Chesapeake Energy (CHK) 10-K 27 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 09, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	CHK
Entity Registrant Name	CHESAPEAKE ENERGY CORP
Entity Central Index Key	895126
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		665,038,368
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$20.50

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
CURRENT ASSETS:
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$4,108	$837
Restricted cash	38	75
Accounts receivable, net	2,236	2,222
Short-term derivative assets ($16 and $0 attributable to our VIE)	879	0
Deferred income tax asset	0	223
Other current assets	207	299
Total Current Assets	7,468	3,656
Oil and natural gas properties, at cost based on full cost accounting:
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	58,594	56,157
Unproved properties	9,788	12,013
Oilfield services equipment	0	2,192
Other property and equipment	3,083	3,203
Total Property and Equipment, at Cost	71,465	73,565
Less: accumulated depreciation, depletion and amortization (($251) and ($168) attributable to our VIE)	-39,043	-37,161
Property and equipment held for sale, net	93	730
Total Property and Equipment, Net	32,515	37,134
LONG-TERM ASSETS:
Investments	265	477
Long-term derivative assets	6	4
Other long-term assets	497	511
TOTAL ASSETS	40,751	41,782
CURRENT LIABILITIES:
Accounts payable	2,049	1,596
Current maturities of long-term debt, net	381	0
Accrued interest	150	200
Deferred income tax liabilities	207	0
Short-term derivative liabilities ($0 and $5 attributable to our VIE)	15	208
Other current liabilities ($15 and $22 attributable to our VIE)	3,061	3,511
Total Current Liabilities	5,863	5,515
LONG-TERM LIABILITIES:
Long-term debt, net	11,154	12,886
Deferred income tax liabilities	4,185	3,407
Long-term derivative liabilities	218	445
Asset retirement obligations, net of current portion	447	405
Other long-term liabilities	679	984
Total Long-Term Liabilities	16,683	18,127
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 7,251,515 shares outstanding	3,062	3,062
Common stock, $0.01 par value, 1,000,000,000 shares authorized: 664,944,232 and 666,192,371 shares issued	7	7
Paid-in capital	12,531	12,446
Retained earnings	1,483	688
Accumulated other comprehensive loss	-143	-162
Less: treasury stock, at cost; 1,614,312 and 2,002,029 common shares	-37	-46
Total Chesapeake Stockholders’ Equity	16,903	15,995
Noncontrolling interests	1,302	2,145
Total Equity	18,205	18,140
TOTAL LIABILITIES AND EQUITY	$40,751	$41,782

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Preferred stock, par value (usd per share)	$0.01	$0.01
Preferred stock, shares authorized (shares)	20,000,000	20,000,000
Preferred stock, shares outstanding (shares)	7,251,515	7,251,515
Common stock, par value (usd per share)	$0.01	$0.01
Common Stock, Shares Authorized	1,000,000,000	1,000,000,000
Common Stock, Shares, Issued	664,944,232	666,192,371
Treasury stock, shares	1,614,312	2,002,029
Cash and cash equivalents	$4,108	$837
Short-term derivative assets ($16 and $0 attributable to our VIE)	879	0
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	58,594	56,157
Less: accumulated depreciation, depletion and amortization (($251) and ($168) attributable to our VIE)	-39,043	-37,161
Short-term derivative liabilities ($0 and $5 attributable to our VIE)	15	208
Other current liabilities ($15 and $22 attributable to our VIE)	3,061	3,511
Variable Interest Entities, Primary Beneficiary [Member]
Cash and cash equivalents	1	1
Short-term derivative assets ($16 and $0 attributable to our VIE)	16	0
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	488	488
Less: accumulated depreciation, depletion and amortization (($251) and ($168) attributable to our VIE)	-251	-168
Short-term derivative liabilities ($0 and $5 attributable to our VIE)	0	5
Other current liabilities ($15 and $22 attributable to our VIE)	$15	$22

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES:
Oil, natural gas and NGL	$8,180	$7,052	$6,278
Marketing, gathering and compression	12,225	9,559	5,431
Oilfield services	546	895	607
Total Revenues	20,951	17,506	12,316
OPERATING EXPENSES:
Oil, natural gas and NGL production	1,208	1,159	1,304
Production taxes	232	229	188
Marketing, gathering and compression	12,236	9,461	5,312
Oilfield services	431	736	465
General and administrative	322	457	535
Restructuring and other termination costs	7	248	7
Provision for legal contingencies	234	0	0
Oil, natural gas and NGL depreciation, depletion and amortization	2,683	2,589	2,507
Depreciation and amortization of other assets	232	314	304
Impairment of oil and natural gas properties	0	0	3,315
Impairments of fixed assets and other	88	546	340
Net gains on sales of fixed assets	-199	-302	-267
Total Operating Expenses	17,474	15,437	14,010
INCOME (LOSS) FROM OPERATIONS	3,477	2,069	-1,694
OTHER INCOME (EXPENSE):
Interest expense	-89	-227	-77
Losses on investments	80	226	103
Net gain (loss) on sales of investments	67	-7	1,092
Losses on purchases of debt	-197	-193	-200
Other income	22	26	8
Total Other Income (Expense)	-277	-627	720
INCOME (LOSS) BEFORE INCOME TAXES	3,200	1,442	-974
INCOME TAX EXPENSE (BENEFIT):
Current income taxes	47	22	47
Deferred income taxes	1,097	526	-427
Total Income Tax Expense (Benefit)	1,144	548	-380
NET INCOME (LOSS)	2,056	894	-594
Net income attributable to noncontrolling interests	-139	-170	-175
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	1,917	724	-769
Preferred stock dividends	-171	-171	-171
Redemption of preferred shares of a subsidiary	-447	-69	0
Earnings allocated to participating securities	-26	-10	0
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$1,273	$474	($940)
EARNINGS (LOSS) PER COMMON SHARE:
Earnings Per Share, Basic	$1.93	$0.73	($1.46)
Earnings Per Share, Diluted	$1.87	$0.73	($1.46)
CASH DIVIDEND DECLARED PER COMMON SHARE	$0.35	$0.35	$0.35
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Weighted Average Number of Shares Outstanding, Basic	659	653	643
Weighted Average Number of Shares Outstanding, Diluted	772	653	643

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
NET INCOME (LOSS)	$2,056	$894	($594)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:
Unrealized gain on derivative instruments, net of income tax expense of $0, $1 and $4	1	2	6
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $14, $12 and ($10)	23	20	-17
Unrealized loss on investments, net of income tax benefit of $0, ($4) and ($4)	0	-6	-5
Reclassification of (gain) loss on investment, net of income tax expense of ($3), $3 and $0	-5	4	0
Other Comprehensive Income (Loss)	19	20	-16
COMPREHENSIVE INCOME (LOSS)	2,075	914	-610
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	-139	-170	-175
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$1,936	$744	($785)

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Unrealized gain on derivative instruments, net of income tax expense of $0, $1 and $4	$0	$1	$4
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $12 million, ($10) million and ($139) million	14	12	-10
Unrealized loss on investments, net of income tax benefit of $0, ($4) and ($4)	0	-4	-4
Reclassification of (gain) loss on investment, net of income tax expense (benefit) of $3 million, $0 and $0	($3)	$3	$0

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$2,056	$894	($594)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	2,915	2,903	2,811
Deferred income tax expense (benefit)	1,097	526	-427
Derivative gains, net	-1,102	-71	-926
Cash (payments) receipts on derivative settlements, net	-253	-104	226
Stock-based compensation	59	98	120
Impairment of oil and natural gas properties	0	0	3,315
Net gains on sales of fixed assets	-199	-302	-267
Impairment of fixed assets and other	58	483	316
Losses on investments	80	229	164
Net (gains) losses on sales of investments	-67	7	-1,092
Restructuring and other termination costs	-15	175	2
Provision for legal contingencies	234	0	0
Losses on purchases of debt	63	40	200
Other	100	80	72
(Increase) decrease in accounts receivable and other assets	-21	5	-68
Decrease in accounts payable, accrued liabilities and other	-371	-349	-1,015
Net Cash Provided By Operating Activities	4,634	4,614	2,837
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	-4,581	-5,604	-8,930
Acquisitions of proved and unproved properties	-1,311	-1,032	-3,161
Proceeds from divestitures of proved and unproved properties	5,813	3,467	5,884
Additions to other property and equipment	-726	-972	-2,651
Proceeds from sales of other property and equipment	1,003	922	2,492
Additions to investments	-17	-44	-395
Proceeds from sales of investments	239	115	2,000
Decrease (increase) in restricted cash	37	177	-222
Other	-3	4	-1
Net Cash Provided By (Used In) Investing Activities	454	-2,967	-4,984
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	7,406	7,669	20,318
Payments on credit facilities borrowings	-7,788	-7,682	-21,650
Proceeds from issuance of senior notes, net of discount and offering costs	3,460
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs	3,460
Proceeds from issuance of term loan, net of issuance costs	394
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	394
Cash paid to purchase debt	-3,362	-2,141	-4,000
Cash paid for common stock dividends	-234	-233	-227
Cash paid for preferred stock dividends	-171	-171	-171
Cash paid to extinguish other financing	0	-141	0
Cash paid on financing derivatives	-53	-91	-37
Cash paid for prepayment of mortgage	0	-55	0
Proceeds from sales of noncontrolling interests	0	6	1,077
Proceeds from other financings	0	0	257
Cash paid to purchase preferred shares of a subsidiary	-1,254	-212	0
Cash held and retained by SSE at spin-off	-8	0	0
Distributions to noncontrolling interest owners	-173	-215	-218
Other	-34	-105	-251
Net Cash Provided By (Used In) Financing Activities	-1,817	-1,097	2,083
Net increase (decrease) in cash and cash equivalents	3,271	550	-64
Cash and cash equivalents, beginning of period	837	287	351
Cash and cash equivalents, end of period	4,108	837	287
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	96	43	0
Income taxes paid, net of refunds received	10	26	44
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in accrued drilling and completion costs	-84	-63	-75
Change in accrued acquisitions of proved and unproved properties	-74	-1	242
Change in accrued additions to other property and equipment	-11	-81	-25
Chesapeake Energy [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior notes, net of discount and offering costs	2,966	2,274	1,263
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs	2,966	2,274	1,263
Proceeds from issuance of term loan, net of issuance costs			5,722
Proceeds from issuance of oilfield services term loan, net of discount and offering costs			5,722
Chesapeake Oilfield Operating [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior notes, net of discount and offering costs	494	0	0
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs	494	0	0
Proceeds from issuance of term loan, net of issuance costs	394	0	0
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	$394	$0	$0

