated in accordance with the new authoritative guidance. See Notes 1 and 9 for further details.

(d)	Included in this discount is $731 million at September 30, 2010 and $794 million at December 31, 2009 associated with the equity component of our contingent convertible senior notes.

(e)	See Note 2 for discussion related to these instruments.

Senior Notes

Our senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Chesapeake is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our senior note obligations are guaranteed by certain of our wholly owned subsidiaries. See Note 12 for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries. We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that limit our ability and our subsidiaries’ ability to incur certain secured indebtedness; enter into sale/leaseback transactions; and consolidate, merge or transfer assets.

We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance. These rates for our 2.75% Contingent Convertible Senior Notes due 2035, our 2.5% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 are 6.86%, 8.0% and 8.0%, respectively.

On June 21, 2010, we redeemed in whole for an aggregate redemption price of approximately $1.366 billion, plus accrued interest, approximately $364 million in principal amount of our outstanding 7.50% Senior Notes due 2013, $300 million in principal amount of our 7.50% Senior Notes due 2014 and approximately $670 million in principal amount of our 6.875% Senior Notes due 2016. Associated with the redemptions, we recognized a loss of $69 million in the Current Period.

On July 22, 2010, we redeemed in whole for a redemption price of approximately $619 million, plus accrued interest, all $600 million in principal amount of our 6.375% Senior Notes due 2015. Associated with the redemption, we recognized a loss of $19 million in the Current Quarter.

On August 3, 2010, we filed a shelf registration statement on Form S-3 with the SEC for the offering from time to time of debt securities.

On August 17, 2010, we completed a public offering of $2.0 billion aggregate principal amount of senior notes for net proceeds of approximately $1.967 billion. The offering consisted of $600 million of 6.875% Senior Notes due 2018 and $1.4 billion of 6.625% Senior Notes due 2020. Both series were priced at par.

On August 30, 2010, we completed tender offers to purchase for cash $245 million of 7.00% Senior Notes due 2014, $567 million of 6.625% Senior Notes due 2016 and $582 million of 6.25% Senior Notes due 2018. On September 16, 2010, we redeemed the remaining $55 million of 7.00% Senior Notes due 2014, $33 million of 6.625% Senior Notes due 2016 and $18 million of 6.25% Senior Notes due 2018 based on the redemption provisions in the indentures. Associated with the tender offers and redemptions, we recognized a loss of $40 million in the Current Quarter.

During the Current Period, holders of our 2.25% Contingent Convertible Senior Notes due 2038 exchanged approximately $11 million in aggregate principal amount for an aggregate of 298,500 shares of our common stock in privately negotiated exchanges. Associated with these exchanges, we recognized a loss of $2 million in the Current Period.

No scheduled principal payments are required under our senior notes until 2013 when $500 million is due.

Bank Credit Facilities

We utilize two bank credit facilities, described below, as sources of liquidity.


	Corporate Credit Facility^(a)	Midstream Credit Facility^(b)
	($ in millions)

Borrowing capacity	$ 3,500	$ 300

Maturity date	November 2012	July 2015

Facility structure	Senior secured revolving	Senior secured revolving

Amount outstanding as of September 30, 2010	$ 2,237	$ 250

Letters of credit outstanding as of September 30, 2010	$ 13	$ —

(a)	Borrowers are Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C.

(b)	Borrower is Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of Chesapeake Midstream Development, L.P.

Our credit facilities do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates under our corporate credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, neither of our credit facilities contains provisions which would trigger an acceleration of amounts due under the facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings.

Corporate Credit Facility

Our $3.5 billion syndicated revolving bank credit facility is used for general corporate purposes. Borrowings under the facility are secured by natural gas and oil proved reserves and bear interest at our option at either (i) the greater of the reference rate of Union Bank, N.A. or the federal funds effective rate plus 0.50%, both of which are subject to a margin that varies from 0.00% to 0.75% per annum according to our senior unsecured long-term debt ratings, or (ii) the London Interbank Offered Rate (LIBOR), plus a margin that varies from 1.50% to 2.25% per annum 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 a commitment fee of 0.50%. 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, make investments or loans and create liens and require us to maintain an indebtedness to total capitalization ratio and an indebtedness to EBITDA ratio, in each case as defined in the agreement. We were in compliance with all covenants under the agreement at September 30, 2010. 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 $50 million or more, 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 of Chesapeake and its restricted subsidiaries with an outstanding principal amount in excess of $75 million.

The facility is fully and unconditionally guaranteed, on a joint and several basis, by Chesapeake and certain of our other wholly owned subsidiaries.

Midstream Credit Facility

Our $300 million midstream syndicated revolving bank credit facility is used to fund capital expenditures to build natural gas gathering and other systems for our drilling program and for general corporate purposes associated with our midstream operations. Borrowings under the midstream credit facility are secured by all of the assets of the wholly owned subsidiaries (the restricted subsidiaries) of Chesapeake Midstream Development, L.P. (CMD), itself a wholly owned subsidiary of Chesapeake, and bear interest at our option at either (i) the greater of the reference rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.75% to 2.25% per annum according to the most recent leverage ratio described below or (ii) the LIBOR plus a margin that varies from 2.75% to 3.25% per annum according to the most recent leverage ratio. The unused portion of the facility is subject to a commitment fee of 0.50% per annum according to the most recent leverage ratio. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The midstream credit facility agreement contains various covenants and restrictive provisions which limit the ability of CMD and its restricted subsidiaries to incur additional indebtedness, make investments or loans and create liens. The agreement requires maintenance of a leverage ratio based on the ratio of indebtedness to EBITDA and an interest coverage ratio based on the ratio of EBITDA to interest expense, in each case as defined in the agreement. The leverage ratio increases during any three-quarter period, beginning in the quarter in which CMD makes a material disposition of assets to our master limited partnership midstream affiliate, Chesapeake Midstream Partners, L.P. We were in compliance with all covenants under the agreement at September 30, 2010. If CMD or its restricted subsidiaries should fail to perform their 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. The midstream credit facility agreement also has cross default provisions that apply to other indebtedness CMD and its restricted subsidiaries may have with an outstanding principal amount in excess of $15 million.

Other Financings

In 2009, we financed 113 real estate surface assets in the Barnett Shale area for approximately $145 million and entered into a 40-year master lease agreement under which we agreed to lease the sites for approximately $15 million to $27 million annually. This lease transaction was recorded as a financing lease and the cash received was recorded with an offsetting long-term liability on the condensed consolidated balance sheet. Chesapeake exercised its option to repurchase two of the assets in the Current Period. As of September 30, 2010, 111 assets were leased and the minimum aggregate undiscounted future lease payments were approximately $832 million.

In 2009, we financed our regional Barnett Shale headquarters building in Fort Worth, Texas for net proceeds of approximately $54 million with a five-year term loan which has a floating rate of prime plus 275 basis points. At our option, we may prepay in full without penalty beginning in year four. The payment obligation is guaranteed by Chesapeake.

Segment Information

9 Months Ended

Sep. 30, 2010

Segment Information

7.	Segment Information

In accordance with accounting guidance for disclosures about segments of an enterprise and related information, we have two reportable operating segments. Our exploration and production operational segment and natural gas and oil midstream segment are managed separately because of the nature of their products and services. The exploration and production segment is responsible for finding and producing natural gas and oil. The midstream segment is responsible for marketing, gathering and compression of natural gas and oil primarily from Chesapeake-operated wells. We also have drilling rig and trucking operations which are responsible for providing drilling rigs primarily used on Chesapeake-operated wells and trucking services utilized in the transportation of drilling rigs on both Chesapeake-operated wells and wells operated by third parties. Our drilling rig and trucking service operations are presented in “Other Operations” in the table below.

Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the midstream segment’s sale of natural gas and oil related to Chesapeake’s ownership interests are reflected as exploration and production revenues. Such amounts totaled $1.045 billion, $716 million, $2.978 billion and $2.009 billion for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period. The following table presents selected financial information for Chesapeake’s operating segments.


	Exploration and Production			Midstream			Other Operations			Intercompany Eliminations			Consolidated Total
	($ in millions)

Three Months Ended September 30, 2010:
Revenues	$	1,639		$	1,928		$	187		$	(1,173	)	$	2,581
Intersegment revenues		—			(1,045	)		(128	)		1,173			—

Total revenues	$	1,639		$	883		$	59		$	—		$	2,581


Income (loss) before income taxes	$	822		$	96		$	(7	)	$	(4	)	$	907


Three Months Ended September 30, 2009:
Revenues	$	1,187		$	1,291		$	69		$	(736	)	$	1,811
Intersegment revenues		—			(716	)		(20	)		736			—

Total revenues	$	1,187		$	575		$	49		$	—		$	1,811


Income (loss) before income taxes	$	431		$	(111	)	$	(19	)	$	6		$	307


Nine Months Ended September 30, 2010:
Revenues	$	4,698		$	5,498		$	538		$	(3,343	)	$	7,391
Intersegment revenues		—			(2,978	)		(365	)		3,343			—

Total revenues	$	4,698		$	2,520		$	173		$	—		$	7,391


Income (loss) before income taxes	$	2,401		$	152		$	(32	)	$	(1	)	$	2,520


Nine Months Ended September 30, 2009:
Revenues	$	3,681		$	3,669		$	338		$	(2,208	)	$	5,480
Intersegment revenues		—			(2,009	)		(199	)		2,208			—

Total revenues	$	3,681		$	1,660		$	139		$	—		$	5,480


Income (loss) before income taxes	$	(8,354	)	$	(82	)	$	(53	)	$	(1	)	$	(8,490	)


As of September 30, 2010:
Total assets	$	30,945		$	3,481		$	721		$	(814	)	$	34,333

As of December 31, 2009:
Total assets	$	25,637		$	4,323		$	660		$	(706	)	$	29,914

Divestitures

9 Months Ended

Sep. 30, 2010

Divestitures

8.	Divestitures

Joint Ventures

In January 2010, Chesapeake and Total E&P USA, Inc., a wholly owned subsidiary of Total S.A., closed a $2.25 billion Barnett Shale joint venture transaction, whereby Total acquired a 25% interest in our upstream Barnett Shale assets. Total paid us approximately $800 million in cash at closing (plus $78 million of drilling and completion carries due from the effective date of the transaction to the closing date) and is obligated to pay a total of $1.45 billion over time by funding 60% of our share of future drilling and completion expenditures. We expect this drilling carry to be fully utilized by year-end 2013.

During the Current Period and Prior Period, our drilling and completion costs included the benefit of approximately $745 million and $959 million, respectively, in drilling and completion carries associated with our shale play joint ventures with Total, Statoil, BP America and Plains Exploration & Production Company as follows:

Shale

Play

Joint Venture

Partner

Joint Venture

Date

Nine Months Ended
September 30,

2010

2009

($ in millions)

Barnett

Total

January 2010

349

—

Marcellus

Statoil

November 2008

396

Fayetteville

September 2008

—

524

Haynesville

Plains

July 2008

—

350

745

959

During the Current Period, as part of our joint venture agreements with Total, Statoil and Plains, we sold interests in additional leasehold in the Barnett, Marcellus and Haynesville shale plays for approximately $395 million.

For accounting purposes, cash proceeds from these joint venture transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized.

Volumetric Production Payments

On February 5, 2010, we sold certain Chesapeake-operated long-lived producing assets in East Texas and the Texas Gulf Coast in our sixth volumetric production payment (VPP) transaction for net proceeds of approximately $180 million, or $3.95 per mcfe.

On June 14, 2010, we sold certain Chesapeake-operated long-lived producing assets in the Permian Basin in our seventh VPP transaction for proceeds of approximately $335 million, or $8.73 per mcfe.

On September 30, 2010, we sold certain Chesapeake-operated long-lived producing assets in the Barnett Shale in our eighth VPP transaction for proceeds of approximately $1.15 billion, or $2.93 per mcfe.

For accounting purposes, cash proceeds from these transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized, and our proved reserves were reduced accordingly.

Other Divestitures

In the Current Period, we sold producing properties and gathering systems in Virginia and in the Permian Basin for proceeds of approximately $330 million.

Investments

9 Months Ended

Sep. 30, 2010

Investments

9.	Investments

At September 30, 2010, investments accounted for under the equity method totaled $1.160 billion and investments accounted for under the cost method totaled $29 million. Following is a summary of our investments:


					Carrying Value
	Approximate % Owned		Accounting Method		September 30, 2010		December 31, 2009
					($ in millions)

Chesapeake Midstream Partners, L.P.		42%		Equity	$	666	$	—
Frac Tech Services, LLC		26%		Equity		347		239
Chaparral Energy, Inc.		20%		Equity		137		103
Gastar Exploration Ltd.		14%		Cost		27		32
Other^(a)		—		Cost/Equity		12		30

					$	1,189	$	404

(a)	In the Current Quarter, we recorded a $16 million impairment of certain other equity investments.

Chesapeake Midstream Partners, L.P. On September 30, 2009, we formed a joint venture with Global Infrastructure Partners (GIP), a New York-based private equity fund, to own and operate natural gas midstream assets. As part of the transaction, Chesapeake contributed certain natural gas gathering and processing assets to, and GIP purchased a 50% interest in, a new joint venture entity. The assets we contributed to the joint venture were substantially all of our midstream assets in the Barnett Shale and also the majority of our non-shale midstream assets in the Arkoma, Anadarko, Delaware and Permian Basins. During the fourth quarter of 2009, the joint venture was consolidated within our financial statements. Effective January 1, 2010, in accordance with new authoritative guidance for variable interest entities, we changed the accounting for our investment in the joint venture to the equity method. Adoption of this new guidance resulted in an after-tax cumulative effect charge to retained earnings of $142 million, which is reflected in our condensed consolidated statement of equity for the Current Period. This charge reflects the difference between the carrying value of our initial investment in the joint venture, which was recorded at carryover basis as an entity under common control, and the fair value of our equity in the joint venture as of the formation date. In May 2010, we received a $75 million cash distribution from the joint venture. The carrying value of our investment in the joint venture is less than our underlying equity in net assets by approximately $240 million as of September 30, 2010. This difference is being accreted over 20 years.

On August 3, 2010, Chesapeake Midstream Partners, L.P. (NYSE: CHKM), which we and GIP formed to own, operate, develop and acquire midstream assets, completed an initial public offering of 24,437,500 common units (including 3,187,500 common units issued pursuant to the exercise of the underwriters' over-allotment option on August 3, 2010) representing limited partner interests and received gross offering proceeds of approximately $513 million at an initial offering price of $21.00 per unit less approximately $38 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of our contribution agreement with GIP, CHKM distributed the approximate $62 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. In connection with the closing of the offering, Chesapeake and GIP contributed the interests of the midstream joint venture's operating subsidiary to CHKM, and CHKM is continuing the business that had been conducted by the joint venture. Common units owned by public security holders represent 17.7% of all outstanding limited partner interests, and Chesapeake and GIP hold 42.3% and 40.0%, respectively, of all outstanding limited partner interests. The limited partners, collectively, have a 98.0% interest in CHKM and the general partner, which is owned and controlled 50/50 by Chesapeake and GIP, has a 2.0% interest in CHKM.

As a result of the initial public offering by CHKM, we recognized a $90 million gain on our investment in the Current Quarter. This gain represented our proportionate share of the excess of offering proceeds over the carrying value of our investment in CHKM.

Frac Tech Services, LLC. The carrying value of our investment in Frac Tech is in excess of our underlying equity in net assets by approximately $190 million as of September 30, 2010. This excess amount is attributed to certain intangibles associated with the specialty services provided by Frac Tech and is being amortized over the estimated life of the intangibles.

Chaparral Energy, Inc. The carrying value of our investment in Chaparral is in excess of our underlying equity in net assets by approximately $61 million as of September 30, 2010. This excess is attributed to the natural gas and oil reserves held by Chaparral and is being amortized over the estimated life of these reserves based on a unit of production rate.

As a result of an additional equity offering by Chaparral to a third party, we recognized a $31 million gain on our investment in the Current Quarter. This gain represented our proportionate share of the excess of offering proceeds over the carrying value of our investment in Chaparral.

Restructuring

9 Months Ended

Sep. 30, 2010

Restructuring

10.

Restructuring

In the Prior Period, we restructured our Charleston, West Virginia-based Eastern Division from a regional corporate headquarters to a regional field office consistent with the business model the company uses elsewhere in the country. As a result, we consolidated the management of our Eastern Division land, legal, accounting, information technology, geoscience and engineering departments into our corporate offices in Oklahoma City. The costs of the reorganization include termination benefits, consolidating or closing facilities and relocating employees. In addition, we had certain other workforce reductions that resulted in termination benefits. A summary of Chesapeake’s restructuring cost is presented below:


Nine Months Ended September 30, 2009
($ in millions)
Termination and relocation costs	$	22
Acceleration of restricted stock awards		9
Other associated costs		3

Total Restructuring Costs	$	34

Fair Value Measurements

9 Months Ended

Sep. 30, 2010

Fair Value Measurements

11.

Fair Value Measurements

Certain financial instruments are reported at fair value on the condensed consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the financial asset or liability and have the lowest priority. Chesapeake uses a market valuation approach based on available inputs and the following methods and assumptions to measure the fair values of its assets and liabilities, which may or may not be observable in the market.

Cash Equivalents. The fair value of cash equivalents is based on quoted market prices.

Investments. The fair value of Chesapeake’s investment in Gastar Exploration Ltd. (NYSE Amex: GST) common stock is based on a quoted market price.

Other Long-Term Assets and Liabilities. The fair value of other long-term assets and liabilities, consisting of obligations under our Deferred Compensation Plan, is based on quoted market prices.

Derivatives. The fair values of our commodity derivatives are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas and oil forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are then compared to the values given by our counterparties for reasonableness. Since the commodity swaps do not have options and therefore no unobservable inputs, they are classified as Level 2. All other commodity derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. For interest rate and foreign currency derivatives, we use the fair value estimates provided by our respective counterparties, which are classified as Level 3 inputs. These values are reviewed internally for reasonableness using future interest rate curves and time to maturity. Derivatives are also subject to the risk that counterparties will be unable to meet their obligations. We factor in non-performance risk in the valuation of our derivatives using current published credit default swap rates. To date this has not had a material impact on the values of our derivatives.

Debt. The fair value of certain of our long-term debt is based on the face amount of that debt along with the value of related interest rate swaps.

The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2010:


	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Total Fair Value
	($ in millions)

Financial Assets (Liabilities):
Cash equivalents	$	609		$	—	$	—		$	609
Investments		27			—		—			27
Other long-term assets		42			—		—			42
Long-term debt		—			—		(816	)		(816	)
Other long-term liabilities		(42	)		—		—			(42	)

Derivatives:
Commodity assets		—			1,387		255			1,642
Commodity liabilities		—			—		(1,445	)		(1,445	)
Interest rate assets		—			—		29			29
Interest rate liabilities		—			—		(68	)		(68	)
Foreign currency liabilities		—			—		(35	)		(35	)

Total derivatives		—			1,387		(1,264	)		123

Total	$	636		$	1,387	$	(2,080	)	$	(57	)

The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2009:


	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value
	($ in millions)

Financial Assets (Liabilities):
Cash equivalents	$	307		$	—		$	—		$	307
Investments		32			—			—			32
Other long-term assets		34			—			—			34
Long-term debt		—			—			(1,398	)		(1,398	)
Other long-term liabilities		(34	)		—			—			(34	)

Derivatives:
Commodity assets		—			693			143			836
Commodity liabilities		—			(1	)		(809	)		(810	)
Interest rate liabilities		—			—			(132	)		(132	)
Foreign currency assets		—			—			43			43

Total derivatives		—			692			(755	)		(63	)

Total	$	339		$	692		$	(2,153	)	$	(1,122	)

A summary of the changes in Chesapeake’s assets (liabilities) classified as Level 3 measurements during the Current Period and the Prior Period is presented below:


	Derivatives
	Commodity			Interest Rate			Foreign Currency			Debt
	($ in millions)

Balance of Level 3 as of January 1, 2010	$	(666	)	$	(132	)	$	43		$	(1,398	)
Total gains (losses) (realized/unrealized):
Included in earnings (realized)^(a)		305			(6	)		—			—
Included in earnings or change in net assets (unrealized)^(a)		(669	)		85			(44	)		32
Included in other comprehensive income (loss)		(18	)		—			(34	)		—
Purchases, issuances and settlements		(142	)		14			—			550	^(b)
Transfers in and out of Level 3		—			—			—			—

Balance of Level 3 as of September 30, 2010	$	(1,190	)	$	(39	)	$	(35	)	$	(816	)


Balance of Level 3 as of January 1, 2009	$	431		$	(63	)	$	(76	)	$	(1,470	)
Total gains (losses) (realized/unrealized):
Included in earnings (realized)^(a)		778			20			—			(128	)
Included in earnings or change in net assets (unrealized)^(a)		(380	)		106			42			—
Included in other comprehensive income (loss)		45			—			78			—
Purchases, issuances and settlements		(835	)		(154	)		—			(450	)^(b)
Transfers in and out of Level 3		—			—			—			—

Balance of Level 3 as of September 30, 2009	$	39		$	(91	)	$	44		$	(2,048	)

(a)	Amounts related to commodity derivatives are included in Natural Gas and Oil Sales, and amounts related to interest rate and foreign currency derivatives and debt are included in Interest Expense.

(b)	Amount represents a(n) (increase)/decrease in debt recorded at fair value as a result of new or terminated interest rate swaps.

Fair Value of Other Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for 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 financial instruments 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 debt and our convertible preferred stock primarily using quoted market prices. Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.


	September 30, 2010				December 31, 2009
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	($ in millions)

Long-term debt	$	11,409	$	12,295	$	12,226	$	12,824
Convertible preferred stock	$	3,065	$	2,994	$	466	$	401

Condensed Consolidating Financial Information

9 Months Ended

Sep. 30, 2010

Condensed Consolidating Financial Information

12.

Condensed Consolidating Financial Information

Chesapeake Energy Corporation 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 and contingent convertible notes listed in Note 6 are fully and unconditionally guaranteed, jointly and severally, by certain of our wholly owned subsidiaries on a senior unsecured basis. Our midstream subsidiary, CMD, is not a guarantor and is subject to covenants in the midstream revolving credit facility referred to in Note 6 that restricts it from paying dividends or distributions or making loans to Chesapeake.

Set forth below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of September 30, 2010 and December 31, 2009 and for the three and nine months ended September 30, 2010 and 2009. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF SEPTEMBER 30, 2010


	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	($ in millions)

CURRENT ASSETS:
Cash and cash equivalents	$	—		$	587	$	22	$	—		$	609
Other		3			2,549		139		(27	)		2,664

Total Current Assets		3			3,136		161		(27	)		3,273


PROPERTY AND EQUIPMENT:
Natural gas and oil properties, at cost based on full-cost accounting		—			24,649		216		—			24,865
Other property and equipment, net		—			3,029		1,586		—			4,615

Total Property and Equipment		—			27,678		1,802		—			29,480


Other assets		193			715		672		—			1,580
Investments in subsidiaries and intercompany advance		1,356			121		—		(1,477	)		—

TOTAL ASSETS	$	1,552		$	31,650	$	2,635	$	(1,504	)	$	34,333


CURRENT LIABILITIES:
Current liabilities	$	226		$	3,816	$	110	$	(29	)	$	4,123
Intercompany payable (receivable) from parent		(23,340	)		21,214		2,145		(19	)		—

Total Current Liabilities		(23,114	)		25,030		2,255		(48	)		4,123


LONG-TERM LIABILITIES:
Long-term debt, net		8,958			2,237		250		—			11,445
Deferred income tax liabilities		392			1,418		8		21			1,839
Other liabilities		43			1,609		1		—			1,653

Total Long-Term Liabilities		9,393			5,264		259		21			14,937


EQUITY:
Chesapeake stockholders’ equity		15,273			1,356		121		(1,477	)		15,273
Noncontrolling interest		—			—		—		—			—

Total Equity		15,273			1,356		121		(1,477	)		15,273

TOTAL LIABILITIES AND EQUITY	$	1,552		$	31,650	$	2,635	$	(1,504	)	$	34,333

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2009


	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	($ in millions)

CURRENT ASSETS:
Cash and cash equivalents	$	—		$	293	$	14	$	—		$	307
Other		27			2,031		166		(85	)		2,139

Total Current Assets		27			2,324		180		(85	)		2,446


PROPERTY AND EQUIPMENT:
Natural gas and oil properties, at cost based on full-cost accounting		—			20,788		4		—			20,792
Other property and equipment, net		—			2,903		3,015		—			5,918

Total Property and Equipment		—			23,691		3,019		—			26,710


Other assets		197			540		21		—			758
Investments in subsidiaries and intercompany advance		3,029			222		—		(3,251	)		—

TOTAL ASSETS	$	3,253		$	26,777	$	3,220	$	(3,336	)	$	29,914


CURRENT LIABILITIES:
Current liabilities	$	277		$	2,261	$	235	$	(85	)	$	2,688
Intercompany payable (receivable) from parent		(19,388	)		17,508		1,793		87			—

Total Current Liabilities		(19,111	)		19,769		2,028		2			2,688


LONG-TERM LIABILITIES:
Long-term debt, net		10,359			1,892		44		—			12,295
Deferred income tax liabilities		393			727		26		(87	)		1,059
Other liabilities		168			1,360		3		—			1,531

Total Long-Term Liabilities		10,920			3,979		73		(87	)		14,885


EQUITY:
Chesapeake stockholders’ equity		11,444			3,029		222		(3,251	)		11,444
Noncontrolling interest		—			—		897		—			897

Total Equity		11,444			3,029		1,119		(3,251	)		12,341


TOTAL LIABILITIES AND EQUITY	$	3,253		$	26,777	$	3,220	$	(3,336	)	$	29,914

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2010


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	($ in millions)

REVENUES:
Natural gas and oil sales	$	—		$	1,639		$	—		$	—		$	1,639
Marketing, gathering and compression sales		—			856			69			(42	)		883
Service operations revenue		—			59			—			—			59

Total Revenues		—			2,554			69			(42	)		2,581


OPERATING COSTS:
Production expenses		—			231			—			—			231
Production taxes		—			34			—			—			34
General and administrative expenses		2			113			10			—			125
Marketing, gathering and compression expenses		—			838			37			(24	)		851
Service operations expense		—			52			—			—			52
Natural gas and oil depreciation, depletion and amortization		—			378			—			—			378
Depreciation and amortization of other assets		—			43			13			—			56
Impairment or loss on sale of property and equipment		—			3			34			—			37

Total Operating Costs		2			1,692			94			(24	)		1,764


INCOME (LOSS) FROM OPERATIONS		(2	)		862			(25	)		(18	)		817


OTHER INCOME (EXPENSE):
Interest (expense) income		(153	)		(16	)		(1	)		167			(3	)
Loss on redemptions or exchanges of Chesapeake debt		(59	)		—			—			—			(59	)
Impairment of investments		—			(16	)		—			—			(16	)
Other income (expense)		167			52			116			(167	)		168
Equity in net earnings of subsidiary		587			44			—			(631	)		—

Total Other Income (Expense)		542			64			115			(631	)		90


INCOME (LOSS) BEFORE INCOME TAXES		540			926			90			(649	)		907
INCOME TAX EXPENSE (BENEFIT)		(18	)		339			35			(7	)		349

NET INCOME (LOSS)		558			587			55			(642	)		558
Net income (loss) attributable to noncontrolling interest		—			—			—			—			—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	558		$	587		$	55		$	(642	)	$	558

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2009


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	($ in millions)
REVENUES:
Natural gas and oil sales	$	—		$	1,187		$	—		$	—		$	1,187
Marketing, gathering and compression sales		—			504			126			(55	)		575
Service operations revenue		—			49			—			—			49

Total Revenues		—			1,740			126			(55	)		1,811

OPERATING COSTS:
Production expenses		—			218			—			—			218
Production taxes		—			25			—			—			25
General and administrative expenses		—			86			9			—			95
Marketing, gathering and compression expenses		—			497			54			(5	)		546
Service operations expense		—			49			—			—			49
Natural gas and oil depreciation, depletion and amortization		—			295			—			—			295
Depreciation and amortization of other assets		1			36			25			—			62
Loss on sale of other property and equipment		—			—			124			—			124

Total Operating Costs		1			1,206			212			(5	)		1,414

INCOME (LOSS) FROM OPERATIONS		(1	)		534			(86	)		(50	)		397

OTHER INCOME (EXPENSE):
Interest (expense) income		(161	)		(57	)		—			175			(43	)
Loss on redemptions or exchanges of Chesapeake debt		(17	)		—			—			—			(17	)
Other income (expense)		175			(24	)		(6	)		(175	)		(30	)
Equity in net earnings of subsidiary		194			(89	)		—			(105	)		—

Total Other Income (Expense)		191			(170	)		(6	)		(105	)		(90	)

INCOME (LOSS) BEFORE INCOME TAXES		190			364			(92	)		(155	)		307
INCOME TAX EXPENSE (BENEFIT)		(2	)		170			(34	)		(19	)		115

NET INCOME (LOSS)		192			194			(58	)		(136	)		192
Net income (loss) attributable to noncontrolling interest		—			—			—			—			—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	192		$	194		$	(58	)	$	(136	)	$	192

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2010


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	($ in millions)
REVENUES:
Natural gas and oil sales	$	—		$	4,698		$	—		$	—		$	4,698
Marketing, gathering and compression sales		—			2,437			179			(96	)		2,520
Service operations revenue		—			173			—			—			173