CONSOLIDATED_STATEMENTS_OF_STO

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (USD $)	Total	Preferred Stock [Member]	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock - Common [Member]	Parent [Member]	Noncontrolling Interest [Member]
In Millions, unless otherwise specified
Stockholders' Equity Attributable to Noncontrolling Interest, Period Start at Dec. 31, 2011									$1,337
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2011				12,146	1,608	-166	-33
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation				174
Exercise of stock options				3
Increase (decrease) in tax benefit from stock-based compensation				-30
Net income (loss) attributable to Chesapeake	-769
Dividends on common stock	-231
Dividends on preferred stock	-171
Spin-off of oilfield services business (Note 13)	0
Redemption of preferred shares of a subsidiary	0
Hedging activity						-11
Investment activity						-5
Purchase of 34,678, 251,403 and 652,443 shares for company benefit plans							-16
Release of 422,395, 397,098 and 57,252 shares from company benefit plans							1
Sales of noncontrolling interests									1,077
Net income attributable to noncontrolling interests	175								175
Distributions to noncontrolling interest owners									-218
Redemption of preferred shares of a subsidiary									0
Deconsolidation of investments, net									-44
Total Equity	17,896
Stockholders' Equity Attributable to Noncontrolling Interest, Period End at Dec. 31, 2012									2,327
Chesapeake stockholders’ equity, end of period at Dec. 31, 2012		3,062	7	12,293	437	-182	-48	15,569
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation				162
Exercise of stock options				4
Increase (decrease) in tax benefit from stock-based compensation				-13
Net income (loss) attributable to Chesapeake	724
Dividends on common stock	-233
Dividends on preferred stock	-171
Spin-off of oilfield services business (Note 13)	0
Redemption of preferred shares of a subsidiary	-69
Hedging activity						22
Investment activity						-2
Purchase of 34,678, 251,403 and 652,443 shares for company benefit plans							-6
Release of 422,395, 397,098 and 57,252 shares from company benefit plans							8
Sales of noncontrolling interests									6
Net income attributable to noncontrolling interests	170								170
Distributions to noncontrolling interest owners									-215
Redemption of preferred shares of a subsidiary									-143
Deconsolidation of investments, net									0
Total Equity	18,140
Stockholders' Equity Attributable to Noncontrolling Interest, Period End at Dec. 31, 2013	2,145								2,145
Chesapeake stockholders’ equity, end of period at Dec. 31, 2013	15,995	3,062	7	12,446	688	-162	-46	15,995
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation				47
Exercise of stock options				23
Increase (decrease) in tax benefit from stock-based compensation				15
Net income (loss) attributable to Chesapeake	1,917
Dividends on common stock	-234
Dividends on preferred stock	-171
Spin-off of oilfield services business (Note 13)	-270
Redemption of preferred shares of a subsidiary	-447
Hedging activity						24
Investment activity						-5
Purchase of 34,678, 251,403 and 652,443 shares for company benefit plans							-1
Release of 422,395, 397,098 and 57,252 shares from company benefit plans							10
Sales of noncontrolling interests									0
Net income attributable to noncontrolling interests	139								139
Distributions to noncontrolling interest owners									-169
Redemption of preferred shares of a subsidiary									-807
Deconsolidation of investments, net									-6
Total Equity	18,205
Stockholders' Equity Attributable to Noncontrolling Interest, Period End at Dec. 31, 2014	1,302								1,302
Chesapeake stockholders’ equity, end of period at Dec. 31, 2014	$16,903	$3,062	$7	$12,531	$1,483	($143)	($37)	$16,903

CONSOLIDATED_STATEMENTS_OF_STO1

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) (Treasury Stock - Common [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Treasury Stock - Common [Member]
Purchase of shares for company benefit plans, shares	34,678	251,403	652,443
Release of shares from company benefit plans, shares	422,395	397,098	57,252

Basis_of_Presentation_and_Summ

Basis of Presentation and Summary of Significant Accounting Policies (Note)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Organization, Consolidation, Basis of Presentation, Business Description and Accounting Policies [Text Block]

Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

Chesapeake Energy Corporation ("Chesapeake" or the "Company") is an oil and natural gas exploration and production company engaged in the acquisition, exploration and development of properties for the production of oil, natural gas and natural gas liquids (NGL) from underground reservoirs. We also own oil and natural gas marketing and natural gas gathering and compression businesses, and prior to June 30, 2014, an oilfield services business (see Note 13). Our operations are located onshore in the United States.

Basis of Presentation

The accompanying consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated.

Accounting Estimates

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

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates.

Consolidation

Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Investments in securities not accounted for under the equity method have been designated as available-for-sale and, as such, are carried at fair value whenever this value is readily determinable. Otherwise, the investment is carried at cost. See Note 14 for further discussion of our investments. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis.

Noncontrolling Interests

Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests.

Variable Interest Entities

VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both our consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs.

Cash and Cash Equivalents and Restricted Cash

For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. Restricted cash consists of the balance required to be maintained by the terms of the agreement governing the activities of CHK Cleveland Tonkawa, L.L.C. (CHK C-T) and, prior to our repurchase of all of the outstanding preferred shares of CHK Utica, L.L.C. (CHK Utica) in 2014, also consisted of a balance required to be maintained by the terms of the agreement governing the activities of CHK Utica. The repurchase of outstanding preferred shares of CHK Utica eliminated the restricted cash maintenance requirement related to this entity. See Note 8 for further discussion of these entities.

Accounts Receivable

Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables we believe may be uncollectible. During 2014, 2013 and 2012, we recognized $2 million, $2 million and a nominal amount of bad debt expense related to potentially uncollectible receivables, and we reduced our allowance by $3 million in 2013 as we wrote off specific receivables against our allowance. Accounts receivable as of December 31, 2014 and 2013 are detailed below.

December 31,

2014

2013

($ in millions)

Oil, natural gas and NGL sales

$

1,340

$

1,548

Joint interest

691

417

Oilfield services(a)

—

63

Related parties(b)

—

62

Other

226

150

Allowance for doubtful accounts

(21

)

(18

)

Total accounts receivable, net

$

2,236

$

2,222

___________________________________________

(a)

In 2014, in connection with the spin-off of our oilfield services business, accounts receivable related to oilfield services were removed from our consolidated balance sheet.

(b)

See Note 7 for discussion of related party transactions.

Oil and Natural Gas Properties

Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information - Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. Estimates of our proved reserves as of December 31, 2014 were prepared by independent engineering firms and Chesapeake's internal staff. Approximately 79% of these proved reserves estimates (by volume) as of December 31, 2014 were prepared by independent engineering firms. In addition, our internal engineers review and update our reserves on a quarterly basis.

Proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized.

The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties leasehold that can be associated with proved reserves, leasehold that expired in the quarter or leasehold that is not a part of our development strategy and will be abandoned.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2014 and the year in which the associated costs were incurred.

Year of Acquisition

2014

2013

2012

Prior

Total

($ in millions)

Leasehold acquisition cost

$

577

$

199

$

1,462

$

5,149

$

7,387

Exploration cost

340

90

244

42

716

Capitalized interest

492

421

325

447

1,685

Total

$

1,409

$

710

$

2,031

$

5,638

$

9,788

We also review, on a quarterly basis, the carrying value of our oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission (SEC). This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for oil and natural gas derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of oil, natural gas and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2014, none of our open derivative instruments were designated as cash flow hedges. Our oil and natural gas hedging activities are discussed in Note 11.

Two primary factors impacting the ceiling test are reserves levels and oil, natural gas and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an extended increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value over the ceiling is written off as an expense.

We account for seismic costs as part of our oil and natural gas properties. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. These costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred.

Other Property and Equipment

Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computer and office equipment, oil and natural gas gathering systems and treating plants. We have no remaining oilfield services equipment as a result of the spin-off of our oilfield services business in 2014 as discussed in Note 13, and substantially all of our natural gas gathering systems and treating plants were sold in 2013 and 2012 as discussed in Note 16. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating costs. See Note 16 for further discussion of our gains and losses on the sales of other property and equipment and a summary of our other property and equipment held for sale as of December 31, 2014 and 2013. Other property and equipment costs, excluding land, are depreciated on a straight-line basis.

Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. During 2014, 2013 and 2012, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 17 for further discussion of these impairments.

Capitalized Interest

Interest from external borrowings is capitalized on significant projects until the asset is ready for service using the weighted average cost of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.

Goodwill

Goodwill represents the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment at least annually. This test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. When the qualitative assessment indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, the quantitative assessment is then performed. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense.

Our goodwill, which is included in other long-term assets on our consolidated balance sheets, was $15 million and $43 million, respectively, as of December 31, 2014 and 2013. The 2014 amount consists of $15 million of excess consideration over the fair value of assets acquired in our Horizon Drilling Services acquisition in 2011. The 2013 amount also included $28 million of excess consideration over the fair value of assets acquired in our Bronco Drilling Company acquisition in 2011. We no longer have the goodwill balance related to Bronco Drilling Company as a result of the spin-off of our oilfield services business in June 2014. We performed annual impairment tests of goodwill in the fourth quarters of 2014 and 2013. Based on these assessments, no impairment of goodwill was required. Goodwill was included in our exploration and production segment as of December 31, 2014 and as of December 31, 2013 was included in our former oilfield services segment.

Accounts Payable

Included in accounts payable as of December 31, 2014 and 2013 are liabilities of approximately $333 million and $397 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.

Debt Issuance and Hedging Facility Costs

Included in other long-term assets are costs associated with the issuance of our senior notes, revolving credit facility, hedging facility and, as of December 31, 2013, costs associated with our former term loan and former oilfield services credit facility. The remaining unamortized issuance costs as of December 31, 2014 and 2013 totaled $130 million and $145 million, respectively, and are being amortized over the life of the applicable debt or facility using the effective interest method.

Environmental Remediation Costs

Chesapeake records environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Asset Retirement Obligations

We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. See Note 20 for further discussion of asset retirement obligations.

Revenue Recognition

Oil, Natural Gas and NGL Sales. Revenue from the sale of oil, natural gas and NGL is recognized when title passes, net of royalties due to third parties and gathering and transportation charges.

Natural Gas Imbalances. We follow the "sales method" of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining natural gas reserves on the underlying properties. The natural gas imbalance net liability position as of December 31, 2014 and 2013 was $12 million and $11 million, respectively.

Marketing, Gathering and Compression Sales. Chesapeake takes title to the oil, natural gas and NGL it purchases from other interest owners in operated wells at defined delivery points and delivers the product to third parties, at which time revenues are recorded. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. In circumstances where we act as a principal rather than an agent, Chesapeake's results of operations related to its oil, natural gas and NGL marketing activities are presented on a "gross" basis. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated.

Oilfield Services Revenue. Prior to the spin-off of our oilfield services business in June 2014, we reported oilfield services revenue. Our former oilfield services operating segment was responsible for contract drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Our oilfield services revenues prior to the spin-off were as follows:

•

Drilling. Revenues were generated by drilling oil and natural gas wells for our customers under daywork contracts and recognized for the days completed based on the dayrate specified in each contract. Revenue generated and costs incurred for mobilization services were recognized over the days of actual mobilization.