Total Revenues		—			7,308			179			(96	)		7,391

OPERATING COSTS:
Production expenses		—			652			—			—			652
Production taxes		—			119			—			—			119
General and administrative expenses		2			315			23			—			340
Marketing, gathering and compression expenses		—			2,383			90			(44	)		2,429
Service operations expense		—			154			—			—			154
Natural gas and oil depreciation, depletion and amortization		—			1,025			—			—			1,025
Depreciation and amortization of other assets		—			124			35			—			159
Impairment or loss on sale of property and equipment		—			3			34			—			37

Total Operating Costs		2			4,775			182			(44	)		4,915

INCOME (LOSS) FROM OPERATIONS		(2	)		2,533			(3	)		(52	)		2,476

OTHER INCOME (EXPENSE):
Interest (expense) income		(451	)		(107	)		(3	)		549			(12	)
Loss on redemptions or exchanges of Chesapeake debt		(130	)		—			—			—			(130	)
Impairment of investments		—			(16	)		—			—			(16	)
Other income (expense)		549			52			150			(549	)		202
Equity in net earnings of subsidiary		1,571			57			—			(1,628	)		—

Total Other Income (Expense)		1,539			(14	)		147			(1,628	)		44

INCOME (LOSS) BEFORE INCOME TAXES		1,537			2,519			144			(1,680	)		2,520
INCOME TAX EXPENSE (BENEFIT)		(13	)		948			55			(20	)		970

NET INCOME (LOSS)		1,550			1,571			89			(1,660	)		1,550
Net income (loss) attributable to noncontrolling interest		—			—			—			—			—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	1,550		$	1,571		$	89		$	(1,660	)	$	1,550

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2009


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	($ in millions)
REVENUES:
Natural gas and oil sales	$	—		$	3,681		$	—		$	—		$	3,681
Marketing, gathering and compression sales		—			1,461			354			(155	)		1,660
Service operations revenue		—			139			—			—			139

Total Revenues		—			5,281			354			(155	)		5,480

OPERATING COSTS:
Production expenses		—			670			—			—			670
Production taxes		—			71			—			—			71
General and administrative expenses		—			239			20			—			259
Marketing, gathering and compression expenses		—			1,436			148			(15	)		1,569
Service operations expense		—			136			—			—			136
Natural gas and oil depreciation, depletion and amortization		—			1,037			—			—			1,037
Depreciation and amortization of other assets		—			110			67			—			177
Impairment of natural gas and oil properties		—			9,600			—			—			9,600
Impairment or loss on sale of other property and equipment		—			35			124			—			159
Restructuring costs		—			34			—			—			34

Total Operating Costs		—			13,368			359			(15	)		13,712

INCOME (LOSS) FROM OPERATIONS		—			(8,087	)		(5	)		(140	)		(8,232	)

OTHER INCOME (EXPENSE):
Interest (expense) income		(447	)		(112	)		(5	)		512			(52	)
Loss on redemptions or exchanges of Chesapeake debt		(19	)		—			—			—			(19	)
Impairment of investments		—			(148	)		(14	)		—			(162	)
Other income (expense)		512			(21	)		(4	)		(512	)		(25	)
Equity in net earnings of subsidiary		(5,335	)		(105	)		—			5,440			—

Total Other Income (Expense)		(5,289	)		(386	)		(23	)		5,440			(258	)

INCOME (LOSS) BEFORE INCOME TAXES		(5,289	)		(8,473	)		(28	)		5,300			(8,490	)
INCOME TAX EXPENSE (BENEFIT)		17			(3,138	)		(11	)		(52	)		(3,184	)

NET INCOME (LOSS)		(5,306	)		(5,335	)		(17	)		5,352			(5,306	)
Net income (loss) attributable to noncontrolling interest		—			—			—			—			—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	(5,306	)	$	(5,335	)	$	(17	)	$	5,352		$	(5,306	)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2010


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	3,774		$	197		$	—	$	3,971
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to natural gas and oil properties		—			(7,723	)		(212	)		—		(7,935	)
Additions to other property and equipment		—			(412	)		(556	)		—		(968	)
Proceeds from divestitures of natural gas and oil properties		—			3,107			—			—		3,107
Other investing activities		—			—			131			—		131

Cash used in investing activities		—			(5,028	)		(637	)		—		(5,665	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			10,076			382			—		10,458
Payments on credit facilities borrowings		—			(9,736	)		(127	)		—		(9,863	)
Proceeds from preferred stock, net of offering costs		2,562			—			—			—		2,562
Proceeds from issuance of senior notes, net of offering costs		1,967			—			—			—		1,967
Cash paid to redeem Chesapeake debt		(3,434	)		—			—			—		(3,434	)
Other financing activities		(243	)		567			(18	)		—		306
Intercompany advances, net		(852	)		641			211			—		—

Cash provided by (used in) financing activities		—			1,548			448			—		1,996

Net increase (decrease) in cash and cash equivalents		—			294			8			—		302
Cash and cash equivalents, beginning of period		—			293			14			—		307

Cash and cash equivalents, end of period	$	—		$	587		$	22		$	—	$	609

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2009


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	3,075		$	56		$	—	$	3,131
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to natural gas and oil properties		—			(4,138	)		—			—		(4,138	)
Additions to other property and equipment		—			(661	)		(701	)		—		(1,362	)
Proceeds from divestitures of natural gas and oil properties		—			1,729			—			—		1,729
Other investing activities		—			78			39			—		117

Cash used in investing activities		—			(2,992	)		(662	)		—		(3,654	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			4,894			669			—		5,563
Payments on credit facilities borrowings		—			(6,749	)		(1,117	)		—		(7,866	)
Proceeds from issuance of senior notes, net of offering costs		1,346			—			—			—		1,346
Proceeds from sales of noncontrolling interest in midstream joint venture		—			—			588			—		588
Other financing activities		(153	)		(167	)		(17	)		—		(337	)
Intercompany advances, net		(1,193	)		554			639			—		—

Cash provided by (used in) financing activities		—			(1,468	)		762			—		(706	)

Net increase (decrease) in cash and cash equivalents		—			(1,385	)		156			—		(1,229	)
Cash and cash equivalents, beginning of period		—			1,749			—			—		1,749

Cash and cash equivalents, end of period	$	—		$	364		$	156		$	—	$	520

Recently Issued and Proposed Accounting Standards

9 Months Ended

Sep. 30, 2010

Recently Issued and Proposed Accounting Standards

13.

Recently Issued and Proposed Accounting Standards

The Financial Accounting Standards Board (FASB) recently issued the following standards which we reviewed to determine the potential impact on our financial statements upon adoption.

In February 2010, the FASB amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted this guidance in the Current Period.

The FASB also issued new guidance requiring additional disclosures about fair value measurements, adding a new requirement to disclose transfers in and out of Levels 1 and 2 measurements and gross presentation of activity within a Level 3 roll forward. The guidance also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. We adopted this guidance in the Current Period. Adoption had no impact on our financial position or results of operations. Required disclosures for the reconciliation of purchases, sales, issuance and settlements of financial instruments valued with a Level 3 method are effective beginning on January 1, 2011, and we do not expect the implementation to have a material impact on our financial position or results of operations. See Note 11 for discussion regarding fair value measurements.

Subsequent Events

9 Months Ended

Sep. 30, 2010

Subsequent Events

14.

Subsequent Events

On October 10, 2010, we entered into an agreement whereby a wholly owned U.S. subsidiary of CNOOC Limited (CNOOC) agreed to purchase a 33.3% undivided interest in 600,000 net oil and natural gas leasehold acres we hold in the Eagle Ford Shale in South Texas. The consideration for the sale will be approximately $1.08 billion in cash at closing. In addition, CNOOC has agreed to fund 75% of our share of drilling and completion costs in the Eagle Ford Shale project until an additional $1.08 billion has been paid, which we expect to occur by year-end 2012. Closing of the transaction is anticipated in the fourth quarter of 2010.

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2010
Statement [Line Items]
Principles of Consolidation	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 (SEC). Chesapeake’s annual report on Form 10-K for the year ended December 31, 2009 (2009 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, 2010 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, 2010 (the “Current Quarter” and the “Current Period”, respectively) and the three and nine months ended September 30, 2009 (the “Prior Quarter” and the “Prior Period”, respectively).
Cumulative Effect of Accounting Change	Cumulative Effect of Accounting Change Effective January 1, 2010, in accordance with new authoritative guidance for variable interest entities, we ceased consolidating our 50/50 midstream joint venture with Global Infrastructure Partners within our financial statements and began to account for the joint venture under the equity method (see Note 9). Adoption of this new guidance resulted in an after-tax cumulative effect charge to retained earnings of $142 million, which is reflected in our condensed consolidated statement of equity for the Current Period. This charge reflects the difference between the carrying value of our initial investment in the joint venture, which was recorded at carryover basis as an entity under common control, and the fair value of our equity in the joint venture as of the formation date.
Critical Accounting Policies	Critical Accounting Policies We consider accounting policies related to hedging, natural gas and oil properties and income taxes to be critical policies. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2009 Form 10-K.

Financial Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2010

Oil and Gas Production/Processing Derivative Activities Disclosure


	September 30, 2010						December 31, 2009
	Volume			Fair Value			Volume			Fair Value
Natural gas (bbtu):				($ in millions)						($ in millions)
Fixed-price swaps		616,190		$	1,378			492,053		$	662
Fixed-price collars		10,980			37			74,240			92
Call options		1,333,619			(481	)		996,750			(541	)
Put options		(58,580	)		(75	)		(69,620	)		(50	)
Fixed-price knockout swaps		28,530			5			38,370			17
Basis protection swaps		154,502			(52	)		125,469			(50	)

Total natural gas		2,085,241			812			1,657,262			130


Oil (mbbl):
Fixed-price swaps		8,044			(28	)		5,475			3
Call options		42,259			(622	)		14,975			(144	)
Fixed-price knockout swaps		3,023			35			6,572			32

Total oil		53,326			(615	)		27,022			(109	)


Total estimated fair value				$	197					$	21

Results of Operations for Oil and Gas Producing Activities Disclosure

The components of natural gas and oil sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2010		2009			2010			2009
	($ in millions)
Natural gas and oil sales	$	1,074	$	785		$	3,243		$	2,280
Realized gains (losses) on natural gas and oil derivatives		512		687			1,484			1,802
Unrealized gains (losses) on non-qualifying natural gas and oil derivatives		48		(278	)		(9	)		(484	)
Unrealized gains (losses) on ineffectiveness of cash flow hedges		5		(7	)		(20	)		83

Total natural gas and oil sales	$	1,639	$	1,187		$	4,698		$	3,681

Interest Rate Derivatives Disclosure

The notional amount of debt hedged and the estimated fair value of our interest rate derivatives outstanding as of September 30, 2010 and December 31, 2009 are provided below.


	September 30, 2010					December 31, 2009
	Notional Amount		Fair Value			Notional Amount		Fair Value
	($ in millions)
Interest rate:
Swaps	$	1,300	$	(13	)	$	2,925	$	(113	)
Collars		—		—			250		(6	)
Call options		250		(26	)		250		(2	)
Swaptions		250		—			500		(11	)

Totals	$	1,800	$	(39	)	$	3,925	$	(132	)

Interest Income and Interest Expense Disclosure

The components of interest expense for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	($ in millions)

Interest expense on senior notes	$	167		$	195		$	550		$	572
Interest expense on credit facilities		18			18			42			47
Capitalized interest		(185	)		(153	)		(525	)		(467	)
Realized (gains) losses on interest rate derivatives		(2	)		(7	)		(6	)		(19	)
Unrealized (gains) losses on interest rate derivatives		2			(20	)		(75	)		(106	)
Amortization of loan discount and other		3			10			26			25

Total interest expense	$	3		$	43		$	12		$	52

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value


		Fair Value
	Balance Sheet Location	September 30, 2010			December 31, 2009
		($ in millions)
Asset Derivatives:
Derivatives designated as hedging instruments:
Commodity contracts	Short-term derivative instruments	$	438		$	417
Commodity contracts	Long-term derivative instruments		41			36
Foreign currency contracts	Long-term derivative instruments		—			43

Total			479			496


Derivatives not designated as hedging instruments:
Commodity contracts	Short-term derivative instruments		794			318
Commodity contracts	Long-term derivative instruments		367			66
Interest rate contracts	Long-term derivative instruments		29			—

Total			1,190			384


Liability Derivatives:
Derivatives designated as hedging instruments:
Commodity contracts	Short-term derivative instruments		—			(1	)
Interest rate contracts	Long-term derivative instruments		—			(11	)
Foreign currency contracts	Long-term derivative instruments		(35	)		—

Total			(35	)		(12	)


Derivatives not designated as hedging instruments:
Commodity contracts	Short-term derivative instruments		(145	)		(42	)
Commodity contracts	Long-term derivative instruments		(1,298	)		(768	)
Interest rate contracts	Short-term derivative instruments		(26	)		(27	)
Interest rate contracts	Long-term derivative instruments		(42	)		(94	)

Total			(1,511	)		(931	)


Total derivative instruments		$	123		$	(63	)

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance

The following table presents the gain (loss) recognized in net income (loss) for instruments designated as fair value derivatives:


		Three Months Ended September 30,				Nine Months Ended September 30,
Fair Value Derivatives	Location of Gain (Loss)	2010		2009		2010		2009
		($ in millions)

Interest rate contracts	Interest expense^(a)	$	3	$	13	$	16	$	31

(a)	Interest expense on items hedged during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period was $0, $33 million, $15 million and $66 million, respectively, which is included in interest expense on the condensed consolidated statements of operations.

Schedule of Cash Flow Hedge Instruments, Gain (Loss) in Statement of Financial Performance


		Three Months Ended September 30,					Nine Months Ended September 30,
Cash Flow Derivatives	Location of Gain (Loss)	2010		2009			2010			2009
		($ in millions)

Gain (Loss) Recognized in AOCI (Effective Portion)
Commodity contracts	AOCI	$	94	$	107		$	458		$	819
Foreign exchange contracts	AOCI		5		1			(34	)		79

		$	99	$	108		$	424		$	898


Gain (Loss) Reclassified from AOCI (Effective Portion)
Commodity contracts	Natural gas and oil sales	$	179	$	381		$	535		$	994

		$	179	$	381		$	535		$	994


Gain (Loss) Recognized (Ineffective Portion and Amount Excluded from Effectiveness Testing)^(a)
Commodity contracts	Natural gas and oil sales	$	2	$	(7	)	$	(95	)	$	83

		$	2	$	(7	)	$	(95	)	$	83

(a)

Derivatives Not Designated as Hedging Instruments Disclosure

The following table presents the gain (loss) recognized in net income (loss) for instruments not qualifying as cash flow or fair value derivatives:


		Three Months Ended September 30,					Nine Months Ended September 30,
Non-Qualifying Derivatives	Location of Gain (Loss)	2010			2009		2010		2009
		($ in millions)

Commodity contracts	Natural gas and oil sales	$	384		$	28	$	1,015	$	324
Interest rate contracts	Interest expense		(3	)		14		65		94

	Total	$	381		$	42	$	1,080	$	418

Contingencies and Commitments (Tables)

9 Months Ended

Sep. 30, 2010

Commitments And Contingencies Disclosure Table

The aggregate undiscounted amounts of such required demand payments are presented below:


	September 30, 2010
	($ in millions)

2010		$	82
2011			378
2012			378
2013			364
2014			344
2015 – 2099			2,449

Total		$	3,995

Oil and Gas Delivery Commitments and Contracts Disclosure

Volume commitments remaining as of September 30, 2010 were as follows:


	Bcf

2010		129
2011		313
2012		325
2013		338
2014		351
After 2014		1,686

Total		3,142

Net Income Per Share (Tables)

9 Months Ended

Sep. 30, 2010

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

The following securities and associated adjustments to net income comprised of dividends and losses on conversions/exchanges were not included in the calculation of diluted EPS for the Prior Quarter and the Prior Period, as the effect was antidilutive.


	Shares		Net Income Adjustments
	(in millions)		($ in millions)
Three Months Ended September 30, 2009:
Common stock equivalent of our preferred stock outstanding:
5.00% cumulative convertible preferred stock (series 2005B)		5	$	3
4.50% cumulative convertible preferred stock		6	$	3

Nine Months Ended September 30, 2009:
Common stock equivalent of our preferred stock outstanding:
5.00% cumulative convertible preferred stock (series 2005B)		5	$	8
4.50% cumulative convertible preferred stock		6	$	9
Common stock equivalent of our preferred stock outstanding prior to conversion:
6.25% mandatory convertible preferred stock		1	$	1

Outstanding stock options		1	$	—
Unvested restricted stock		5	$	—

Reconciliation of Earnings Per Share

A reconciliation of basic EPS and diluted EPS for the Current Quarter, the Prior Quarter and the Current Period is as follows:


	Income (Numerator)		Weighted Average Shares (Denominator)		Per Share Amount
	(in millions, except per share data)
Three Months Ended September 30, 2010:
Basic EPS	$	515		632	$	0.81


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 5.75% cumulative convertible preferred stock		21		56
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)		16		40
Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)		2		5
Common shares assumed issued for 4.50% cumulative convertible preferred stock		3		6
Outstanding stock options		—		1
Unvested restricted stock		—		4


Diluted EPS	$	557		744	$	0.75


Three Months Ended September 30, 2009:
Basic EPS	$	186		619	$	0.30


Effect of Dilutive Securities:
Outstanding stock options		—		1
Unvested restricted stock		—		6


Diluted EPS	$	186		626	$	0.30


Nine Months Ended September 30, 2010:
Basic EPS	$	1,482		631	$	2.35


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 5.75% cumulative convertible preferred stock		28		24
Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)		23		20
Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)		8		5
Common shares assumed issued for 4.50% cumulative convertible preferred stock		9		6
Outstanding stock options		—		1
Unvested restricted stock		—		5


Diluted EPS	$	1,550		692	$	2.24

Stockholders' Equity, Restricted Stock and Stock Options (Tables)

9 Months Ended

Sep. 30, 2010

Convertible preferred stock disclosure

Issuance Of Common Stock

The following is a summary of the changes in our common shares issued for the nine months ended September 30, 2010 and 2009:


	2010		2009
	(in thousands)

Shares issued at January 1		648,549		607,953
Restricted stock issuances (net of forfeitures)		6,108		3,940
Stock option exercises		354		429
Convertible note exchanges		299		6,707
Preferred stock conversions/exchanges		21		1,422
Common stock issued for the purchase of proved and unproved properties		—		24,823

Shares issued at September 30		655,331		645,274

The following is a summary of the changes in our preferred shares outstanding for the nine months ended September 30, 2010 and 2009:


	5.75%		5.75%(A)		4.50%		5.00% (2005B)		5.00% (2005)			6.25%			4.125%
	(in thousands)

Shares outstanding at January 1, 2010		—		—		2,559		2,096		5			—			—
Preferred stock issuances		1,500		1,100		—		—		—			—			—
Conversion of preferred into common stock		—		—		—		—		(5	)		—			—

Shares outstanding at September 30, 2010		1,500		1,100		2,559		2,096		—			—			—


Shares outstanding at January 1, 2009		—		—		2,559		2,096		5			144			3
Conversion of preferred into common stock		—		—		—		—		—			(144	)		(3	)

Shares outstanding at September 30, 2009		—		—		2,559		2,096		5			—			—

Stock Based Compensation

We recorded the following stock-based compensation during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	($ in millions)

Natural gas and oil properties	$	30	$	27	$	95	$	85
General and administrative expenses		21		22		63		60
Production expenses		9		8		27		26
Marketing, gathering and compression expenses		5		4		13		12
Service operations expense		2		2		7		6
Restructuring costs		—		—		—		9

Total	$	67	$	63	$	205	$	198

Restricted Share Activity Disclosure

A summary of the changes in unvested shares of restricted stock for the nine months ended September 30, 2010 is presented below:


	Number of Unvested Restricted Shares			Weighted-Average Grant-Date Fair Value
	(in thousands)
Unvested shares as of January 1, 2010		19,225		$ 31.89
Granted		8,901		$ 24.21
Vested		(5,332	)	$ 32.49
Forfeited		(885	)	$ 30.49

Unvested shares as of September 30, 2010		21,909		$ 28.68

Schedule of Share-based Compensation, Options Activity

The following table provides information related to stock option activity for the nine months ended September 30, 2010:


	Number of Shares Underlying Options			Weighted Average Exercise Price Per Share		Weighted Average Contract Life in Years	Aggregate Intrinsic Value^(a)
	(in thousands)						($ in millions)

Outstanding at January 1, 2010		2,283		$	8.36	2.75	$ 40
Exercised		(366	)	$	6.15
Expired		—		$	—

Outstanding at September 30, 2010		1,917		$	8.78	2.22	$ 27


Exercisable at September 30, 2010		1,917		$	8.78	2.22	$ 27

(a)	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

Debt (Tables)

9 Months Ended

Sep. 30, 2010

Schedule of Long-term Debt Instruments

Debt Table Disclosure

Our total debt consisted of the following at September 30, 2010 and December 31, 2009:


	September 30, 2010			December 31, 2009
	($ in millions)

7.5% senior notes due 2013	$	—		$	364
7.625% senior notes due 2013		500			500
7.0% senior notes due 2014		—			300
7.5% senior notes due 2014		—			300
6.375% senior notes due 2015		—			600
9.5% senior notes due 2015		1,425			1,425
6.625% senior notes due 2016		—			600
6.875% senior notes due 2016		—			670
6.25% euro-denominated senior notes due 2017^(a)		816			860
6.5% senior notes due 2017		1,100			1,100
6.25% senior notes due 2018		—			600
6.875% senior notes due 2018		600			—
7.25% senior notes due 2018		800			800
6.625% senior notes due 2020		1,400			—
6.875% senior notes due 2020		500			500
2.75% contingent convertible senior notes due 2035^(b)		451			451
2.5% contingent convertible senior notes due 2037^(b)		1,378			1,378
2.25% contingent convertible senior notes due 2038^(b)		752			763
Corporate revolving bank credit facility		2,237			1,892
Midstream revolving bank credit facility		250			—
Midstream joint venture revolving bank credit facility^(c)		—			44
Discount on senior notes^(d)		(800	)		(921	)
Interest rate derivatives^(e)		36			69

Total notes payable and long-term debt	$	11,445		$	12,295

(a)	The principal amount shown is based on the dollar/euro exchange rate of $1.3601 to €1.00 and $1.4332 to €1.00 as of September 30, 2010 and December 31, 2009, respectively. See Note 2 for information on our related foreign currency derivatives.

(b)


Contingent Convertible Senior Notes	Repurchase Dates	Common Stock Price Conversion Thresholds	Contingent Interest First Payable (if applicable)

2.75% due 2035	November 15, 2015, 2020, 2025, 2030	$ 48.71	May 14, 2016
2.5% due 2037	May 15, 2017, 2022, 2027, 2032	$ 64.26	November 14, 2017
2.25% due 2038	December 15, 2018, 2023, 2028, 2033	$ 107.36	June 14, 2019

(c)	Effective January 1, 2010, our midstream joint venture was no longer consolidated in accordance with the new authoritative guidance. See Notes 1 and 9 for further details.

(d)	Included in this discount is $731 million at September 30, 2010 and $794 million at December 31, 2009 associated with the equity component of our contingent convertible senior notes.

(e)	See Note 2 for discussion related to these instruments.

We utilize two bank credit facilities, described below, as sources of liquidity.


	Corporate Credit Facility^(a)	Midstream Credit Facility^(b)
	($ in millions)

Borrowing capacity	$ 3,500	$ 300

Maturity date	November 2012	July 2015

Facility structure	Senior secured revolving	Senior secured revolving

Amount outstanding as of September 30, 2010	$ 2,237	$ 250

Letters of credit outstanding as of September 30, 2010	$ 13	$ —

(a)	Borrowers are Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C.

(b)	Borrower is Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of Chesapeake Midstream Development, L.P.

Segment Information (Tables)

9 Months Ended

Sep. 30, 2010

Schedule of Segment Reporting Information, by Segment

The following table presents selected financial information for Chesapeake’s operating segments.


	Exploration and Production			Midstream			Other Operations			Intercompany Eliminations			Consolidated Total
	($ in millions)

Three Months Ended September 30, 2010:
Revenues	$	1,639		$	1,928		$	187		$	(1,173	)	$	2,581
Intersegment revenues		—			(1,045	)		(128	)		1,173			—

Total revenues	$	1,639		$	883		$	59		$	—		$	2,581


Income (loss) before income taxes	$	822		$	96		$	(7	)	$	(4	)	$	907


Three Months Ended September 30, 2009:
Revenues	$	1,187		$	1,291		$	69		$	(736	)	$	1,811
Intersegment revenues		—			(716	)		(20	)		736			—

Total revenues	$	1,187		$	575		$	49		$	—		$	1,811


Income (loss) before income taxes	$	431		$	(111	)	$	(19	)	$	6		$	307


Nine Months Ended September 30, 2010:
Revenues	$	4,698		$	5,498		$	538		$	(3,343	)	$	7,391
Intersegment revenues		—			(2,978	)		(365	)		3,343			—

Total revenues	$	4,698		$	2,520		$	173		$	—		$	7,391


Income (loss) before income taxes	$	2,401		$	152		$	(32	)	$	(1	)	$	2,520


Nine Months Ended September 30, 2009:
Revenues	$	3,681		$	3,669		$	338		$	(2,208	)	$	5,480
Intersegment revenues		—			(2,009	)		(199	)		2,208			—

Total revenues	$	3,681		$	1,660		$	139		$	—		$	5,480


Income (loss) before income taxes	$	(8,354	)	$	(82	)	$	(53	)	$	(1	)	$	(8,490	)


As of September 30, 2010:
Total assets	$	30,945		$	3,481		$	721		$	(814	)	$	34,333

As of December 31, 2009:
Total assets	$	25,637		$	4,323		$	660		$	(706	)	$	29,914

Divestitures (Tables)

9 Months Ended

Sep. 30, 2010

Drilling and Completion Costs Associated to Joint Ventures

Shale

Play

Joint Venture

Partner

Joint Venture

Date

Nine Months Ended
September 30,

2010

2009

($ in millions)

Barnett

Total

January 2010

349

—

Marcellus

Statoil

November 2008

396

Fayetteville

September 2008

—

524

Haynesville

Plains

July 2008

—

350

745

959

Investments (Tables)

9 Months Ended

Sep. 30, 2010

Investments in equity securities Disclosure

Following is a summary of our investments:


					Carrying Value
	Approximate % Owned		Accounting Method		September 30, 2010		December 31, 2009
					($ in millions)

Chesapeake Midstream Partners, L.P.		42%		Equity	$	666	$	—
Frac Tech Services, LLC		26%		Equity		347		239
Chaparral Energy, Inc.		20%		Equity		137		103
Gastar Exploration Ltd.		14%		Cost		27		32
Other^(a)		—		Cost/Equity		12		30

					$	1,189	$	404

(a)	In the Current Quarter, we recorded a $16 million impairment of certain other equity investments.

Restructuring (Tables)

9 Months Ended

Sep. 30, 2010

Restructuring Charges Disclosure

A summary of Chesapeake’s restructuring cost is presented below:


Nine Months Ended September 30, 2009
($ in millions)
Termination and relocation costs	$	22
Acceleration of restricted stock awards		9
Other associated costs		3

Total Restructuring Costs	$	34

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2010

Fair Value, Measurement Inputs, Disclosure

The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2010:


	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Total Fair Value
	($ in millions)

Financial Assets (Liabilities):
Cash equivalents	$	609		$	—	$	—		$	609
Investments		27			—		—			27
Other long-term assets		42			—		—			42
Long-term debt		—			—		(816	)		(816	)
Other long-term liabilities		(42	)		—		—			(42	)

Derivatives:
Commodity assets		—			1,387		255			1,642
Commodity liabilities		—			—		(1,445	)		(1,445	)
Interest rate assets		—			—		29			29
Interest rate liabilities		—			—		(68	)		(68	)
Foreign currency liabilities		—			—		(35	)		(35	)

Total derivatives		—			1,387		(1,264	)		123

Total	$	636		$	1,387	$	(2,080	)	$	(57	)

The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2009:


	Quoted Prices in Active Markets (Level 1)			Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total Fair Value
	($ in millions)

Financial Assets (Liabilities):
Cash equivalents	$	307		$	—		$	—		$	307
Investments		32			—			—			32
Other long-term assets		34			—			—			34
Long-term debt		—			—			(1,398	)		(1,398	)
Other long-term liabilities		(34	)		—			—			(34	)

Derivatives:
Commodity assets		—			693			143			836
Commodity liabilities		—			(1	)		(809	)		(810	)
Interest rate liabilities		—			—			(132	)		(132	)
Foreign currency assets		—			—			43			43

Total derivatives		—			692			(755	)		(63	)

Total	$	339		$	692		$	(2,153	)	$	(1,122	)

Fair Value, Assets and Liabilities, Unobservable Input Reconciliation

A summary of the changes in Chesapeake’s assets (liabilities) classified as Level 3 measurements during the Current Period and the Prior Period is presented below:


	Derivatives
	Commodity			Interest Rate			Foreign Currency			Debt
	($ in millions)

Balance of Level 3 as of January 1, 2010	$	(666	)	$	(132	)	$	43		$	(1,398	)
Total gains (losses) (realized/unrealized):
Included in earnings (realized)^(a)		305			(6	)		—			—
Included in earnings or change in net assets (unrealized)^(a)		(669	)		85			(44	)		32
Included in other comprehensive income (loss)		(18	)		—			(34	)		—
Purchases, issuances and settlements		(142	)		14			—			550	^(b)
Transfers in and out of Level 3		—			—			—			—

Balance of Level 3 as of September 30, 2010	$	(1,190	)	$	(39	)	$	(35	)	$	(816	)


Balance of Level 3 as of January 1, 2009	$	431		$	(63	)	$	(76	)	$	(1,470	)
Total gains (losses) (realized/unrealized):
Included in earnings (realized)^(a)		778			20			—			(128	)
Included in earnings or change in net assets (unrealized)^(a)		(380	)		106			42			—
Included in other comprehensive income (loss)		45			—			78			—
Purchases, issuances and settlements		(835	)		(154	)		—			(450	)^(b)
Transfers in and out of Level 3		—			—			—			—

Balance of Level 3 as of September 30, 2009	$	39		$	(91	)	$	44		$	(2,048	)

(a)	Amounts related to commodity derivatives are included in Natural Gas and Oil Sales, and amounts related to interest rate and foreign currency derivatives and debt are included in Interest Expense.