•

Hydraulic Fracturing. Revenue was recognized upon the completion of each fracturing stage. Typically, one or more fracturing stages per day per active crew was completed during the course of a job. A stage was considered complete when the customer requested or the job design dictated that pumping discontinue for that stage. Invoices typically included a lump sum equipment charge determined by the rate per stage specified in each contract and product charges for sand, chemicals and other products actually consumed during the course of providing fracturing services.

•

Oilfield Rentals. Oilfield equipment rentals included drill pipe, drill collars, tubing, blowout preventers, and frac and mud tanks, and services included air drilling services and services associated with the transfer of fresh water to the wellsite. Rentals and services were priced by the day or hour based on the type of equipment rented and the service job performed. Revenue was recognized ratably over the term of the rental.

•

Oilfield Trucking. Oilfield trucking provided rig relocation and logistics services as well as fluid handling services. Trucks moved drilling rigs, crude oil, other fluids and construction materials to and from the wellsites and also transported produced water from the wellsites. These services were priced on a per barrel basis based on mileage and revenue was recognized as services were performed.

•

Other Operations. A manufacturing subsidiary designed, engineered and fabricated natural gas compressor packages that were purchased primarily by Chesapeake. Compression units were priced based on certain specifications such as horsepower, stages and additional options. Revenue was recognized upon completion and transfer of ownership of the natural gas compression unit.

Fair Value Measurements

Certain financial instruments are reported at fair value on our 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 asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

The carrying values of financial instruments comprising cash and cash equivalents, restricted cash, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments.

Derivatives

Derivative instruments are recorded on our consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Locked-in gains and losses of settled cash flow hedges are recorded in accumulated other comprehensive income and are transferred to earnings in the month of production. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge ineffectiveness and are recognized currently in earnings. Locked-in gains and losses related to settled fair value hedges are amortized as an adjustment to interest expense over the remaining term of the related senior notes. We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in our consolidated statements of operations within oil, natural gas and NGL sales and interest expense, respectively.

Derivative instruments reflected as current in the 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 respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type (i.e., commodity, interest rate and cross currency contracts) which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.

We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 11 for further discussion of our derivative instruments.

Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only be settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as compensation expense in the consolidated statements of operations.

To the extent compensation cost relates to employees directly involved in the acquisition of oil and natural gas leasehold and exploration and development activities, these amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses, oil, natural gas and NGL production expenses, or marketing, gathering and compression expenses, based on the employees involved in those activities.

Cash inflows resulting from tax deductions in excess of compensation expense recognized for stock options and restricted stock are classified as financing cash inflows, while reductions in tax benefits are classified as operating cash outflows in our consolidated statements of cash flows. See Note 9 for further discussion of share-based compensation.

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for 2012 and 2013 to conform to the presentation used for the 2014 consolidated financial statements.

Earnings_Per_Share_Note

Earnings Per Share (Note)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Earnings Per Share Disclosure [Text Block]	Earnings Per Share
	Basic earnings per share (EPS) is calculated using the weighted average number of common shares outstanding during the period and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide dividend rights.
	Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For the years ended December 31, 2014, 2013 and 2012, our contingent convertible senior notes did not have a dilutive effect and therefore were excluded from the calculation of diluted EPS. See Note 3 for further discussion of our contingent convertible senior notes.
	For the years ended December 31, 2014, 2013 and 2012, shares of the following securities and associated adjustments to net income, representing dividends on preferred stock and allocated earnings on participating securities, were excluded from the calculation of diluted EPS as the effect was antidilutive. The impact of our stock options was immaterial in the calculation of diluted EPS for these periods.
		Net Income		Shares
		Adjustments
		($ in millions)		(in millions)
	Year Ended December 31, 2014
	Participating securities	$	22	3
	Year Ended December 31, 2013
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	86	56
	5.75% cumulative convertible preferred stock (series A)	$	63	40
	5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
	4.50% cumulative convertible preferred stock	$	12	6
	Participating securities	$	10	5
	Year Ended December 31, 2012
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	86	56
	5.75% cumulative convertible preferred stock (series A)	$	63	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
	4.50% cumulative convertible preferred stock	$	12	6
	Participating securities	$	—	5
	For the year ended December 31, 2014, all outstanding equity securities convertible into common stock were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the year ended December 31, 2014 is as follows:
		Income (Numerator)		Weighted	Per
				Average	Share
				Shares	Amount
				(Denominator)
		(in millions, except per share data)
	For the Year Ended December 31, 2014:
	Basic EPS	$	1,273	659	$	1.93
	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	86		59
	Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)	63		42
	Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)	10		6
	Common shares assumed issued for 4.50% cumulative convertible preferred stock	12		6
	Diluted EPS	$	1,444	772	$	1.87