(b)	Amount represents a(n) (increase)/decrease in debt recorded at fair value as a result of new or terminated interest rate swaps.

Fair Value, by Balance Sheet Grouping

Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.


	September 30, 2010				December 31, 2009
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	($ in millions)

Long-term debt	$	11,409	$	12,295	$	12,226	$	12,824
Convertible preferred stock	$	3,065	$	2,994	$	466	$	401

Condensed Consolidating Financial Information (Tables)

9 Months Ended

Sep. 30, 2010

Condensed Consolidating Balance Sheet

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF SEPTEMBER 30, 2010


	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	($ in millions)

CURRENT ASSETS:
Cash and cash equivalents	$	—		$	587	$	22	$	—		$	609
Other		3			2,549		139		(27	)		2,664

Total Current Assets		3			3,136		161		(27	)		3,273


PROPERTY AND EQUIPMENT:
Natural gas and oil properties, at cost based on full-cost accounting		—			24,649		216		—			24,865
Other property and equipment, net		—			3,029		1,586		—			4,615

Total Property and Equipment		—			27,678		1,802		—			29,480


Other assets		193			715		672		—			1,580
Investments in subsidiaries and intercompany advance		1,356			121		—		(1,477	)		—

TOTAL ASSETS	$	1,552		$	31,650	$	2,635	$	(1,504	)	$	34,333


CURRENT LIABILITIES:
Current liabilities	$	226		$	3,816	$	110	$	(29	)	$	4,123
Intercompany payable (receivable) from parent		(23,340	)		21,214		2,145		(19	)		—

Total Current Liabilities		(23,114	)		25,030		2,255		(48	)		4,123


LONG-TERM LIABILITIES:
Long-term debt, net		8,958			2,237		250		—			11,445
Deferred income tax liabilities		392			1,418		8		21			1,839
Other liabilities		43			1,609		1		—			1,653

Total Long-Term Liabilities		9,393			5,264		259		21			14,937


EQUITY:
Chesapeake stockholders’ equity		15,273			1,356		121		(1,477	)		15,273
Noncontrolling interest		—			—		—		—			—

Total Equity		15,273			1,356		121		(1,477	)		15,273

TOTAL LIABILITIES AND EQUITY	$	1,552		$	31,650	$	2,635	$	(1,504	)	$	34,333

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2009


	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	($ in millions)

CURRENT ASSETS:
Cash and cash equivalents	$	—		$	293	$	14	$	—		$	307
Other		27			2,031		166		(85	)		2,139

Total Current Assets		27			2,324		180		(85	)		2,446


PROPERTY AND EQUIPMENT:
Natural gas and oil properties, at cost based on full-cost accounting		—			20,788		4		—			20,792
Other property and equipment, net		—			2,903		3,015		—			5,918

Total Property and Equipment		—			23,691		3,019		—			26,710


Other assets		197			540		21		—			758
Investments in subsidiaries and intercompany advance		3,029			222		—		(3,251	)		—

TOTAL ASSETS	$	3,253		$	26,777	$	3,220	$	(3,336	)	$	29,914


CURRENT LIABILITIES:
Current liabilities	$	277		$	2,261	$	235	$	(85	)	$	2,688
Intercompany payable (receivable) from parent		(19,388	)		17,508		1,793		87			—

Total Current Liabilities		(19,111	)		19,769		2,028		2			2,688


LONG-TERM LIABILITIES:
Long-term debt, net		10,359			1,892		44		—			12,295
Deferred income tax liabilities		393			727		26		(87	)		1,059
Other liabilities		168			1,360		3		—			1,531

Total Long-Term Liabilities		10,920			3,979		73		(87	)		14,885


EQUITY:
Chesapeake stockholders’ equity		11,444			3,029		222		(3,251	)		11,444
Noncontrolling interest		—			—		897		—			897

Total Equity		11,444			3,029		1,119		(3,251	)		12,341


TOTAL LIABILITIES AND EQUITY	$	3,253		$	26,777	$	3,220	$	(3,336	)	$	29,914

Condensed Consolidating Statement of Operations

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2010


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	($ in millions)

REVENUES:
Natural gas and oil sales	$	—		$	1,639		$	—		$	—		$	1,639
Marketing, gathering and compression sales		—			856			69			(42	)		883
Service operations revenue		—			59			—			—			59

Total Revenues		—			2,554			69			(42	)		2,581


OPERATING COSTS:
Production expenses		—			231			—			—			231
Production taxes		—			34			—			—			34
General and administrative expenses		2			113			10			—			125
Marketing, gathering and compression expenses		—			838			37			(24	)		851
Service operations expense		—			52			—			—			52
Natural gas and oil depreciation, depletion and amortization		—			378			—			—			378
Depreciation and amortization of other assets		—			43			13			—			56
Impairment or loss on sale of property and equipment		—			3			34			—			37

Total Operating Costs		2			1,692			94			(24	)		1,764


INCOME (LOSS) FROM OPERATIONS		(2	)		862			(25	)		(18	)		817


OTHER INCOME (EXPENSE):
Interest (expense) income		(153	)		(16	)		(1	)		167			(3	)
Loss on redemptions or exchanges of Chesapeake debt		(59	)		—			—			—			(59	)
Impairment of investments		—			(16	)		—			—			(16	)
Other income (expense)		167			52			116			(167	)		168
Equity in net earnings of subsidiary		587			44			—			(631	)		—

Total Other Income (Expense)		542			64			115			(631	)		90


INCOME (LOSS) BEFORE INCOME TAXES		540			926			90			(649	)		907
INCOME TAX EXPENSE (BENEFIT)		(18	)		339			35			(7	)		349

NET INCOME (LOSS)		558			587			55			(642	)		558
Net income (loss) attributable to noncontrolling interest		—			—			—			—			—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	558		$	587		$	55		$	(642	)	$	558

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2009


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	($ in millions)
REVENUES:
Natural gas and oil sales	$	—		$	1,187		$	—		$	—		$	1,187
Marketing, gathering and compression sales		—			504			126			(55	)		575
Service operations revenue		—			49			—			—			49

Total Revenues		—			1,740			126			(55	)		1,811

OPERATING COSTS:
Production expenses		—			218			—			—			218
Production taxes		—			25			—			—			25
General and administrative expenses		—			86			9			—			95
Marketing, gathering and compression expenses		—			497			54			(5	)		546
Service operations expense		—			49			—			—			49
Natural gas and oil depreciation, depletion and amortization		—			295			—			—			295
Depreciation and amortization of other assets		1			36			25			—			62
Loss on sale of other property and equipment		—			—			124			—			124

Total Operating Costs		1			1,206			212			(5	)		1,414

INCOME (LOSS) FROM OPERATIONS		(1	)		534			(86	)		(50	)		397

OTHER INCOME (EXPENSE):
Interest (expense) income		(161	)		(57	)		—			175			(43	)
Loss on redemptions or exchanges of Chesapeake debt		(17	)		—			—			—			(17	)
Other income (expense)		175			(24	)		(6	)		(175	)		(30	)
Equity in net earnings of subsidiary		194			(89	)		—			(105	)		—

Total Other Income (Expense)		191			(170	)		(6	)		(105	)		(90	)

INCOME (LOSS) BEFORE INCOME TAXES		190			364			(92	)		(155	)		307
INCOME TAX EXPENSE (BENEFIT)		(2	)		170			(34	)		(19	)		115

NET INCOME (LOSS)		192			194			(58	)		(136	)		192
Net income (loss) attributable to noncontrolling interest		—			—			—			—			—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	192		$	194		$	(58	)	$	(136	)	$	192

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2010


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	($ in millions)
REVENUES:
Natural gas and oil sales	$	—		$	4,698		$	—		$	—		$	4,698
Marketing, gathering and compression sales		—			2,437			179			(96	)		2,520
Service operations revenue		—			173			—			—			173

Total Revenues		—			7,308			179			(96	)		7,391

OPERATING COSTS:
Production expenses		—			652			—			—			652
Production taxes		—			119			—			—			119
General and administrative expenses		2			315			23			—			340
Marketing, gathering and compression expenses		—			2,383			90			(44	)		2,429
Service operations expense		—			154			—			—			154
Natural gas and oil depreciation, depletion and amortization		—			1,025			—			—			1,025
Depreciation and amortization of other assets		—			124			35			—			159
Impairment or loss on sale of property and equipment		—			3			34			—			37

Total Operating Costs		2			4,775			182			(44	)		4,915

INCOME (LOSS) FROM OPERATIONS		(2	)		2,533			(3	)		(52	)		2,476

OTHER INCOME (EXPENSE):
Interest (expense) income		(451	)		(107	)		(3	)		549			(12	)
Loss on redemptions or exchanges of Chesapeake debt		(130	)		—			—			—			(130	)
Impairment of investments		—			(16	)		—			—			(16	)
Other income (expense)		549			52			150			(549	)		202
Equity in net earnings of subsidiary		1,571			57			—			(1,628	)		—

Total Other Income (Expense)		1,539			(14	)		147			(1,628	)		44

INCOME (LOSS) BEFORE INCOME TAXES		1,537			2,519			144			(1,680	)		2,520
INCOME TAX EXPENSE (BENEFIT)		(13	)		948			55			(20	)		970

NET INCOME (LOSS)		1,550			1,571			89			(1,660	)		1,550
Net income (loss) attributable to noncontrolling interest		—			—			—			—			—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	1,550		$	1,571		$	89		$	(1,660	)	$	1,550

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2009


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	($ in millions)
REVENUES:
Natural gas and oil sales	$	—		$	3,681		$	—		$	—		$	3,681
Marketing, gathering and compression sales		—			1,461			354			(155	)		1,660
Service operations revenue		—			139			—			—			139

Total Revenues		—			5,281			354			(155	)		5,480

OPERATING COSTS:
Production expenses		—			670			—			—			670
Production taxes		—			71			—			—			71
General and administrative expenses		—			239			20			—			259
Marketing, gathering and compression expenses		—			1,436			148			(15	)		1,569
Service operations expense		—			136			—			—			136
Natural gas and oil depreciation, depletion and amortization		—			1,037			—			—			1,037
Depreciation and amortization of other assets		—			110			67			—			177
Impairment of natural gas and oil properties		—			9,600			—			—			9,600
Impairment or loss on sale of other property and equipment		—			35			124			—			159
Restructuring costs		—			34			—			—			34

Total Operating Costs		—			13,368			359			(15	)		13,712

INCOME (LOSS) FROM OPERATIONS		—			(8,087	)		(5	)		(140	)		(8,232	)

OTHER INCOME (EXPENSE):
Interest (expense) income		(447	)		(112	)		(5	)		512			(52	)
Loss on redemptions or exchanges of Chesapeake debt		(19	)		—			—			—			(19	)
Impairment of investments		—			(148	)		(14	)		—			(162	)
Other income (expense)		512			(21	)		(4	)		(512	)		(25	)
Equity in net earnings of subsidiary		(5,335	)		(105	)		—			5,440			—

Total Other Income (Expense)		(5,289	)		(386	)		(23	)		5,440			(258	)

INCOME (LOSS) BEFORE INCOME TAXES		(5,289	)		(8,473	)		(28	)		5,300			(8,490	)
INCOME TAX EXPENSE (BENEFIT)		17			(3,138	)		(11	)		(52	)		(3,184	)

NET INCOME (LOSS)		(5,306	)		(5,335	)		(17	)		5,352			(5,306	)
Net income (loss) attributable to noncontrolling interest		—			—			—			—			—

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$	(5,306	)	$	(5,335	)	$	(17	)	$	5,352		$	(5,306	)

Condensed Consolidating Statement of Cash Flows

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2010


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	3,774		$	197		$	—	$	3,971
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to natural gas and oil properties		—			(7,723	)		(212	)		—		(7,935	)
Additions to other property and equipment		—			(412	)		(556	)		—		(968	)
Proceeds from divestitures of natural gas and oil properties		—			3,107			—			—		3,107
Other investing activities		—			—			131			—		131

Cash used in investing activities		—			(5,028	)		(637	)		—		(5,665	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			10,076			382			—		10,458
Payments on credit facilities borrowings		—			(9,736	)		(127	)		—		(9,863	)
Proceeds from preferred stock, net of offering costs		2,562			—			—			—		2,562
Proceeds from issuance of senior notes, net of offering costs		1,967			—			—			—		1,967
Cash paid to redeem Chesapeake debt		(3,434	)		—			—			—		(3,434	)
Other financing activities		(243	)		567			(18	)		—		306
Intercompany advances, net		(852	)		641			211			—		—

Cash provided by (used in) financing activities		—			1,548			448			—		1,996

Net increase (decrease) in cash and cash equivalents		—			294			8			—		302
Cash and cash equivalents, beginning of period		—			293			14			—		307

Cash and cash equivalents, end of period	$	—		$	587		$	22		$	—	$	609

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2009


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	($ in millions)
CASH FLOWS FROM OPERATING ACTIVITIES	$	—		$	3,075		$	56		$	—	$	3,131
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to natural gas and oil properties		—			(4,138	)		—			—		(4,138	)
Additions to other property and equipment		—			(661	)		(701	)		—		(1,362	)
Proceeds from divestitures of natural gas and oil properties		—			1,729			—			—		1,729
Other investing activities		—			78			39			—		117

Cash used in investing activities		—			(2,992	)		(662	)		—		(3,654	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			4,894			669			—		5,563
Payments on credit facilities borrowings		—			(6,749	)		(1,117	)		—		(7,866	)
Proceeds from issuance of senior notes, net of offering costs		1,346			—			—			—		1,346
Proceeds from sales of noncontrolling interest in midstream joint venture		—			—			588			—		588
Other financing activities		(153	)		(167	)		(17	)		—		(337	)
Intercompany advances, net		(1,193	)		554			639			—		—

Cash provided by (used in) financing activities		—			(1,468	)		762			—		(706	)

Net increase (decrease) in cash and cash equivalents		—			(1,385	)		156			—		(1,229	)
Cash and cash equivalents, beginning of period		—			1,749			—			—		1,749

Cash and cash equivalents, end of period	$	—		$	364		$	156		$	—	$	520

Basis of Presentation and Summary of Significant Accounting Policies - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2010 USD ($)
Statement [Line Items]
Adoption of new guidance, after-tax charge	$ 142