Debt_Note

Debt (Note)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	Debt
	Our long-term debt consisted of the following as of December 31, 2014 and 2013:
			December 31,
			2014				2013
			($ in millions)
	Term loan due 2017(a)		$	—			$	2,000
	9.5% senior notes due 2015(b)		—				1,265
	3.25% senior notes due 2016		500				500
	6.25% euro-denominated senior notes due 2017(c)		416				473
	6.5% senior notes due 2017		660				660
	6.875% senior notes due 2018(d)		—				97
	7.25% senior notes due 2018		669				669
	Floating rate senior notes due 2019		1,500				—
	6.625% senior notes due 2019(e)		—				650
	6.625% senior notes due 2020		1,300				1,300
	6.875% senior notes due 2020		500				500
	6.125% senior notes due 2021		1,000				1,000
	5.375% senior notes due 2021		700				700
	4.875% senior notes due 2022		1,500				—
	5.75% senior notes due 2023		1,100				1,100
	2.75% contingent convertible senior notes due 2035(f)		396				396
	2.5% contingent convertible senior notes due 2037(f)		1,168				1,168
	2.25% contingent convertible senior notes due 2038(f)		347				347
	Revolving credit facility		—				—
	Oilfield services revolving credit facility(g)		—				405
	Discount on senior notes and term loan(h)		(231		)		(357		)
	Interest rate derivatives(i)		10				13
	Total debt, net		11,535				12,886
	Less current maturities of long-term debt, net(j)		(381		)		—
	Total long-term debt, net		$	11,154			$	12,886
	___________________________________________
	(a)	In 2014, we repaid the borrowings outstanding under and terminated the term loan due 2017.
	(b)	In 2014, we completed a tender offer for a portion of the 9.5% Senior Notes due 2015, and we redeemed the remaining balance of the notes.
	(c)	The principal amount shown is based on the exchange rate of $1.2098 to €1.00 and $1.3743 to €1.00 as of December 31, 2014 and 2013, respectively. See Note 11 for information on our related foreign currency derivatives.
	(d)	In 2014, we redeemed all outstanding 6.875% Senior Notes due 2018.
	(e)	Initial issuers were Chesapeake Oilfield Operating, L.L.C. (COO) and Chesapeake Oilfield Finance, Inc., a wholly owned subsidiary of COO. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes. In 2014, in connection with the spin-off of our oilfield services business, the obligations with respect to the COO senior notes were removed from our consolidated balance sheet. See Note 13 for further discussion of the spin-off.
	(f)	The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows:
	Holders’ Demand Repurchase Rights. 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.
	Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, the notes are convertible 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 quarterly. During the specified period in the fourth quarter of 2014, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the first quarter of 2015 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. The notes were not convertible under this provision in 2014, 2013 or 2012. 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 the principal amount.
	Contingent Interest. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years during certain periods if the average trading price of the notes exceeds the threshold defined in the indenture.
	The holders’ demand repurchase dates, the common stock price conversion threshold amounts (as adjusted to give effect to the dividend of SSE common stock paid in the spin-off of our oilfield services business and cash dividends on our common stock) and the ending date of the first six-month period in which contingent interest may be payable for the contingent convertible senior notes are as follows:
	Contingent		Holders' Demand		Common Stock				Contingent Interest
	Convertible		Repurchase Dates		Price Conversion				First Payable
	Senior  Notes				Thresholds				(if applicable)
	2.75% due 2035		November 15, 2015, 2020, 2025, 2030		$	45.14			May 14, 2016
	2.5% due 2037		May 15, 2017, 2022, 2027, 2032		$	59.71			November 14, 2017
	2.25% due 2038		December 15, 2018, 2023, 2028, 2033		$	100.35			June 14, 2019
	Optional Redemption by the Company. We may redeem the contingent 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.
	(g)	In 2014, in connection with the spin-off of our oilfield services business, we terminated our oilfield services credit facility. See Note 13 for further discussion of the spin-off.
	(h)	Discount as of December 31, 2014 and 2013 included $224 million and $303 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. Discount also included $33 million as of December 31, 2013 associated with our term loan due 2017 discussed below.
	(i)	See Note 11 for further discussion related to these instruments.
	(j)	As of December 31, 2014, there was $15 million of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035. As discussed in footnote (f) above, the holders of our 2.75% Contingent Convertible Senior Notes due 2035 could exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the principal amount of the notes.
	Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes, for the five years ended after December 31, 2014 and thereafter are as follows:
			Principal Amount
			of Debt Securities
			($ in millions)
	2015		$	396
	2016		500
	2017		2,244
	2018		1,016
	2019		1,500
	2020 and thereafter		6,100
	Total		$	11,756
Term Loan
In November 2012, we established an unsecured five-year term loan credit facility in an aggregate principal amount of $2.0 billion for net proceeds of $1.935 billion. The term loan provided that it could be voluntarily repaid before November 9, 2015 at par plus a specified premium and at any time thereafter at par. The maturity date of the term loan was December 2, 2017. In 2014, we used a portion of the net proceeds from our offering of $3.0 billion in aggregate principal amount of senior notes to repay the borrowings under, and terminate, the term loan. We recorded a loss of $90 million, consisting of $40 million in premiums, $30 million of unamortized discount and $20 million of unamortized deferred charges, in connection with the termination.
Chesapeake Senior Notes and Contingent Convertible Senior Notes
The Chesapeake senior notes and the contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Chesapeake is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Chesapeake’s obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect 100% owned subsidiaries. See Note 22 for 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 may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale-leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the senior notes and the contingent convertible senior notes do not have any financial or restricted payment covenants. The senior notes and contingent convertible senior notes indentures have cross default provisions that apply to other indebtedness the Company or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million or $75 million, depending on the indenture.
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. The applicable 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.
During 2014, we issued $3.0 billion in aggregate principal amount of senior notes at par. The offering included two series of notes: $1.5 billion in aggregate principal amount of Floating Rate Senior Notes due 2019 and $1.5 billion in aggregate principal amount of 4.875% Senior Notes due 2022. We used a portion of the net proceeds of $2.966 billion to repay the borrowings under, and terminate, our term loan credit facility. We used the remaining proceeds along with cash on hand to redeem the remaining $97 million principal amount of the 6.875% Senior Notes due 2018 and to purchase and redeem the remaining $1.265 billion principal amount of the 9.5% Senior Notes due 2015 for $1.454 billion. We recorded a loss of approximately $6 million associated with the redemption of the 6.875% Senior Notes due 2018, which consisted of $5 million in premiums and $1 million of unamortized deferred charges. We recorded a loss of approximately $99 million associated with the purchase and redemption of the 9.5% Senior Notes due 2015, which consisted of $87 million in premiums, $9 million of unamortized discount and $3 million of unamortized deferred charges.
During 2013, we issued $2.3 billion in aggregate principal amount of senior notes at par. The offering included three series of notes: $500 million in aggregate principal amount of 3.25% Senior Notes due 2016; $700 million in aggregate principal amount of 5.375% Senior Notes due 2021; and $1.1 billion in aggregate principal amount of 5.75% Senior Notes due 2023. We used a portion of the net proceeds of $2.274 billion to repay outstanding indebtedness under our revolving credit facility and purchase certain senior notes. We purchased $217 million in aggregate principal amount of our 7.625% Senior Notes due 2013 for $221 million and $377 million in aggregate principal amount of our 6.875% Senior Notes due 2018 for $405 million pursuant to tender offers during 2013. We recorded a loss of approximately $37 million associated with the tender offers, including $32 million in premiums and $5 million of unamortized deferred charges. During 2013, we also redeemed $1.3 billion in aggregate principal amount of our 6.775% Senior Notes due 2019 (the 2019 Notes) at par pursuant to notice of special early redemption. We recorded a loss of approximately $33 million associated with the redemption, including $19 million of unamortized deferred charges and $14 million of discount. As described in the following paragraph, our redemption of the 2019 Notes has been the subject of litigation. On July 15, 2013, we retired at maturity the remaining $247 million aggregate principal amount outstanding of our 7.625% Senior Notes due 2013.
In March 2013, the Company brought suit in the U.S. District Court for the Southern District of New York against The Bank of New York Mellon Trust Company, N.A., the indenture trustee for the 2019 Notes. The Company sought and ultimately obtained a judgment declaring that the notice it issued on March 15, 2013 to redeem all of the 2019 Notes at par (plus accrued interest through the redemption date) was timely and effective for that redemption pursuant to the special early redemption provision of the supplemental indenture governing the 2019 Notes. In May 2013, as a result of that ruling, the 2019 Notes were redeemed at par. In November 2014, the U.S. Court of Appeals for the Second Circuit, on appeal by the indenture trustee, reversed the District Court’s declaratory judgment and held that the notice was not effective to redeem the 2019 Notes at par because it was not timely for that purpose. The Court of Appeals remanded the case to the District Court for a determination whether the redemption notice triggered a redemption at the make-whole price specified in the indenture, instead of at par. The Company sought a rehearing by the Court of Appeals en banc in December 2014, and that petition was denied on February 6, 2015. On February 13, 2015, the indenture trustee filed a motion in the District Court for entry of a judgment requiring the Company to pay the make-whole price, as defined in the indenture, less the par amount paid in the 2013 redemption plus prejudgment interest at the statutory 9% rate from the redemption date. The Company intends to oppose the trustee’s motion vigorously.
On December 30, 2014, six former holders of the 2019 Notes filed a putative class action against the Company on behalf of all former holders who sold the 2019 Notes after the Company issued the notice of early redemption in March 2013 but before the notes were redeemed at par in May 2013. These former holders allege that the Company breached the indenture by issuing a wrongful notice of special early redemption, and that this breach caused the market value of the notes to decline, injuring them when they sold their 2019 Notes. This suit has been assigned to the same District Court judge as the suit described above. The Company intends to defend itself against this claim vigorously.
No scheduled principal payments are required on our senior notes until 2016 unless the holders of our 2.75% Contingent Convertible Senior Notes due 2035 exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the $396 million principal amount of notes.
Revolving Credit Facility
In December 2014, we entered into a new five-year $4.0 billion senior unsecured revolving credit facility to use for general corporate purposes. The new credit facility replaced our then-existing $4.0 billion senior secured revolving credit facility that was scheduled to mature in December 2015. The aggregate commitments under the facility may be increased up to an additional $1.0 billion, and the December 2019 maturity date may be extended for two one-year periods at our request and with the consent of the participating lenders. As of December 31, 2014, we had no outstanding borrowings under the facility and utilized $15 million of the facility for various letters of credit. Borrowings under the facility are currently unsecured; however, we will be required to provide collateral and the facility will be subject to a borrowing base if our credit rating declines to Ba3 (Moody’s Investors Services, Inc.) or BB- (Standard & Poor’s Ratings Services) or lower.
Revolving loans under the revolving credit facility bear interest at a fluctuating rate per annum equal to the highest of (i) the federal funds effective rate plus 0.5%, (ii) the administrative agent’s prime rate or (iii) the London interbank offer rate (LIBOR) for a one-month interest period plus 1.0% (alternative base rate (ABR) loans), and/or LIBOR rates (LIBOR loans), at our election, plus an applicable margin rate depending on our credit rating (currently 0.625% per annum for ABR loans and 1.625% per annum for LIBOR loans). The terms of the credit facility include covenants limiting, among other things, the ability of the Company and its restricted subsidiaries to incur additional indebtedness, make investments or loans, create liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates. In addition, the credit facility requires us to maintain, as of the last day of each fiscal quarter, (i) a net debt to capitalization ratio (as defined in the credit agreement) that does not exceed 65%; and (ii) a leverage ratio (net debt to consolidated EBITDA, as defined in the credit agreement) that does not exceed 4.0 to 1.0; provided, however, that the leverage ratio will not apply during any period in which our credit rating, as determined by either Moody’s Investors Services, Inc. or Standard & Poor’s Rating Services, meet and continue to meet certain investment grade thresholds, as defined in the credit agreement.
Our credit facility is fully and unconditionally guaranteed, on a joint and several basis, by certain of our material subsidiaries. The credit agreement includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $125 million or more; bankruptcy; judgments involving liability of $125 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.
Spin-Off Debt Transactions
Prior to the spin-off of our oilfield services business, COO or its subsidiaries completed the following debt transactions:
•	Entered into a five-year senior secured revolving credit facility with total commitments of $275 million and incurred approximately $3 million in financing costs related to entering into the facility.
•	Entered into a $400 million seven-year secured term loan and used the net proceeds of approximately $394 million and borrowings under the new revolving credit facility to repay and terminate COO’s existing credit facility.
•	Issued $500 million in aggregate principal amount of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds of approximately $494 million to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility discussed above and for general corporate purposes.
All deferred charges and debt balances related to these transactions were removed from our consolidated balance sheet as of June 30, 2014. See Note 13 for further discussion of the spin-off.
Fair Value of Debt
We estimate the fair value of our exchange-traded debt using quoted market prices (Level 1). The fair value of all other debt, which currently consists of our revolving credit facility and as of December 31, 2013 also consisted of our former oilfield services credit facility and term loan, is estimated using our credit default swap rate (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.
		31-Dec-14							31-Dec-13
		Carrying				Estimated			Carrying		Estimated
		Amount				Fair Value			Amount		Fair Value
						($ in millions)
Long-term debt (Level 1)		$	11,525			$	12,052		$	10,501	$	11,557
Long-term debt (Level 2)		$	—			$	—		$	2,372	$	2,369

Contingencies_and_Commitments_

Contingencies and Commitments (Note)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure [Text Block]	Contingencies and Commitments
	Contingencies
	Litigation and Regulatory Proceedings
	The Company is involved in a number of litigation and regulatory proceedings (including those described below). Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different. Our total estimated liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. We account for legal defense costs in the period the costs are incurred.
	July 2008 Common Stock Offering 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. 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. Chesapeake and the officer and director defendants moved for summary judgment on grounds of loss causation and materiality on December 28, 2011, and the motion was granted as to all claims as a matter of law on March 29, 2013. On appeal, the U.S. Court of Appeals for the Tenth Circuit affirmed the dismissal on August 8, 2014 and denied the plaintiffs’ petition for rehearing on November 12, 2014.
	Shareholder Derivative Litigation. A derivative action relating to the July 2008 offering was filed in the U.S. District Court for the Western District of Oklahoma on September 6, 2011. The case was thereafter stayed by stipulation between the parties, and on November 20, 2014, the parties entered a stipulation to have the case voluntarily dismissed. On January 16, 2015, pursuant to Court order, the Company provided notice to shareholders of the voluntary dismissal and allowed eligible shareholders to intervene.
	A federal consolidated derivative action and an Oklahoma state court derivative action have been stayed since 2012 pending resolution of a related, previously reported putative federal securities class action. The shareholder derivative actions allege breaches of fiduciary duty, among other things, related to the former CEO’s personal financial practices and purported conflicts of interest, and the Company’s accounting for volumetric production payments. With the dismissal of the federal securities class action now affirmed, the parties have stipulated to continue the stay of the Oklahoma state court derivative action while the plaintiffs pursue their claims in the federal consolidated derivative action. The plaintiffs filed a consolidated derivative complaint on October 31, 2014 and an amended consolidated derivative complaint on February 12, 2015. Chesapeake filed its motion to dismiss on February 23, 2015.
	Regulatory Proceedings. The Company has received, from the U.S. Department of Justice (DOJ) and certain state governmental agencies and authorities, subpoenas and demands for documents, information and testimony in connection with investigations into possible violations of federal and state antitrust laws relating to our purchase and lease of oil and gas rights in various states. The Company also has received DOJ and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake has engaged in discussions with the DOJ and state representatives and continues to respond to such subpoenas and demands.
	On March 5, 2014, the Attorney General of the State of Michigan filed a criminal complaint against Chesapeake in Michigan state court alleging misdemeanor antitrust violations and attempted antitrust violations under state law arising out of the Company’s leasing activities in Michigan during 2010. On July 9, 2014, following a preliminary hearing on the complaint, as amended, the 89th District Court for Cheboygan County, Michigan ruled that one count alleging a bid-rigging conspiracy between Chesapeake and Encana Oil & Gas USA, Inc. regarding the October 2010 state lease auction would proceed to trial and dismissed claims alleging a second antitrust violation and an attempted antitrust violation. A trial date of April 15, 2015 has been set for this case. The Michigan Attorney General filed a second criminal complaint against Chesapeake in the same court on June 5, 2014 which, as amended, alleges that Chesapeake’s conduct in canceling lease offers to Michigan landowners in 2010 violated the state’s criminal enterprises and false pretenses felony statutes. On September 9, 2014, following a preliminary hearing, the Court ruled that all charges in the complaint would be tried. No trial date has been set for this matter.
	Redemption of 2019 Notes. See Note 3 for a description of pending litigation regarding our redemption in May 2013 of our 2019 Notes. As a result of the reversal of the trial court’s decision in our declaratory judgment action against the indenture trustee, we have accrued a loss contingency of $100 million for this matter. We estimate the range of potential loss between $100 million to $380 million, plus prejudgment interest of up to 9%. The high end of this range is based upon the indenture trustee’s request in mid-February 2015 that the Court order us to pay noteholders the “make-whole” amount (as defined in the indenture) less the par amount already paid. Our $100 million accrual is based on an estimate of the remedy required to restore the redeemed noteholders and the Company to the economic positions they would have been in had the 2019 Notes not been redeemed. We are unable to estimate an amount or range of loss with respect to the recently filed putative class action by certain former holders of the 2019 Notes.
	Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. With regard to contract actions, 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 successfully defended a number of these failure-to-close cases in various courts, has settled and resolved other such cases and disputes and believes that its remaining loss exposure for these claims will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. In addition, as described above, the Michigan Attorney General has commenced a criminal proceeding against us based on lease offers to Michigan landowners in 2010.
	Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending lawsuits seeking damages for royalty underpayment in various states, including cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The Company also has received DOJ and state subpoenas seeking information on the Company’s royalty payment practices.
	Plaintiffs have varying royalty provisions in their respective leases and oil and gas law varies from state to state. Royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations, an issue in a putative class action filed in November 2010 in the District Court of Beaver County, Oklahoma on behalf of Oklahoma royalty owners asserting claims dating back to 2004. In July 2014, this case was remanded to the trial court for further proceedings following the reversal on appeal of certification of a statewide class. We and the named plaintiff participated in mediation concerning the claims asserted in the putative class action litigation and have negotiated a settlement requiring the Company to pay $119 million cash to compensate the putative settlement class for alleged past royalty underpayments in exchange for the release of claims for the ten-year period ended December 31, 2014. The plaintiff filed a motion for preliminary approval of the settlement on January 2, 2015. The Company has accrued a loss contingency for the settlement amount in the 2014 consolidated statement of operations. A fairness hearing on the settlement has been scheduled for April 17, 2015. Although Chesapeake believes that its royalty calculation and payment methodologies are appropriate under Oklahoma oil and gas law and denies that it committed any acts or omissions giving rise to any liability, it also believes that settlement is in the best interest of the Company considering the questions of law and fact involved and the uncertainty of continued litigation. There can be no assurance the court will approve the settlement, however, and the final resolution of the Oklahoma royalty claims could differ from the amount accrued.
	We believe losses are reasonably possible in certain of the other pending royalty cases for which we have not accrued a loss contingency, but we are currently unable to estimate an amount or range of loss or the impact the actions could have on our future results of operations or cash flows. In Pennsylvania, three putative statewide class actions and one purported class arbitration have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the Company’s divestiture of substantially all of its midstream business and most of its gathering assets in 2012 and 2013. These Pennsylvania cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and one of the cases includes claims of intentional interference with contractual relations and violations of antitrust laws. Uncertainties in pending royalty cases generally include the complex nature of the claims and defenses, the potential size of the class in class actions, the scope and types of the properties and agreements involved, and the applicable production years.
	Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to the Company’s business operations is likely to have a material adverse effect on its future 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 Contingencies
	The nature of the oil and gas business carries with it certain environmental risks for Chesapeake and its subsidiaries. Chesapeake has implemented various policies, procedures, training and auditing to reduce and mitigate such environmental risks. Chesapeake conducts periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, Chesapeake may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.
	Commitments
	Operating Leases
	Future operating lease commitments related to other property and equipment are not recorded in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below.
		31-Dec-14
		($ in millions)
	2015	$	5
	2016	4
	2017	1
	2018	1
	Total	$	11
	Lease expense for the years ended December 31, 2014, 2013 and 2012 was $33 million, $158 million and $185 million, respectively. Lease expense decreased significantly in 2014 primarily due to the repurchase of all rigs and compressors previously sold under long-term sale-leaseback arrangements.
	Gathering, Processing and Transportation Agreements
	We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas and liquids to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded in the accompanying consolidated balance sheets; however, they are reflected as adjustments to oil, natural gas and NGL sales prices used in our proved reserves estimates.
	The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners or credits for third-party volumes, are presented below.
		December 31, 2014
		($ in millions)
	2015	$	1,855
	2016	1,987
	2017	2,003
	2018	1,802
	2019	1,516
	2020 - 2099	6,880
	Total	$	16,043
	In addition to the gathering, processing and transportation agreements discussed above, we have entered into long-term agreements for certain natural gas gathering and related services within specified acreage dedication areas in exchange for cost-of-service based fees redetermined annually or tiered fees based on volumes delivered relative to scheduled volumes. Future gathering fees will vary depending on the applicable agreement. Two of these agreements, one for production in the Anadarko Basin and the other for production in the Haynesville/Bossier Shales in northwestern Louisiana, contain cost-of-service based fees that are redetermined annually through 2019 and 2020, respectively. The annual upward or downward fee adjustment for these two contracts is capped at 15% of the then-current fees at the time of redetermination. To the extent the actual rate of return on capital expended by the counterparty over the term of the agreement differs from the applicable rate of return, a payment is due to (from) the midstream service company.
	Drilling Contracts
	We have contracts with various drilling contractors, including those entered into with Seventy Seven Energy Inc. (SSE) in connection with the spin-off of our oilfield services business as discussed in Note 13, to utilize drilling services with terms ranging from three months to three years at market-based pricing. These commitments are not recorded in the accompanying consolidated balance sheets. As of December 31, 2014, the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below.
		December 31,
		2014
		($ in millions)
	2015	$	232
	2016	179
	2017	91
	Total	$	502
	Pressure Pumping Contracts
	As discussed in Note 13, in connection with the spin-off of our oilfield services business we entered into an agreement with a subsidiary of SSE related to pressure pumping services. The services agreement requires us to utilize, at market-based pricing, the lesser of (i) seven, five and three pressure pumping crews in years one, two and three of the agreement, respectively, or (ii) 50% of the total number of all pressure pumping crews working for us in all of our operating regions during the respective year. We are also required to utilize SSE pressure pumping services for a minimum number of fracture stages as set forth in the agreement. We are entitled to terminate the agreement in certain situations, including if SSE fails to provide the overall quality of service provided by similar service providers. The aggregate undiscounted minimum future payments under this agreement are detailed below.
		31-Dec-14
		($ in millions)
	2015	$	245
	2016	162
	2017	59
	Total	$	466
	Drilling Commitments
	We have committed to drill wells for the benefit of CHK Cleveland Tonkawa, L.L.C. and Chesapeake Granite Wash Trust. See Noncontrolling Interests in Note 8 for discussion of these commitments.
	Natural Gas and Liquids Purchase Commitments
	We regularly commit to purchase natural gas and liquids from other owners in the properties we operate, including owners associated with our volumetric production payment (VPP) transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices. See Note 12 for further discussion of our VPP transactions.
	Net Acreage Maintenance Commitments
	Under the terms of our joint venture agreements with Total and Sinopec (see Note 12), we are required to extend, renew or replace expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas as of future measurement dates. To date, we have satisfied our replacement commitments under the Sinopec agreement. In 2014, we settled a dispute with Total regarding our acreage maintenance obligation as of December 31, 2012 for $50 million. The payment was based on a shortfall of approximately 20,800 net acres.
Other Commitments
In July 2011, we agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc. (Sundrop), a privately held cellulosic biofuels company based in Longmont, Colorado. We also provided Sundrop with a one-time option to require us to purchase up to $25 million in additional preferred equity securities following the full payment of the initial investment, subject to the occurrence of specified milestones. As of December 31, 2014, we had funded our $155 million commitment in full and the milestones related to Sundrop’s preferred equity call option had not been met. See Note 14 for further discussion of this investment.
As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance.
In connection with divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of oil and gas properties, our purchase and sale agreements may require the return of a portion of the proceeds we receive as a result of uncured title defects.
Certain of our oil and natural gas properties are burdened by non-operating interests such as royalty and overriding royalty interests, including overriding royalty interests sold through our VPP transactions. As the holder of the working interest from which these interests have been created, we have the responsibility to bear the cost of developing and producing the reserves attributable to these interests. See Note 12 for further discussion of our VPP transactions.
While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, certain actions that may reduce financial leverage and complexity could negatively impact our future results of operations and/or liquidity, and we may incur additional cash and noncash charges.

Other_Liabilities_Note

Other Liabilities (Note)	12 Months Ended
	Dec. 31, 2014
Other Liabilities Disclosure [Abstract]
Other Liabilities Disclosure [Text Block]	Other Liabilities
	Other current liabilities as of December 31, 2014 and 2013 are detailed below.
			December 31,
			2014		2013
			($ in millions)
	Revenues and royalties due others		$	1,176	$	1,409
	Accrued oil, natural gas and NGL drilling and production costs		385		457
	Joint interest prepayments received		189		464
	Accrued compensation and benefits		344		320
	Other accrued taxes		55		161
	Accrued dividends		101		101
	Other		811		599
	Total other current liabilities		$	3,061	$	3,511
	Other long-term liabilities as of December 31, 2014 and 2013 are detailed below.
			December 31,
			2014		2013
			($ in millions)
	CHK Utica ORRI conveyance obligation(a)		$	220	$	250
	CHK C-T ORRI conveyance obligation(b)		135		149
	Financing obligations		30		31
	Unrecognized tax benefits		45		317
	Other		249		237
	Total other long-term liabilities		$	679	$	984
	____________________________________________
	(a)	$14 million and $13 million of the total $234 million and $263 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction.
	(b)	$23 million and $12 million of the total $158 million and $161 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction.