Estimated Fair Values of Natural Gas and Oil Derivative Instruments (Detail) $ in Millions	Sep. 30, 2010 USD ($)	Dec. 31, 2009 USD ($)
Statement [Line Items]
Fair Value	$ 197	$ 21
Natural Gas
Statement [Line Items]
Volume Hedged (natural gas (bbtu) and oil (mbbls))	2,085,241	1,657,262
Fair Value	$ 812	$ 130
Natural Gas \| Fixed-price swaps
Statement [Line Items]
Volume Hedged (natural gas (bbtu) and oil (mbbls))	616,190	492,053
Fair Value	$ 1,378	$ 662
Natural Gas \| Fixed-price collars
Statement [Line Items]
Volume Hedged (natural gas (bbtu) and oil (mbbls))	10,980	74,240
Fair Value	$ 37	$ 92
Natural Gas \| Call Options
Statement [Line Items]
Volume Hedged (natural gas (bbtu) and oil (mbbls))	1,333,619	996,750
Fair Value	$ (481)	$ (541)
Natural Gas \| Put Options
Statement [Line Items]
Volume Hedged (natural gas (bbtu) and oil (mbbls))	(58,580)	(69,620)
Fair Value	$ (75)	$ (50)
Natural Gas \| Fixed-price knockout swaps
Statement [Line Items]
Volume Hedged (natural gas (bbtu) and oil (mbbls))	28,530	38,370
Fair Value	$ 5	$ 17
Natural Gas \| Basis protection swaps
Statement [Line Items]
Volume Hedged (natural gas (bbtu) and oil (mbbls))	154,502	125,469
Fair Value	$ (52)	$ (50)
Crude Oil
Statement [Line Items]
Volume Hedged (natural gas (bbtu) and oil (mbbls))	53,326	27,022
Fair Value	$ (615)	$ (109)
Crude Oil \| Fixed-price swaps
Statement [Line Items]
Volume Hedged (natural gas (bbtu) and oil (mbbls))	8,044	5,475
Fair Value	$ (28)	$ 3
Crude Oil \| Call Options
Statement [Line Items]
Volume Hedged (natural gas (bbtu) and oil (mbbls))	42,259	14,975
Fair Value	$ (622)	$ (144)
Crude Oil \| Fixed-price knockout swaps
Statement [Line Items]
Volume Hedged (natural gas (bbtu) and oil (mbbls))	3,023	6,572
Fair Value	$ 35	$ 32

Components of Natural Gas and Oil Sales (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Natural gas and oil sales	$ 1,074	$ 785	$ 3,243	$ 2,280
Realized gains (losses) on natural gas and oil derivatives	512	687	1,484	1,802
Unrealized gains (losses) on non-qualifying natural gas and oil derivatives	48	(278)	(9)	(484)
Unrealized gains (losses) on ineffectiveness of cash flow hedges	5	(7)	(20)	83
Total natural gas and oil sales	$ 1,639	$ 1,187	$ 4,698	$ 3,681

Financial Instruments and Hedging Activities - Additional Information (Detail) € in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2010 USD ($)	Sep. 30, 2009 USD ($)	Dec. 06, 2006 EUR (€)
Statement [Line Items]
Expected amount (net of income taxes) to be transfered of the gain included in the balance in accumulated other comprehensive income to net income (loss) during the next 12 months	$ 188
Natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility, multiplier	1.65
Amount realized over the next ten years for gains and losses related to terminated qualifying interest rate derivative transactions are amortized as an adjustment to interest expense	$ 36
Recognized amount of bad debt expense related to potentially uncollectible receivables		$ 13
6.25% Euro-denominated senior notes due 2017
Statement [Line Items]
Issued 6.25% Euro-denominated Senior Notes due 2017 \| €			€ 600
Euro-denominated debt in notes payable, adjusted value	$ 816
Euro-denominated debt in notes payable, adjusted value, based on exchange rate	$1.3601 to €1.00
Cross Currency Interest Rate Contract \| 6.25% Euro-denominated senior notes due 2017
Statement [Line Items]
Terms of the cross currency swap	Under the terms of the cross currency swap, on each semi-annual interest payment date, the counterparties pay Chesapeake €19 million and Chesapeake pays the counterparties $30 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay Chesapeake €600 million and Chesapeake will pay the counterparties $800 million. The terms of the cross currency swap were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Through the cross currency swap, we have eliminated any potential variability in Chesapeake’s expected cash flows related to changes in foreign exchange rates and therefore the swap qualifies as a cash flow hedge. The fair value of the cross currency swap is recorded on the condensed consolidated balance sheet as a liability of $35 million at Sept ember 30, 2010. The euro-denominated debt in long-term debt has been adjusted to $816 million at September 30, 2010 using an exchange rate of $1.3601 to €1.00.
Fair value of the cross currency swap	$ 35
Multi Counterparty Hedge Facility
Statement [Line Items]
Multi-counterparty hedge facility, committed to provide a trading capacity (in tcfe)	5.6
Multi-counterparty hedge facility, committed to provide an aggregate mark-to-market capacity	$ 15,000
Multi-counterparty hedge facility, hedged total (in tcfe)	2.3

Notional Amount of Debt Hedged and Estimated Fair Value of Interest Rate Derivatives Outstanding (Detail) - USD ($) $ in Millions	Sep. 30, 2010	Dec. 31, 2009
Statement [Line Items]
Notional amount of debt hedged	$ 1,800	$ 3,925
Fair value of interest rate derivatives	(39)	(132)
Fixed-price swaps
Statement [Line Items]
Notional amount of debt hedged	1,300	2,925
Fair value of interest rate derivatives	(13)	(113)
Fixed-price collars
Statement [Line Items]
Notional amount of debt hedged		250
Fair value of interest rate derivatives		(6)
Call Options
Statement [Line Items]
Notional amount of debt hedged	250	250
Fair value of interest rate derivatives	(26)	(2)
Swaptions
Statement [Line Items]
Notional amount of debt hedged	$ 250	500
Fair value of interest rate derivatives		$ (11)

Components of Interest Expense (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Interest expense on senior notes	$ 167	$ 195	$ 550	$ 572
Interest expense on credit facilities	18	18	42	47
Capitalized interest	(185)	(153)	(525)	(467)
Amortization of loan discount and other	3	10	26	25
Total interest expense	3	43	12	52
Unrealized (gains) losses on derivatives			(45)	295
Interest rate derivatives
Statement [Line Items]
Realized (gains) losses on interest rate derivatives	(2)	(7)	(6)	(19)
Unrealized (gains) losses on derivatives	$ 2	$ (20)	$ (75)	$ (106)

Fair Value of Each Classification of Derivative Instrument (Detail) - USD ($) $ in Millions	Sep. 30, 2010	Dec. 31, 2009
Asset Derivatives:
Derivatives designated as hedging instruments, assets	$ 479	$ 496
Derivatives not designated as hedging instruments, assets	1,190	384
Liability Derivatives:
Derivatives designated as hedging instruments, liabilty	(35)	(12)
Derivatives not designated as hedging instruments, liabilty	(1,511)	(931)
Total derivative instruments	123	(63)
Commodity derivatives \| Short-term derivative instruments
Asset Derivatives:
Derivatives designated as hedging instruments, assets	438	417
Derivatives not designated as hedging instruments, assets	794	318
Liability Derivatives:
Derivatives designated as hedging instruments, liabilty		(1)
Derivatives not designated as hedging instruments, liabilty	(145)	(42)
Commodity derivatives \| Long-term derivative instruments
Asset Derivatives:
Derivatives designated as hedging instruments, assets	41	36
Derivatives not designated as hedging instruments, assets	367	66
Liability Derivatives:
Derivatives not designated as hedging instruments, liabilty	(1,298)	(768)
Foreign currency derivatives \| Long-term derivative instruments
Asset Derivatives:
Derivatives designated as hedging instruments, assets		43
Liability Derivatives:
Derivatives designated as hedging instruments, liabilty	(35)
Interest rate derivatives \| Short-term derivative instruments
Liability Derivatives:
Derivatives not designated as hedging instruments, liabilty	(26)	(27)
Interest rate derivatives \| Long-term derivative instruments
Asset Derivatives:
Derivatives not designated as hedging instruments, assets	29
Liability Derivatives:
Derivatives designated as hedging instruments, liabilty		(11)
Derivatives not designated as hedging instruments, liabilty	$ (42)	$ (94)

Gain (Loss) Recognized in Net Income (Loss) for Instruments Designated as Fair Value Derivatives (Detail) - Interest rate derivatives - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2010

Sep. 30, 2009

Sep. 30, 2010

Sep. 30, 2009

Gain (loss) recognized in net income (loss)

$ 2

$ 7

$ 6

$ 19

Fair Value Hedges | Interest Expense

Gain (loss) recognized in net income (loss)

^[1]

$ 3

$ 13

$ 16

$ 31

[1]	Interest expense on items hedged during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period was $0, $33 million, $15 million and $66 million, respectively, which is included in interest expense on the condensed consolidated statements of operations.

Gain (Loss) Recognized in Net Income (Loss) for Instruments Designated as Fair Value Derivatives (Parenthetical) (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Interest expense on the hedged items	$ 0	$ 33	$ 15	$ 66

Pre-Tax Gain (Loss) for Derivative Instruments Designated as Cash Flow Derivatives (Detail) - Cash Flow Hedges - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2010

Sep. 30, 2009

Sep. 30, 2010

Sep. 30, 2009

Gain (Loss) Recognized in AOCI (Effective Portion)

$ 99

$ 108

$ 424

$ 898

Gain (Loss) Reclassified from AOCI (Effective Portion)

179

381

535

994

Gain (Loss) Recognized (Ineffective Portion and Amount Excluded from Effectiveness Testing)

^[1]

(7)

(95)

Commodity derivatives

Gain (Loss) Recognized in AOCI (Effective Portion)

107

458

819

Commodity derivatives | Natural gas and oil sales

Gain (Loss) Reclassified from AOCI (Effective Portion)

179

381

535

994

Gain (Loss) Recognized (Ineffective Portion and Amount Excluded from Effectiveness Testing)

^[1]

(7)

(95)

Foreign currency derivatives

Gain (Loss) Recognized in AOCI (Effective Portion)

$ 5

$ 1

$ (34)

$ 79

[1]

Pre-Tax Gain (Loss) for Derivative Instruments Designated as Cash Flow Derivatives (Parenthetical) (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Gain(loss) reconginzed in net income (loss)	$ 5	$ (7)	$ (20)	$ 83
Gain (loss) related to hedge effectiveness	$ (3)	$ 0	$ (75)	$ 0

Gain (Loss) Recognized in Net Income (Loss) for Instruments Not Qualifying as Cash Flow or Fair Value Derivatives (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Interest rate derivatives
Statement [Line Items]
Gain (loss) recognized in net income (loss)	$ 2	$ 7	$ 6	$ 19
Non-Qualifying Derivatives
Statement [Line Items]
Gain (loss) recognized in net income (loss)	381	42	1,080	418
Non-Qualifying Derivatives \| Commodity derivatives \| Natural gas and oil sales
Statement [Line Items]
Gain (loss) recognized in net income (loss)	384	28	1,015	324
Non-Qualifying Derivatives \| Interest rate derivatives \| Interest Expense
Statement [Line Items]
Gain (loss) recognized in net income (loss)	$ (3)	$ 14	$ 65	$ 94

Contingencies and Commitments - Additional Information (Detail) $ in Millions	9 Months Ended	12 Months Ended	36 Months Ended
	Sep. 30, 2010 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)
Statement [Line Items]
Payments to acquire additional leasehold	$ 1,700
Minimum
Statement [Line Items]
Chesapeake has entered into commitments from July 2010 through September 2021 to deliver to third party midstream companies a total volume (in bcf)	530
Rig Leases
Statement [Line Items]
Entered into a master lease agreement under which we agreed to leaseback from the buyer, proceeds from sale				$ 704
Entered into a master lease agreement under which we agreed to leaseback from the buyer, minimum term (in years)	7
Entered into a master lease agreement under which we agreed to leaseback from the buyer, maximum term (in years)	10
Entered into a master lease agreement under which we agreed to leaseback from the buyer, annual payment		$ 97
Entered into a master lease agreement under which we agreed to leaseback from the buyer, minimum aggregate future lease payments	$ 478
Purchase contract, price of 7 rigs	85
Purchase contract, deposit	9
Purchase contract, remaining commitment	$ 76
Compressor Leases
Statement [Line Items]
Entered into a master lease agreement under which we agreed to leaseback from the buyer, proceeds from sale			$ 517
Entered into a master lease agreement under which we agreed to leaseback from the buyer, minimum term (in years)	4
Entered into a master lease agreement under which we agreed to leaseback from the buyer, maximum term (in years)	10
Entered into a master lease agreement under which we agreed to leaseback from the buyer, annual payment		$ 77
Entered into a master lease agreement under which we agreed to leaseback from the buyer, minimum aggregate future lease payments	$ 441
Drilling Contracts
Statement [Line Items]
Aggregate drilling rig commitment	$ 204

Aggregate Undiscounted Amounts of Demand Payments (Detail) - Transportation Contracts $ in Millions	Sep. 30, 2010 USD ($)
Statement [Line Items]
2010	$ 82
2011	378
2012	378
2013	364
2014	344
2015 - 2099	2,449
Total	$ 3,995

Obligations for Shortfalls in Volumn Commitments of Natural Gas (Detail) - Minimum Volume Commitment	Sep. 30, 2010
Statement [Line Items]
Minimum volume commitment obligations (in Mmcf)	3,142
2010
Statement [Line Items]
Minimum volume commitment obligations (in Mmcf)	129
2011
Statement [Line Items]
Minimum volume commitment obligations (in Mmcf)	313
2012
Statement [Line Items]
Minimum volume commitment obligations (in Mmcf)	325
2013
Statement [Line Items]
Minimum volume commitment obligations (in Mmcf)	338
2014
Statement [Line Items]
Minimum volume commitment obligations (in Mmcf)	351
After 2014
Statement [Line Items]
Minimum volume commitment obligations (in Mmcf)	1,686

Securities And Associated Adjustment To Net Income Not Included In The Calculation Of Diluted Earnings Per Share (Detail) - USD ($) shares in Millions, $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2009	Sep. 30, 2009
Common stock equivalent of preferred stock outstanding \| 5.00% cumulative convertible preferred stock (series 2005B)
Statement [Line Items]
Shares	5	5
Net Income Adjustments	$ 3	$ 8
Common stock equivalent of preferred stock outstanding \| 4.50% cumulative convertible preferred stock
Statement [Line Items]
Shares	6	6
Net Income Adjustments	$ 3	$ 9
Common stock equivalent of preferred stock outstanding prior to conversion \| 6.25% mandatory convertible preferred stock
Statement [Line Items]
Shares		1
Net Income Adjustments		$ 1
Stock Options
Statement [Line Items]
Shares		1
Restricted stock
Statement [Line Items]
Shares		5

Earnings Per Share Reconciliation (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Income (Numerator)
Basic EPS	$ 515	$ 186	$ 1,482	$ (5,324)
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Outstanding stock options
Unvested restricted stock
Diluted EPS	$ 557	$ 186	$ 1,550
Weighted Average Shares (Denominator)
Basic EPS	632	619	631	606
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Outstanding stock options	1	1	1
Unvested restricted stock	4	6	5
Diluted EPS	744	626	692	606
Per Share Amount
Basic EPS	$ 0.81	$ 0.30	$ 2.35	$ (8.78)
Diluted EPS	$ 0.75	$ 0.30	$ 2.24	$ (8.78)
5.75% Cumulative Convertible Preferred Stock
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 4.50% cumulative convertible preferred stock	$ 21		$ 28
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 4.50% cumulative convertible preferred stock	56		24
5.75% (Series A) Cumulative Convertible Preferred Stock
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 4.50% cumulative convertible preferred stock	$ 16		$ 23
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 4.50% cumulative convertible preferred stock	40		20
5.00% cumulative convertible preferred stock (series 2005B)
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 4.50% cumulative convertible preferred stock	$ 2		$ 8
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 4.50% cumulative convertible preferred stock	5		5
4.50% cumulative convertible preferred stock
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 4.50% cumulative convertible preferred stock	$ 3		$ 9
Assumed conversion as of the beginning of the period of preferred shares outstanding during the period:
Common shares assumed issued for 4.50% cumulative convertible preferred stock	6		6

Summary of the Changes in Common Shares Issued (Detail) - shares	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Shares issued at January 1	648,549,165	607,953,000
Restricted stock issuances (net of forfeitures)	6,108,000	3,940,000
Stock option exercises	354,000	429,000
Common stock issued for the purchase of proved and unproved properties		24,822,832
Shares issued at September 30	655,330,601	645,274,000
Convertible Debt
Statement [Line Items]
Convertible note exchanges	299,000	6,707,000
Preferred Stock
Statement [Line Items]
Convertible note exchanges	21,000	1,422,000

Stockholders’ Equity, Restricted Stock and Stock Options - Additional Information (Detail) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010 USD ($) $ / shares shares	Sep. 30, 2009 USD ($)	Sep. 30, 2010 USD ($) $ / shares shares	Sep. 30, 2009 USD ($) shares
Statement [Line Items]
Loss associated with exchanges			$ (29)	$ (19)
Common stock issued for purchase of proved and unproved properties \| shares				24,822,832
Oil and Gas Proved and Unproved Properties
Statement [Line Items]
Common stock issued for purchase of proved and unproved properties \| shares				24,822,832
Common stock value for purchase of proved and unproved properties				$ 429
2.25% contingent convertible senior notes due 2038
Statement [Line Items]
Aggregate principal amount	$ 11	$ 238	$ 11	$ 238
Cumulative Convertible Preferred Stock \| shares			298,500	6,707,321
Exchanged debt for common stock, value			$ 9	$ 164
Debt component	7	148	7	148
Equity conversion feature			4	90
Loss associated with exchanges			$ 2	19
Loss associated with exchanges, deferred charges				3
Restricted stock
Statement [Line Items]
Aggregate intrinsic value of restricted stock vested \| $ / shares			$ 124
Total unrecognized compensation cost related to unvested restricted stock	425		$ 425
Cost expected to be recognized over a weighted average period (in years)			2.40
Reduction in tax benefits related to restricted stock	14	36	$ 15	48
Stock Options
Statement [Line Items]
Recognized excess tax benefits related to stock options	$ 1	$ 1	$ 2	$ 1
5.75% Cumulative Convertible Preferred Stock
Statement [Line Items]
Preferred Stock, issued \| shares	600,000		600,000
Preferred Stock, par value \| $ / shares	$ 0.01		$ 0.01
Preferred Stock, liquidation preference \| $ / shares	$ 1,000		$ 1,000
Net proceeds from Private Placement			$ 594
Additional Preferred Stock
Statement [Line Items]
Preferred Stock, issued \| shares	900,000		900,000
Net proceeds from Private Placement			$ 877
5.75% (Series A) Cumulative Convertible Preferred Stock
Statement [Line Items]
Preferred Stock, issued \| shares	1,100,000		1,100,000
Preferred Stock, par value \| $ / shares	$ 0.01		$ 0.01
Preferred Stock, liquidation preference \| $ / shares	$ 1,000		$ 1,000
Net proceeds from Private Placement			$ 1,091
5.00% cumulative convertible preferred stock (series 2005)
Statement [Line Items]
Cumulative Convertible Preferred Stock \| shares			5,000
Shares of common stock pursuant to mandatory conversion rights \| shares			20,774
6.25% mandatory convertible preferred stock
Statement [Line Items]
Cumulative Convertible Preferred Stock \| shares				143,768
Shares of common stock pursuant to mandatory conversion rights \| shares				1,239,538
4.125% Cumulative Convertible Preferred Stock
Statement [Line Items]
Cumulative Convertible Preferred Stock \| shares				3,033
Shares of common stock pursuant to mandatory conversion rights \| shares				182,887

Summary of the Changes in Preferred Shares Outstanding (Detail) - shares	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009
5.75% Cumulative Convertible Preferred Stock
Statement [Line Items]
Beginning Balance	0
Preferred stock issuances	1,500,000
Ending Balance	1,500,000
5.75% (Series A) Cumulative Convertible Preferred Stock
Statement [Line Items]
Beginning Balance	0
Preferred stock issuances	1,100,000
Ending Balance	1,100,000
4.50% cumulative convertible preferred stock
Statement [Line Items]
Beginning Balance	2,558,900	2,558,900
Ending Balance	2,558,900	2,558,900
5.00% cumulative convertible preferred stock (series 2005B)
Statement [Line Items]
Beginning Balance	2,095,615	2,095,615
Ending Balance	2,095,615	2,095,615
5.00% cumulative convertible preferred stock (series 2005)
Statement [Line Items]
Beginning Balance	5,000	5,000
Conversion of preferred into common stock	(5,000)
Ending Balance	0	5,000
6.25% mandatory convertible preferred stock
Statement [Line Items]
Beginning Balance		143,768
Conversion of preferred into common stock		(143,768)
4.125% Cumulative Convertible Preferred Stock
Statement [Line Items]
Beginning Balance		3,033
Conversion of preferred into common stock		(3,033)

Stock-based Compensation (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Stock-based Compensation (Detail) - USD ($) $ in Millions	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Natural gas and oil properties	$ 30	$ 27	$ 95	$ 85
General and administrative expenses	21	22	63	60
Production expenses	9	8	27	26
Marketing, gathering and compression expenses	5	4	13	12
Service operations expense	2	2	7	6
Restructuring costs				9
Total	$ 67	$ 63	$ 205	$ 198

Changes in Unvested Shares of Restricted Stock (Detail) - Restricted stock shares in Thousands	9 Months Ended
	Sep. 30, 2010 $ / shares shares
Number of Unvested Restricted Shares
Beginning Balance \| shares	19,225
Granted \| shares	8,901
Vested \| shares	(5,332)
Forfeited \| shares	(885)
Ending Balance \| shares	21,909
Weighted-Average Grant-Date Fair Value
Beginning Balance \| $ / shares	$ 31.89
Granted \| $ / shares	24.21
Vested \| $ / shares	32.49
Forfeited \| $ / shares	30.49
Ending Balance \| $ / shares	$ 28.68

Stock Option Activity (Detail)
$ / shares in Units, shares in Thousands, $ in Millions

9 Months Ended

Sep. 30, 2010

USD ($)

$ / shares

Number of Shares Underlying Options

Beginning Balance | shares

2,283

Exercised | shares

(366)

Expired | shares

Ending Balance | shares

1,917

Exercisable at September 30, 2010 | shares

1,917

Weighted Average Exercise Price Per Share

Beginning Balance | $ / shares

$ 8.36

Exercised | $ / shares

6.15

Expired | $ / shares

Ending Balance | $ / shares

8.78

Exercisable at September 30, 2010 | $ / shares

$ 8.78

Weighted Average Contract Life in Years

2.75

Exercisable at September 30, 2010

2.22

2.22

Aggregate Intrinsic Value

Outstanding at January 1, 2010 | $

$ 40

^[1]

Outstanding at September 30, 2010 | $

^[1]

Exercisable at September 30, 2010 | $

$ 27

^[1]

[1]	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

Total Debt (Detail) - USD ($)
$ in Millions

Sep. 30, 2010

Dec. 31, 2009

7.5% senior notes due 2013

$ 11,445

$ 12,295

7.625% senior notes due 2013

364

7.0% senior notes due 2014

500

7.5% senior notes due 2014

300

6.375% senior notes due 2015

300

9.5% senior notes due 2015

600

6.625% senior notes due 2016

1,425

6.875% senior notes due 2016

600

6.25% Euro-denominated senior notes due 2017

670

6.5% senior notes due 2017

^[1]

816

860

6.25% senior notes due 2018

1,100

Senior notes 6.875 percent due 2018

600

7.25% senior notes due 2018

600

Senior notes 6.625 percent due 2020

800

6.875% senior notes due 2020

1,400

2.75% contingent convertible senior notes due 2035

500

2.5% contingent convertible senior notes due 2037

^[2]

451

2.25% contingent convertible senior notes due 2038

^[2]

1,378

Corporate revolving bank credit facility

^[2]

752

763

Midstream revolving bank credit facility

2,237

1,892

Midstream joint venture revolving bank credit facility

250

^[3]

Discount on senior notes

Interest rate derivatives

^[4]

(800)

(921)

^[5]

$ 36

$ 69

[1]	The principal amount shown is based on the dollar/euro exchange rate of $1.3601 to ?1.00 and $1.4332 to ?1.00 as of September 30, 2010 and December 31, 2009, respectively. See Note 2 for information on our related foreign currency derivatives.
[2]	The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date. The notes are convertible, at the holder's option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process. One such triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarter by quarter. In the third quarter of 2010, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes during the specified period and, as a result, the holders do not have the option to convert their notes into cash and common stock in the fourth quarter of 2010 under this provision. The notes are also convertible, at the holder's option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note's conversion value in excess of such principal amount. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years, under certain conditions. We may redeem the convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash. The optional repurchase dates, the common stock price conversion threshold amounts and the ending date of the first six-month period continge nt interest may be payable for the contingent convertible senior notes are as follows: Contingent Convertible Senior Notes Repurchase Dates Common Stock Price Conversion Thresholds Contingent Interest First Payable (if applicable) 2.75% due 2035 November 15, 2015, 2020, 2025, 2030 $ 48.71 May 14, 2016 2.5% due 2037 May 15, 2017, 2022, 2027, 2032 $ 64.26 November 14, 2017 2.25% due 2038 December 15, 2018, 2023, 2028, 2033 $ 107.36 June 14, 2019
[3]	Effective January 1, 2010, our midstream joint venture was no longer consolidated in accordance with the new authoritative guidance. See Notes 1 and 9 for further details.
[4]	Included in this discount is $731 million at September 30, 2010 and $794 million at December 31, 2009 associated with the equity component of our contingent convertible senior notes.
[5]	See Note 2 for discussion related to these instruments.

Total Debt (Parenthetical) (Detail) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2010 USD ($) $ / shares	Dec. 31, 2009 USD ($)
6.25% Euro-denominated senior notes due 2017
Statement [Line Items]
The principal amount of 6.25% Euro-denominated senior notes due 2017 shown is based on the dollar/euro exchange rate per €1.00	1.3601	1.4332
2.75% contingent convertible senior notes due 2035
Statement [Line Items]
Repurchase Dates	November 15, 2015, 2020, 2025, 2030
Common Stock Price Conversion Thresholds	$ 48.71
Contingent Interest First Payable (if applicable)	May 14, 2016
2.5% contingent convertible senior notes due 2037
Statement [Line Items]
Repurchase Dates	May 15, 2017, 2022, 2027, 2032
Common Stock Price Conversion Thresholds	$ 64.26
Contingent Interest First Payable (if applicable)	November 14, 2017
2.25% contingent convertible senior notes due 2038
Statement [Line Items]
Repurchase Dates	December 15, 2018, 2023, 2028, 2033
Common Stock Price Conversion Thresholds	$ 107.36
Contingent Interest First Payable (if applicable)	June 14, 2019
Discount on senior notes
Statement [Line Items]
Discount on senior notes included the equity component of the contingent convertible senior notes \| $	$ 731	$ 794

Debt - Additional Information (Detail)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2010

USD ($)

Sep. 30, 2010

USD ($)

Sep. 30, 2009

USD ($)

Dec. 31, 2009

USD ($)

Recognized loss on redemption

$ 69

Public offering, aggregate principal amount of senior notes

2,000

Public offering, net proceeds

1,967

$ 11,445

$ 12,295

Barnett Shale Area

Real estate financed in 2009

113

Financed real estate surface assets

$ 145

Master lease term

Exercise of option to repurchase assets

Minimum aggregate undiscounted future lease payments were approximately

$ 832

Barnett Shale Area | Minimum

Barnett Shale Area | Maximum

Annual lease payments

$ 15

Barnett Shale Headquarters Fort Worth Texas

Annual lease payments

Financed real estate surface assets

$ 54

Financed approximately $54 million with a five-year term loan with an interest rate of which has a

floating rate of prime plus 275 basis points

Corporate revolving bank credit facility

Borrowings under the facility are secured by

^[1]

$ 3,500

natural gas and oil proved reserves and bear interest at our option at either (i) the greater of the reference rate of Union Bank, N.A. or the federal funds effective rate plus 0.50%, both of which are subject to a margin that varies from 0.00% to 0.75% per annum according to our senior unsecured long-term debt ratings, or (ii) the London Interbank Offered Rate (LIBOR), plus a margin that varies from 1.50% to 2.25% per annum according to our senior unsecured long-term debt ratings.