Income_Taxes_Note

Income Taxes (Note)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	Income Taxes
	The components of the income tax provision (benefit) for each of the periods presented below are as follows:
		Years Ended December 31,
		2014			2013			2012
		($ in millions)
	Current
	Federal	$	—		$	—		$	—
	State	47			22			47
	Current Income Taxes	47			22			47
	Deferred
	Federal	1,115			502			(358		)
	State	(18		)	24			(69		)
	Deferred Income Taxes	1,097			526			(427		)
	Total	$	1,144		$	548		$	(380	)
	The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:
		Years Ended December 31,
		2014			2013			2012
		($ in millions)
	Income tax expense (benefit) at the federal statutory rate (35%)	$	1,120		$	505		$	(341	)
	State income taxes (net of federal income tax benefit)	68			88			(38		)
	Remeasurement of state deferred tax liabilities	(114		)	(38		)	(19		)
	Change in valuation allowance	74			(12		)	—
	Other	(4		)	5			18
	Total	$	1,144		$	548		$	(380	)
	During the 2014 fourth quarter, Chesapeake simplified its organizational structure which impacts how income (loss) is allocated and apportioned to various states. This change resulted in a $114 million tax benefit due to the remeasurement of state deferred tax liabilities. Additionally, we reassessed the realizability of our deferred tax assets given the decline in commodity prices. We recorded a $74 million tax expense for the increase in our valuation allowance.
	Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:
		Years Ended December 31,
		2014			2013
		($ in millions)
	Deferred tax liabilities:
	Oil and natural gas properties	$	(3,950	)	$	(2,631	)
	Other property and equipment	(14		)	(371		)
	Volumetric production payments	(920		)	(1,216		)
	Contingent convertible debt	(443		)	(439		)
	Deferred revenue	(102		)	—
	Derivative instruments	(428		)	—
	Deferred tax liabilities	(5,857		)	(4,657		)
	Deferred tax assets:
	Net operating loss carryforwards (carrybacks)	945			535
	Derivative instruments	—			108
	Asset retirement obligations	165			153
	Investments	88			130
	Deferred stock compensation	50			66
	Accrued liabilities	214			120
	Noncontrolling interest liabilities	135			152
	Alternative minimum tax credits	34			317
	Other	56			40
	Deferred tax assets	1,687			1,621
	Valuation allowance	(222		)	(148		)
	Net deferred tax assets	1,465			1,473
	Net deferred tax assets (liabilities)	$	(4,392	)	$	(3,184	)
	Reflected in accompanying balance sheets as:
	Current deferred income tax asset	—			223
	Current deferred income tax liability	(207		)	—
	Non-current deferred income tax liability	(4,185		)	(3,407		)
	Total	$	(4,392	)	$	(3,184	)
	As of December 31, 2014, Chesapeake had federal income tax NOL carryforwards of approximately $1.6 billion and state NOL carryforwards of approximately $8.3 billion which excludes the NOL carryforwards related to unrecognized tax benefits and stock compensation windfalls that have not been recognized under U.S. GAAP. The associated deferred tax assets related to these NOL carryforwards were $551 million and $394 million, respectively. Additionally, we had $76 million of alternative minimum tax (AMT) NOL carryforwards, net of unrecognized tax benefits, available as a deduction against future AMT income. The NOL carryforwards expire from 2031 through 2033. The value of these carryforwards depends on the ability of Chesapeake to generate taxable income. As of December 31, 2014 and 2013, we had deferred tax assets of $1.687 billion and $1.621 billion, respectively, upon which we had a valuation allowance of $222 million and $148 million, respectively, for certain state NOL carryforwards and credits that we have concluded are not more likely than not to be utilized prior to expiration. The net change in the valuation allowance of $74 million is reflected as a component of income tax expense.
	Deferred tax assets relating to tax benefits of employee share-based compensation have been reduced for stock options exercised and restricted stock that vested in periods in which Chesapeake was in a net operating loss (NOL) position. Some exercises and vestings result in tax deductions in excess of previously recorded benefits based on the stock option or restricted stock value at the time of grant (windfalls). Although these additional tax benefits or windfalls are reflected in NOL carryforwards in the tax return, the additional tax benefit associated with the windfalls is not recognized until the deduction reduces taxes payable pursuant to accounting for stock compensation under U.S. GAAP. Accordingly, since the tax benefit does not reduce Chesapeake's current taxes payable due to NOL carryforwards, these windfall tax benefits are not reflected in Chesapeake's NOLs in deferred tax assets. Windfalls included in NOL carryforwards but not reflected in deferred tax assets as of December 31, 2014 totaled $18 million. Any shortfalls resulting from tax deductions that were less than the previously recorded benefits were recorded as reductions to additional paid-in capital.
	The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of these carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake.
	As of December 31, 2014, we do not believe that an ownership change has occurred that would limit the carryforwards. Due to the spin-off of SSE, the limitation on previously acquired NOLs was increased such that the remaining carryforward became fully available. Future equity transactions by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs.
	Accounting guidance for recognizing and measuring uncertain tax positions prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. As of December 31, 2014 and 2013, the amount of unrecognized tax benefits related to NOL carryforwards and state tax liabilities associated with uncertain tax positions was $303 million and $644 million, respectively. Of the 2014 amount, $23 million and $17 million are related to AMT and state tax liabilities, respectively, while the remainder is related to NOL carryforwards. Of the 2013 amount, $4 million is related to state tax liabilities while the remainder is related to NOL carryforwards. If these unrecognized tax benefits are disallowed and our NOL carryforwards are reduced, the reduction will be offset by additional tax basis that will generate future deductions. The uncertain tax positions identified would not have a material effect on the effective tax rate. No material changes to the current uncertain tax positions are expected within the next 12 months. As of December 31, 2014 and 2013, we had accrued liabilities of $5 million and $13 million, respectively, for interest related to these uncertain tax positions. Chesapeake recognizes interest related to uncertain tax positions in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses.
	A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
		2014			2013			2012
		($ in millions)
Unrecognized tax benefits at beginning of period	$	644		$	599		$	369
Additions based on tax positions related to the current year	13			15			134
Additions to tax positions of prior years	—			30			96
Reductions to tax positions of prior years	(354		)	—			—
Unrecognized tax benefits at end of period	$	303		$	644		$	599
Chesapeake's federal and state income tax returns are routinely audited by federal and state fiscal authorities. The Internal Revenue Service (IRS) is currently auditing our federal income tax returns for 2007 through 2013. The federal tax returns for 1999 through 2006 remain subject to examination for the purpose of determining the amount of remaining tax NOL and other carryforwards. The 2007 through 2014 years remain open for all purposes of examination by the IRS and other taxing authorities in material jurisdictions.

Related_Party_Transactions_Not

Related Party Transactions (Note)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	Related Party Transactions
	Our equity method investees are considered related parties. During 2014, 2013 and 2012, we had the following transactions with our equity method investees:
			Years Ended December 31,
			2014		2013		2012
			($ in millions)
	Purchases(a)		$	—	$	—	$	73
	Sales(b)		$	—	$	666	$	392
	Services(c)		$	220	$	397	$	480
	___________________________________________
	(a)	Purchase of equipment from FTS International, Inc. (FTS).
	(b)	In 2013 and 2012, Chesapeake sold produced gas to our 30%-owned investee, Twin Eagle Resource Management LLC (Twin Eagle). We sold our investment in Twin Eagle in 2014.
	(c)	Hydraulic fracturing and other services provided to us by FTS in the ordinary course of business. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs.
	The table below shows the total amounts due from and due to our equity method investees.
			December 31,
			2014		2013		2012
			($ in millions)
	Amounts due from equity method investees		$	—	$	47	$	67
	Amounts due to equity method investees		$	—	$	1	$	42