The unused portion of the facility, commitment fee

0.50%

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 $50 million or more, 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 of Chesapeake and its restricted subsidiaries with an outstanding principal amount in excess of $75 million

Midstream revolving bank credit facility

Borrowings under the facility are secured by

^[2]

$ 300

all of the assets of the wholly owned subsidiaries (the restricted subsidiaries) of Chesapeake Midstream Development, L.P. (CMD), itself a wholly owned subsidiary of Chesapeake, and bear interest at our option at either (i) the greater of the reference rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.75% to 2.25% per annum according to the most recent leverage ratio described below or (ii) the LIBOR plus a margin that varies from 2.75% to 3.25% per annum according to the most recent leverage ratio

The unused portion of the facility, commitment fee

0.50%

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. The midstream credit facility agreement also has cross default provisions that apply to other indebtedness CMD and its restricted subsidiaries may have with an outstanding principal amount in excess of $15 million

2.75% contingent convertible senior notes due 2035

Senior Notes, interest expense

6.86%

2.5% contingent convertible senior notes due 2037

^[3]

$ 451

451

Senior Notes, interest expense

8.00%

2.25% contingent convertible senior notes due 2038

^[3]

1,378

$ 1,378

1,378

Senior Notes, interest expense

8.00%

Aggregate principal amount

$ 11

$ 238

Convertible note exchanges | shares

298,500

6,707,321

Recognized loss associated with privately negotiated exchanges

$ (2)

^[3]

752

763

Senior Notes

Redemption price, plus accrued interest

1,366

Senior notes, maturity date

500

$ 500

Dec. 31, 2013

7.5% senior notes due 2013

364

$ 364

7.5% senior notes due 2014

364

300

6.875% senior notes due 2016

300

670

6.375% senior notes due 2015

670

Redemption price, plus accrued interest

619

Recognized loss on redemption

600

Senior notes 6.875 percent due 2018

600

Public offering, aggregate principal amount of senior notes

600

Senior notes 6.625 percent due 2020

600

Public offering, aggregate principal amount of senior notes

1,400

7.0% senior notes due 2014

1,400

Tender offer, cash payment

245

6.625% senior notes due 2016

300

Tender offer, cash payment

567

6.25% senior notes due 2018

600

Tender offer, cash payment

$ 582

Tender Offer and Redemption

$ 600

Recognized loss on redemption

$ 40

[1]	Borrowers are Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C.
[2]	Borrower is Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of Chesapeake Midstream Development, L.P.
[3]	The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date. The notes are convertible, at the holder's option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process. One such triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarter by quarter. In the third quarter of 2010, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes during the specified period and, as a result, the holders do not have the option to convert their notes into cash and common stock in the fourth quarter of 2010 under this provision. The notes are also convertible, at the holder's option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note's conversion value in excess of such principal amount. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years, under certain conditions. We may redeem the convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash. The optional repurchase dates, the common stock price conversion threshold amounts and the ending date of the first six-month period continge nt interest may be payable for the contingent convertible senior notes are as follows: Contingent Convertible Senior Notes Repurchase Dates Common Stock Price Conversion Thresholds Contingent Interest First Payable (if applicable) 2.75% due 2035 November 15, 2015, 2020, 2025, 2030 $ 48.71 May 14, 2016 2.5% due 2037 May 15, 2017, 2022, 2027, 2032 $ 64.26 November 14, 2017 2.25% due 2038 December 15, 2018, 2023, 2028, 2033 $ 107.36 June 14, 2019

Utilized Bank Credit Facilities as Sources of Liquidity (Detail)
$ in Millions

9 Months Ended

Sep. 30, 2010

USD ($)

Corporate revolving bank credit facility

Amount outstanding as of September 30, 2010

$ 3,500

^[1]

Maturity date

November 2012

^[1]

Facility structure

Senior secured revolving

^[1]

$ 2,237

^[1]

Letters of credit outstanding as of September 30, 2010

^[1]

Midstream revolving bank credit facility

Amount outstanding as of September 30, 2010

$ 300

^[2]

Maturity date

July 2015

^[2]

Facility structure

Senior secured revolving

^[2]

$ 250

^[2]

[1]	Borrowers are Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C.
[2]	Borrower is Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of Chesapeake Midstream Development, L.P.

Utilized Bank Credit Facilities as Sources of Liquidity (Parenthetical) (Detail)	9 Months Ended
	Sep. 30, 2010
Corporate revolving bank credit facility
Statement [Line Items]
Borrowers	Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C.
Midstream revolving bank credit facility
Statement [Line Items]
Borrowers	Borrower is Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of Chesapeake Midstream Development, L.P. Certain terms of the credit agreement for this facility were amended on August 2, 2010.

Segment Information - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009
Midstream Activities
Statement [Line Items]
Exploration and production revenues	$ 1,045	$ 716	$ 2,978	$ 2,009

Financial Information for Chesapeake's Operating Segments (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009	Sep. 30, 2010	Sep. 30, 2009	Dec. 31, 2009
Statement [Line Items]
Revenues	$ 2,581	$ 1,811	$ 7,391	$ 5,480
Total Revenues	2,581	1,811	7,391	5,480
Income (loss) before income taxes	907	307	2,520	(8,490)
Total assets	34,333		34,333		$ 29,914
Exploration and Production
Statement [Line Items]
Revenues	1,639	1,187	4,698	3,681
Total Revenues	1,639	1,187	4,698	3,681
Income (loss) before income taxes	822	431	2,401	(8,354)
Total assets	30,945		30,945		25,637
Midstream Activities
Statement [Line Items]
Revenues	1,928	1,291	5,498	3,669
Intersegment revenues	(1,045)	(716)	(2,978)	(2,009)
Total Revenues	883	575	2,520	1,660
Income (loss) before income taxes	96	(111)	152	(82)
Total assets	3,481		3,481		4,323
Other Operations
Statement [Line Items]
Revenues	187	69	538	338
Intersegment revenues	(128)	(20)	(365)	(199)
Total Revenues	59	49	173	139
Income (loss) before income taxes	(7)	(19)	(32)	(53)
Total assets	721		721		660
Intercompany Eliminations
Statement [Line Items]
Revenues	(1,173)	(736)	(3,343)	(2,208)
Intersegment revenues	1,173	736	3,343	2,208
Income (loss) before income taxes	(4)	$ 6	(1)	$ (1)
Total assets	$ (814)		$ (814)		$ (706)

Divestitures - Additional Information (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Benefit received from drilling carries associated with Joint Ventures	$ 745	$ 959
Proceeds from sale of producing properties and gathering systems	3,107	$ 1,729
Barnett Shale Joint Venture
Statement [Line Items]
Barnett Shale joint venture transaction value	$ 2,250
Total E&P USA, Inc. acquired interest in upstream Barnett Shale assets, percentage sold	25.00%
Joint venture transaction, interest acquired	In January 2010, Chesapeake and Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP) (Total), closed a $2.25 billion Barnett Shale joint venture transaction, whereby Total acquired a 25% interest in our upstream Barnett Shale assets. Total paid us approximately $800 million in cash at closing and will pay a further $1.45 billion over time by funding 60% of our share of future drilling and completion expenditures. We expect this drilling carry to be fully utilized by year-end 2012.
Total E&P USA, Inc. acquired interest in upstream Barnett Shale assets, amount received	$ 800
Drilling and completion carries due	78
Total E&P USA, Inc. acquired interest in upstream Barnett Shale assets, future amounts receivable	$ 1,450
Percent share of future drilling and completion expenditures funded by Total	60.00%
Benefit received from drilling carries associated with Joint Ventures	$ 349
Proceeds from sale of long-lived producing assets	$ 1,150
Proceeds from sale of long-lived producing assets, per unit (mcfe)	2.93
Statoil Joint Venture
Statement [Line Items]
Proceeds from sale of leasehold	$ 395
East Texas and Texas Gulf Coast
Statement [Line Items]
Proceeds from sale of long-lived producing assets	$ 180
Proceeds from sale of long-lived producing assets, per unit (mcfe)	3.95
Permian Basin
Statement [Line Items]
Proceeds from sale of long-lived producing assets	$ 335
Proceeds from sale of long-lived producing assets, per unit (mcfe)	8.73
Virginia and Permian Basin
Statement [Line Items]
Proceeds from sale of producing properties and gathering systems	$ 330

Drilling and Completion Costs Associated with Shale Play Joint Ventures (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Benefit received from drilling carries associated with Joint Ventures	$ 745	$ 959
Barnett Shale Joint Venture
Statement [Line Items]
Joint Venture Partner	Total
Joint Venture Date	January 2010
Benefit received from drilling carries associated with Joint Ventures	$ 349
Marcellus Joint Venture
Statement [Line Items]
Joint Venture Partner	Statoil
Joint Venture Date	November 2008
Benefit received from drilling carries associated with Joint Ventures	$ 396	85
Fayetteville Joint Venture
Statement [Line Items]
Joint Venture Partner	BP
Joint Venture Date	September 2008
Benefit received from drilling carries associated with Joint Ventures		524
Haynesville Joint Venture
Statement [Line Items]
Joint Venture Partner	Plains
Joint Venture Date	July 2008
Benefit received from drilling carries associated with Joint Ventures		$ 350

Investments - Additional Information (Detail) $ / shares in Units, $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2010 USD ($) $ / shares shares	Sep. 30, 2010 USD ($) $ / shares shares
Statement [Line Items]
Investments accounted for under the equity method	$ 1,160	$ 1,160
Investments accounted for under the cost method	$ 29	29
Adoption of new guidance, after-tax charge		$ 142
Chesapeake Midstream Partners LLC
Statement [Line Items]
Precentage sold to GIP	50.00%	50.00%
Adoption of new guidance, after-tax charge		$ 142
Cash distribution from the joint venture		75
Excess carrying value of investment over underlying equity in net assets	$ 240	$ 240
Chesapeake Midstream Partners, L.P., ownership structure	In connection with the closing of the offering, Chesapeake and GIP contributed the interests of the midstream joint venture's operating subsidiary to CHKM, and CHKM is continuing the business that had been conducted by the joint venture. Common units owned by public security holders represent 17.7% of all outstanding limited partner interests, and Chesapeake and GIP hold 42.3% and 40.0%, respectively, of all outstanding limited partner interests. The limited partners, collectively, have a 98.0% interest in CHKM and the general partner, which is owned and controlled 50/50 by Chesapeake and GIP, has a 2.0% interest in CHKM.
Gain on investment	$ 90
Chesapeake Midstream Partners LLC \| Limited Partner
Statement [Line Items]
Initial public offering of Chesapeake Midstream Partners, L.P. \| shares	24,437,500
Chesapeake Midstream Partners LLC \| Common Units
Statement [Line Items]
Initial public offering of common units pursuant to exercise of underwriters' over-allotment option \| shares	3,187,500	3,187,500
Gross offering proceeds	$ 513	$ 513
Initial offering price, per unit \| $ / shares	$ 21.00	$ 21.00
Underwriting discounts and commissions, structuring fees and offering expenses	$ 38	$ 38
Net proceeds from the exercise of the over-allotment option	62
CMP Midstream Joint Venture
Statement [Line Items]
Accretion period for the difference between the carrying value of our investment in CMP and the underlying equity in net assets (in years)		20
Frac Tech Services, LLC
Statement [Line Items]
Excess carrying value of investment over underlying equity in net assets	190	$ 190
Chaparral Energy Inc.
Statement [Line Items]
Excess carrying value of investment over underlying equity in net assets	61	$ 61
Gain on investment	$ 31

Equity and Cost Method Investment (Detail) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2010

Sep. 30, 2009

Dec. 31, 2009

Cost Method Carrying Value

$ 29

Long-term Investments, Total

1,160

^[1]

1,189

$ 404

Impairment of certain equity investments

$ 16

$ 162

Chesapeake Midstream Partners LLC

Equity Method Percentage Owned

42.00%

$ 666

Frac Tech Services, LLC

Equity Method Percentage Owned

26.00%

$ 347

239

Chaparral Energy Inc.

Equity Method Percentage Owned

20.00%

$ 137

103

Gastar Exploration Ltd.

Cost Method Percentage Owned

14.00%

Cost Method Carrying Value

$ 27

Other

Cost/Equity Method Percentage Owned

Cost/Equity Method Carrying Value

$ 12

$ 30

Impairment of certain equity investments

$ 16

[1]	In the Current Quarter, we recorded a $16 million impairment of certain other equity investments.

Restructuring Cost (Detail) - USD ($) $ in Millions	9 Months Ended
Restructuring Cost (Detail) - USD ($) $ in Millions	Sep. 30, 2010	Sep. 30, 2009
Statement [Line Items]
Total Restructuring Costs	$ 34	$ 34
Termination and relocation costs
Statement [Line Items]
Total Restructuring Costs	22
Acceleration of restricted stock awards
Statement [Line Items]
Total Restructuring Costs	9
Other associated costs
Statement [Line Items]
Total Restructuring Costs	$ 3

Fair Value Measurement Information for Financial Assets (Liabilities) Measured at Fair Value on a Recurring Basis (Detail) - USD ($) $ in Millions	Sep. 30, 2010	Dec. 31, 2009
Financial Assets (Liabilities):
Cash equivalents	$ 609	$ 307
Investments	27	32
Other long-term assets	42	34
Long-term debt	(816)	(1,398)
Other long-term liabilities	(42)	(34)
Derivatives	123	(63)
Total	(57)	(1,122)
Commodity derivatives
Financial Assets (Liabilities):
Derivatives assets	1,642	836
Derivatives liabilities	(1,445)	(810)
Interest rate derivatives
Financial Assets (Liabilities):
Derivatives assets	29
Derivatives liabilities	(68)	(132)
Foreign currency derivatives
Financial Assets (Liabilities):
Derivatives liabilities	(35)	43
Quoted Prices in Active Markets (Level 1)
Financial Assets (Liabilities):
Cash equivalents	609	307
Investments	27	32
Other long-term assets	42	34
Other long-term liabilities	(42)	(34)
Total	636	339
Significant Other Observable Inputs (Level 2)
Financial Assets (Liabilities):
Derivatives	1,387	692
Total	1,387	692
Significant Other Observable Inputs (Level 2) \| Commodity derivatives
Financial Assets (Liabilities):
Derivatives assets	1,387	693
Derivatives liabilities		(1)
Significant Unobservable Inputs (Level 3)
Financial Assets (Liabilities):
Long-term debt	(816)	(1,398)
Derivatives	(1,264)	(755)
Total	(2,080)	(2,153)
Significant Unobservable Inputs (Level 3) \| Commodity derivatives
Financial Assets (Liabilities):
Derivatives assets	255	143
Derivatives liabilities	(1,445)	(809)
Significant Unobservable Inputs (Level 3) \| Interest rate derivatives
Financial Assets (Liabilities):
Derivatives assets	29
Derivatives liabilities	(68)	(132)
Significant Unobservable Inputs (Level 3) \| Foreign currency derivatives
Financial Assets (Liabilities):
Derivatives liabilities	$ (35)	$ 43

Summary of the Changes in Chesapeake's Assets (Liabilities) Classified as Level 3 Measurements During the Current Period and Prior Period (Detail) - USD ($)
$ in Millions

9 Months Ended

Sep. 30, 2010

Sep. 30, 2009

Commodity derivatives

$ (666)

$ 431

Included in earnings (realized)

^[1]

305

778

Included in earnings or change in net assets (unrealized)

^[1]

(669)

(380)

Included in other comprehensive income (loss)

(18)

Purchases, issuances and settlements

(142)

(835)

Interest rate derivatives

(1,190)

(132)

(63)

Included in earnings (realized)

^[1]

(6)

Included in earnings or change in net assets (unrealized)

^[1]

106

Purchases, issuances and settlements

(154)

Foreign currency derivatives

(39)

(91)

(76)

Included in earnings or change in net assets (unrealized)

^[1]

(44)

Included in other comprehensive income (loss)

(34)

(35)

Debt

(1,398)

(1,470)

Included in earnings (realized)

^[1]

(128)

Included in earnings or change in net assets (unrealized)

^[1]

Purchases, issuances and settlements

^[2]

550

(450)