Equity_Note

Equity (Note)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Stockholders' Equity Note Disclosure [Text Block]	Equity
	Common Stock
	The following is a summary of the changes in our common shares issued for the years ended December 31, 2014, 2013 and 2012:
			Years Ended December 31,
			2014			2013			2012
			(in thousands)
	Shares issued as of January 1		666,192			666,468			660,888
	Restricted stock issuances (net of forfeitures and cancellations)(a)		(2,529	)		(599	)		5,038
	Stock option exercises		1,281			323			542
	Shares issued as of December 31		664,944			666,192			666,468
	___________________________________________
	(a)	In the second quarter of 2013, we began granting restricted stock units (RSUs) in lieu of restricted stock awards (RSAs) to non-employee directors and employees. Shares of common stock underlying RSUs are issued when the units vest, whereas shares of common stock are issued on the date the RSAs are granted. We refer to RSAs and RSUs collectively as restricted stock.
	Preferred Stock
	Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2014:
	Preferred Stock Series		Issue Date		Liquidation				Holder's Conversion Right		Conversion Rate		Conversion Price		Company's	Company's Market Conversion Trigger(a)
					Preference										Conversion
					per Share										Right From
	5.75% cumulative		May and		$	1,000			Any time		39.5856		$	25.2617	May 17, 2015	$	32.8402
	convertible		Jun-10
	non-voting
	5.75% (series A)		May		$	1,000			Any time		38.2538		$	26.1412	May 17, 2015	$	33.9836
	cumulative		2010
	convertible
	non-voting
	4.50% cumulative convertible		Sep-05		$	100			Any time		2.4468		$	40.8693	September 15, 2010	$	53.1301
	5.00% cumulative convertible (series 2005B)		Nov-05		$	100			Any time		2.7669		$	36.1415	November 15, 2010	$	46.984
	___________________________________________
	(a)	Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding.
	The following reflects the shares outstanding of our preferred stock for the years ended December 31, 2014, 2013 and 2012:
			5.75%			5.75% (A)			4.50%			5.00%
												(2005B)
			(in thousands)
	Shares outstanding as of January 1, 2014, 2013 and 2012 and shares outstanding as of December 31, 2014, 2013 and 2012		1,497			1,100			2,559			2,096
	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 exists after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, payments constitute a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.
	Dividends on our outstanding preferred stock are payable quarterly. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash.
	Accumulated Other Comprehensive Income (Loss)
	For the years ended December 31, 2014 and 2013, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.
			Net Gains				Net Gains				Total
			(Losses) on				(Losses)
			Cash Flow				on
			Hedges				Investments
			($ in millions)
	Balance, December 31, 2013		$	(167	)		$	5			$	(162	)
	Other comprehensive income before reclassifications		1				—				1
	Amounts reclassified from accumulated other comprehensive income		23				(5		)		18
	Net other comprehensive income		24				(5		)		19
	Balance, December 31, 2014		$	(143	)		$	—			$	(143	)
	Balance, December 31, 2012		$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications		2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income		20				4				24
	Net other comprehensive income		22				(2		)		20
	Balance, December 31, 2013		$	(167	)		$	5			$	(162	)
	For the years ended December 31, 2014 and 2013, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statements of operations are detailed below.
	Details About Accumulated		Affected Line Item		Year Ended
	Other Comprehensive		in the Statement		December 31,
	Income (Loss) Components		Where Net Income is Presented		2014
					($ in millions)
	Year Ended December 31, 2014:
	Net losses on cash flow hedges:
	Commodity contracts		Oil, natural gas and NGL revenues		$	23
	Investments:
	Sale of investment		Net gain on sale of investment		(5		)
	Total reclassifications for the period, net of tax				$	18
Year Ended December 31, 2013:
Net losses on cash flow hedges:
Commodity contracts		Oil, natural gas and NGL revenues		$	20
Investments:
Impairment of investment		Losses on investments		6
Sale of investment		Net gain on sale of investment		(2		)
Total reclassifications for the period, net of tax				$	24
Noncontrolling Interests
Cleveland Tonkawa Financial Transaction. We formed CHK Cleveland Tonkawa, L.L.C. (CHK C-T) in March 2012 to continue development of a portion of our oil and natural gas assets in our Cleveland and Tonkawa plays. CHK C-T is an unrestricted subsidiary under our revolving credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including indebtedness under our indentures. In exchange for all of the common shares of CHK C-T, we contributed to CHK C-T approximately 245,000 net acres of leasehold and the existing wells within an area of mutual interest in the plays between the top of the Tonkawa and the top of the Big Lime formations covering Ellis and Roger Mills counties in western Oklahoma. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 future net wells to be drilled on the contributed play leasehold. Subject to customary minority interest protections afforded the investors by the terms of the CHK C-T limited liability company agreement (the CHK C-T LLC Agreement), as the holder of all the common shares and the sole managing member of CHK C-T, we maintain voting and managerial control of CHK C-T and therefore include it in our consolidated financial statements. Of the $1.25 billion of investment proceeds, we allocated $225 million to the ORRI obligation and $1.025 billion to the preferred shares based on estimates of fair values. The remaining ORRI obligation is included in other current and long-term liabilities and the preferred shares are included in noncontrolling interests on our consolidated balance sheets. Pursuant to the CHK C-T LLC Agreement, CHK C-T is required to retain an amount of cash equal to the next two quarters of preferred dividend payments. The amount reserved, approximately $38 million as of December 31, 2014 and 2013, was reflected as restricted cash on our consolidated balance sheets.
Dividends on the preferred shares are payable on a quarterly basis at a rate of 6% per annum based on $1,000 per share. This dividend rate is subject to increase in limited circumstances in the event that, and only for so long as, any dividend amount is not paid in full for any quarter. As the managing member of CHK C-T, we may, at our sole discretion and election at any time after March 31, 2014, distribute certain excess cash of CHK C-T, as determined in accordance with the CHK C-T LLC Agreement and the development agreement, as amended. The optional distribution of excess cash is allocated 75% to the preferred shares (which is applied toward redemption of the preferred shares) and 25% to the common shares; provided, however, that in certain circumstances, as set forth in the CHK C-T L.L.C. Agreement and the development agreement, as amended, the optional distribution would be allocated 100% to the preferred shares (and applied toward redemption thereof). We may also, at our sole discretion and election, in accordance with the CHK C-T LLC Agreement, cause CHK C-T to redeem all or a portion of the CHK C-T preferred shares for cash. The preferred shares may be redeemed at a valuation equal to the greater of a 9% internal rate of return or a return on investment of 1.35x, in each case inclusive of dividends paid through redemption at the rate of 6% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to March 31, 2019, the optional redemption valuation will increase to provide a 15% internal rate of return to the investors. The preferred shares can be redeemed on a pro-rata basis in accordance with the then-applicable redemption valuation formula. As of December 31, 2014 and 2013, the redemption price and the liquidation preference were approximately $1,185 and $1,245, respectively, per preferred share.
We initially committed to drill and complete, for the benefit of CHK C-T in the area of mutual interest, a minimum of 37.5 net wells per six-month period through 2013, inclusive of wells drilled in 2012, and 25 net wells per six-month period in 2014 through 2016, up to a minimum cumulative total of 300 net wells. In April 2014, the drilling commitment was amended to require us to drill and complete a minimum cumulative total of (i) 162.5 net wells by June 30, 2014 and (ii) 175 net wells by December 31, 2014. In January 2015, the drilling commitment was suspended. We are not required or allowed to drill any wells with respect to the CHK C-T properties unless we receive written notice from the owners of a majority of the preferred shares electing to lift the drilling prohibition. If we receive written notice at least 45 days prior to June 30, 2015, we will be required to drill and complete a minimum cumulative total of 225 net wells by June 30, 2016, and thereafter the minimum cumulative total will be increased by 25 net wells in each of the subsequent six-month periods ending December 31, 2017. If notice is not received by that time, future drilling commitment dates will be extended, as provided in the January 2015 amendment to the drilling commitment. If we fail to meet the then-current cumulative drilling commitment in any six-month period, any optional cash distributions will be distributed 100% to the investors. If we fail to meet the then-current cumulative drilling commitment in two consecutive six-month periods, the then-applicable internal rate of return to investors at redemption will increase by 3% per annum. In addition, if we fail to meet the then-current cumulative drilling commitment in four consecutive six-month periods, the then-applicable internal rate of return to investors at redemption will be increased by an additional 3% per annum. Any increase in the internal rate of return would be effective only until the end of the first succeeding six-month period in which we have met our then-current cumulative drilling commitment. CHK C-T is responsible for all capital and operating costs of the wells drilled for the benefit of the entity. Under the development agreement, approximately 17, 77 and 84 qualified net wells were added in 2014, 2013 and 2012, respectively. Through December 31, 2014, we had met all current drilling commitments associated with the CHK C-T transaction.
The CHK C-T investors’ right to receive, proportionately, a 3.75% ORRI in the contributed wells and up to 1,000 future net wells on our contributed leasehold is subject to an increase to 5% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs from 2012 through the first quarter of 2025. However, in no event are we required to deliver to investors more than a total ORRI of 3.75% in existing wells and 1,000 future net wells. If at any time CHK C-T holds fewer net acres than would enable us to drill all then-remaining net wells on 160-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. CHK C-T retains the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 867 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. We had met our ORRI conveyance commitment as of December 31, 2013, but we did not meet the 2014 ORRI conveyance commitment as of December 31, 2014.
As of December 31, 2014 and 2013, $1.015 billion of noncontrolling interests on our consolidated balance sheets were attributable to CHK C-T. For 2014, 2013 and 2012, income of $75 million, $75 million and $57 million, respectively, was attributable to the noncontrolling interests of CHK C-T.
Utica Financial Transaction. We formed CHK Utica, L.L.C. (CHK Utica) in October 2011 to develop a portion of our Utica Shale oil and natural gas assets. In exchange for all of the common shares of CHK Utica, we contributed to CHK Utica approximately 700,000 net acres of leasehold and the existing wells within an area of mutual interest in the Utica Shale play covering 13 counties located primarily in eastern Ohio. During November and December 2011, in private placements, third-party investors contributed $1.25 billion in cash to CHK Utica in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3% ORRI in 1,500 net wells to be drilled on certain of our Utica Shale leasehold.
In 2014, we repurchased all of the outstanding preferred shares of CHK Utica from third-party preferred shareholders for approximately $1.254 billion, or approximately $1,189 per share including accrued dividends. The $447 million difference between the cash paid for the preferred shares and the carrying value of the noncontrolling interest acquired is reflected in retained earnings and as a reduction to net income available to common stockholders for purposes of our EPS computations. Pursuant to the transaction, our obligation to pay quarterly dividends to third-party preferred shareholders was eliminated. In addition, the development agreement was terminated pursuant to the transaction, which eliminated our obligation to drill and complete a minimum number of wells within a specified period for the benefit of CHK Utica. Our repurchase of the outstanding preferred shares in CHK Utica did not affect our obligation to deliver a 3% ORRI in 1,500 net wells on certain Utica Shale leasehold.
The CHK Utica investors’ right to receive, proportionately, a 3% ORRI in the first 1,500 net wells drilled on our Utica Shale leasehold is subject to an increase to 4% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs from 2012 through 2023. However, in no event are we required to deliver to investors more than a total ORRI of 3% in 1,500 net wells. If at any time we hold fewer net acres than would enable us to drill all then-remaining net wells on 150-acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. We retain the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 1,300 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the future conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. Because we did not meet our ORRI commitment in 2012, the ORRI increased to 4% for wells earned in 2013, and the ultimate number of wells in which we must assign an interest will be reduced accordingly. We met the 2013 ORRI conveyance commitment as of December 31, 2013 and met the 2014 ORRI conveyance commitment as of December 31, 2014 associated with the CHK Utica transaction.
As of December 31, 2014 and 2013, $0 and $807 million, respectively, of noncontrolling interests on our consolidated balance sheets were attributable to CHK Utica. In 2014, 2013 and 2012, income of approximately $43 million, $79 million and $88 million, respectively, was attributable to the noncontrolling interests of CHK Utica.
Chesapeake Granite Wash Trust. In November 2011, Chesapeake Granite Wash Trust (the Trust) sold 23,000,000 common units representing beneficial interests in the Trust at a price of $19.00 per common unit in its initial public offering. The common units are listed on the New York Stock Exchange and trade under the symbol “CHKR”. We own 12,062,500 common units and 11,687,500 subordinated units, which in the aggregate represent an approximate 51% beneficial interest in the Trust. The Trust has a total of 46,750,000 units outstanding.
In connection with the initial public offering of the Trust, we conveyed royalty interests to the Trust that entitle the Trust to receive (i) 90% of the proceeds (after deducting certain post-production expenses and any applicable taxes) that we receive from the production of hydrocarbons from 69 producing wells, and (ii) 50% of the proceeds (after deducting certain post-production expenses and any applicable taxes) in 118 development wells that have been or will be drilled on approximately 45,400 gross acres (29,000 net acres) in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma. Pursuant to the terms of a development agreement with the Trust, we are obligated to drill, or cause to be drilled, the development wells at our own expense prior to June 30, 2016, and the Trust is not responsible for any costs related to the drilling of the development wells or any other operating or capital costs of the Trust properties. In addition, we granted to the Trust a lien on our remaining interests in the undeveloped properties that are subject to the development agreement in order to secure our drilling obligation to the Trust, although the maximum amount that may be recovered by the Trust under the lien cannot exceed $263 million initially and will be proportionately reduced as we fulfill our drilling obligation over time. As of December 31, 2014 and 2013, we had drilled or caused to be drilled approximately 102 and 82 development wells, respectively, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $36 million and $79 million, respectively.
The subordinated units we hold in the Trust are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is not less than the applicable subordination threshold for the quarter. If there is not sufficient cash to fund a distribution on all of the Trust units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for the quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. The distribution made with respect to the subordinated units to Chesapeake was either reduced or eliminated for each of the most recent ten quarters of distributions paid. In exchange for agreeing to subordinate a portion of our Trust units, and in order to provide additional financial incentive to us to satisfy our drilling obligation and perform operations on the underlying properties in an efficient and cost-effective manner, Chesapeake is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on the Trust units in any quarter exceeds the applicable incentive threshold for the quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold will be paid to Trust unitholders, including Chesapeake, on a pro rata basis. Through December 31, 2014, no incentive distributions had been made. At the end of the fourth full calendar quarter following our satisfaction of our drilling obligation with respect to the development wells, the subordinated units will automatically convert into common units on a one-for-one basis and our right to receive incentive distributions will terminate. After such time, the common units will no longer have the protection of the subordination threshold, and all Trust unitholders will share in the Trust’s distributions on a pro rata basis.
For the years ended December 31, 2014, 2013 and 2012, the Trust declared and paid the following distributions:
Production Period		Distribution Date		Cash Distribution				Cash Distribution
				per				per
				Common Unit				Subordinated Unit
June 2014 - August 2014		December 1, 2014		$	0.5079			$	—
March 2014 - May 2014		August 29, 2014		$	0.5796			$	—
December 2013 - February 2014		May 30, 2014		$	0.6454			$	—
September 2013 - November 2013		March 3, 2014		$	0.6624			$	—
June 2013 - August 2013		November 29, 2013		$	0.6671			$	—
March 2013 - May 2013		August 29, 2013		$	0.69			$	0.1432
December 2012 - February 2013		May 31, 2013		$	0.69			$	0.301
September 2012 - November 2012		March 1, 2013		$	0.67			$	0.3772
June 2012 - August 2012		November 29, 2012		$	0.63			$	0.2208
March 2012 - May 2012		August 30, 2012		$	0.61			$	0.4819
December 2011 - February 2012		May 31, 2012		$	0.6588			$	0.6588
September 2011 - November 2011		March 1, 2012		$	0.7277			$	0.7277
We have determined that the Trust is a variable interest entity (VIE) and that Chesapeake is the primary beneficiary. As a result, the Trust is included in our consolidated financial statements. As of December 31, 2014 and 2013, $287 million and $314 million, respectively, of noncontrolling interests on our consolidated balance sheets were attributable to the Trust. In 2014, 2013 and 2012, income of approximately $24 million, $20 million and $35 million, respectively, was attributable to the Trust’s noncontrolling interests in our consolidated statements of operations. See Note 15 for further discussion of VIEs.
Wireless Seismic, Inc. As of December 31, 2014, we no longer consolidated Wireless Seismic, Inc. (Wireless), a privately owned company engaged in research, development and production of wireless seismic systems and related technology that delivers seismic information obtained from standard geophones in real time to personal computers. Because we no longer have a controlling equity interest in Wireless, our interest is included in investments in our consolidated balance sheet and within other in the table in Note 14.

ShareBased_Compensation_Note

Share-Based Compensation (Note)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	Share-Based Compensation
	Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units (PSUs) granted to employees and common stock and restricted stock granted to non-employee directors under our long term incentive plans. The restricted stock and stock options are equity-classified awards and the PSUs are liability-classified awards. In connection with the spin-off of our oilfield services business on June 30, 2014, and pursuant to the terms of our share-based compensation plans and the employee matters agreement between Chesapeake and Seventy Seven Energy Inc., unexercised stock options and unvested restricted stock were modified as of the date of the spin-off. The modifications were designed to ensure that the value of each award of unexercised stock options and unvested restricted stock did not change as a result of the spin-off. The number of stock options and number of shares of restricted stock reported below have been adjusted to reflect modifications on the spin-off date.
	Share-Based Compensation Plans
	2014 Long Term Incentive Plan. Our 2014 Long Term Incentive Plan (2014 LTIP), which is administered by the Compensation Committee of our Board of Directors, became effective on June 13, 2014 after it was approved by shareholders at our 2014 Annual Meeting. The 2014 LTIP replaced our Amended and Restated Long Term Incentive Plan (2005 LTIP) which was adopted in 2005. The 2014 LTIP provides for up to 36,600,000 shares of common stock that may be issued as long-term incentive compensation to our employees and non-employee directors; provided, however, that the 2014 LTIP uses a fungible share pool under which (i) each share issued pursuant to a stock option or stock appreciation right (SAR) reduces the number of shares available under the 2014 LTIP by 1.0 share; (ii) each share issued pursuant to awards other than options and SARs reduces the number of shares available by 2.12 shares; and (iii) PSUs and other performance awards which are payable solely in cash are not counted against the aggregate number of shares issuable. In addition, the 2014 LTIP prohibits the reuse of shares withheld or delivered to satisfy the exercise price of, or to satisfy tax withholding requirements for, an option or SAR. The 2014 LTIP also prohibits “net share counting” upon the exercise of options or SARs.
	The 2014 LTIP authorizes the issuance of the following types of awards: (i) nonqualified and incentive stock options; (ii) SARs; (iii) restricted stock; (iv) performance awards, including PSUs; and (v) other stock-based awards. For both stock options and SARs, the exercise price may not be less than the fair market value of our common stock on the date of grant and the maximum exercise period may not exceed ten years from the date of grant. Awards granted under the plan vest at specified dates and/or upon the satisfaction of certain performance or other criteria, as determined by the Compensation Committee. In 2014, we issued 50,771 and 272,289 shares of restricted stock, net of forfeitures, to non-employee directors and employees, respectively, under the 2014 LTIP. As of December 31, 2014, 36 million shares of common stock remained issuable under the 2014 LTIP.
	2005 Long Term Incentive Plan. Chesapeake’s 2005 LTIP, which terminated upon shareholder approval of the 2014 LTIP on June 13, 2014, provided for the issuance of restricted stock, stock options and PSUs to employees, directors and consultants of Chesapeake. Subject to any adjustments as provided by the plan, the aggregate number of shares of common stock available for awards under the plan was limited to 59,300,000 shares. The maximum period for exercise of an option or SAR was not more than ten years from the date of grant, and the exercise price was not less than the fair market value of the shares underlying the option or SAR on the date of grant. Awards granted under the plan became vested at specified dates or upon the satisfaction of certain performance or other criteria determined by a committee of the Board of Directors. The plan was approved by our shareholders. We issued 48,083, 147,108 and 170,151 shares of restricted stock to non-employee directors under the 2005 LTIP in 2014, 2013 and 2012, respectively. We issued options to purchase 993,730, 5.3 million and no shares of common stock to employees and consultants under the 2005 LTIP in 2014, 2013 and 2012, respectively. Additionally, we issued 1.3 million, 2.5 million and 5.0 million shares of restricted stock, net of forfeitures, to employees and consultants under the 2005 LTIP in 2014, 2013 and 2012, respectively.
	2003 Stock Award Plan for Non-Employee Directors. Under Chesapeake's 2003 Stock Award Plan for Non-Employee Directors (2003 Non-Employee Director Plan), a maximum of 10,000 shares of Chesapeake's common stock is awarded to each newly appointed non-employee director on his or her first day of service. Subject to any adjustments as provided by the plan, the aggregate number of shares issued may not exceed 250,000 shares. The plan was approved by our shareholders. We issued 10,000, 20,000 and 30,000 shares of common stock to newly appointed non-employee directors under the 2003 Non-Employee Director Plan in 2014, 2013 and 2012, respectively. As of December 31, 2014, there were 120,000 shares remaining available for issuance under the 2003 Non-Employee Director Plan.
	Equity-Classified Awards
	Restricted Stock. We grant restricted stock to employees and non-employee directors. Restricted stock vests over a minimum of three years and the holder receives dividends on unvested shares. A summary of the changes in unvested restricted stock during 2014, 2013 and 2012 is presented below.
			Shares of			Weighted Average
			Unvested			Grant Date
			Restricted Stock			Fair Value
			(in thousands)
	Unvested restricted stock as of January 1, 2014		13,400			$	23.38
	Granted		5,049			$	25.92
	Vested		(4,803	)		$	27.17
	Forfeited		(3,555	)		$	28.09
	Unvested restricted stock as of December 31, 2014		10,091			$	21.2
	Unvested restricted stock as of January 1, 2013		18,899			$	23.72
	Granted		9,189			$	19.68
	Vested		(12,897	)		$	21.32
	Forfeited		(1,791	)		$	22.86
	Unvested restricted stock as of December 31, 2013		13,400			$	23.38
	Unvested restricted stock as of January 1, 2012		19,544			$	26.97
	Granted		9,480			$	21.13
	Vested		(8,620	)		$	28.08
	Forfeited		(1,505	)		$	24.57
	Unvested restricted stock as of December 31, 2012		18,899			$	23.72
	The aggregate intrinsic value of restricted stock that vested during 2014 was approximately $130 million based on the stock price at the time of vesting.
	As of December 31, 2014, there was approximately $135 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 2.02 years.
	The vesting of certain restricted stock grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant. During 2014, we recognized an excess tax benefit related to restricted stock of $12 million. During 2013 and 2012, we recognized reductions in tax benefits related to restricted stock of $14 million and $32 million, respectively. Each adjustment was recorded to additional paid-in capital and deferred income taxes.
	Stock Options. In 2014 and 2013, we granted members of senior management stock options that vest ratably over a three-year period. In January 2013, we also granted retention awards to certain officers of stock options that vest one-third on each of the third, fourth and fifth anniversaries of the grant date. Each stock option award has an exercise price equal to the closing price of the Company’s common stock on the grant date. Outstanding options generally expire ten years from the date of grant.
	We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method, as there is no adequate historical exercise behavior available. Volatility assumptions are estimated based on an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's current dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2014:
	Expected option life - years		5.9
	Volatility		48.63	%
	Risk-free interest rate		1.93	%
	Dividend yield		1.33	%
	The following table provides information related to stock option activity for 2014, 2013 and 2012:
			Number of			Weighted			Weighted		Aggregate
			Shares			Average			Average		Intrinsic
			Underlying			Exercise			Contract		Value(a)
			Options			Price			Life in
						Per Share			Years
			(in thousands)								($ in millions)
	Outstanding at January 1, 2014		5,268			$	19.28		6.66		$	41
	Granted		994			$	24.43
	Exercised		(1,322	)		$	18.71				$	11
	Expired		(28	)		$	18.97
	Forfeited		(313	)		$	21.05
	Outstanding at December 31, 2014		4,599			$	19.55		7.03		$	5
	Exercisable at December 31, 2014		1,304			$	18.71		5.7		$	1
	Outstanding at January 1, 2013		481			$	12.69		0.96		$	2
	Granted		5,264			$	19.32
	Exercised		(346	)		$	10.82				$	3
	Expired		(131	)		$	19.31
	Outstanding at December 31, 2013		5,268			$	19.28		6.66		$	41
	Exercisable at December 31, 2013		1,552			$	18.82		1.97		$	13
	Outstanding at January 1, 2012		1,051			$	9.84		1.41		$	13
	Exercised		(570	)		$	7.45				$	7
	Outstanding and exercisable at December 31, 2012		481			$	12.69		0.96		$	2
	___________________________________________
	(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.
	As of December 31, 2014, there was $11 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 2.02 years.
	The vesting of certain stock option grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant. During 2014, 2013 and 2012, we recognized excess tax benefits related to stock options of $3 million, $1 million and $2 million, respectively. Each adjustment was recorded to additional paid-in capital and deferred income taxes.
Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2014, 2013 and 2012:
		Years Ended December 31,
		2014				2013			2012
		($ in millions)
General and administrative expenses		$	46			$	60		$	71
Oil and natural gas properties		29				52			71
Oil, natural gas and NGL production expenses		18				21			24
Marketing, gathering and compression expenses		6				7			15
Oilfield services expenses		5				10			10
Total		$	104			$	150		$	191
Liability-Classified Awards
Performance Share Units. In 2012, 2013 and 2014, we granted PSUs to senior management that settle in cash at the end of their respective performance periods and vest ratably over their respective terms. The 2012 awards were granted in one-, two- and three-year tranches and are settled in cash on the first, second and third anniversary dates of the awards, and the 2013 and 2014 awards are settled in cash on the third anniversary of the awards. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors, which include total shareholder return (TSR) and, for certain of the awards, the achievement of operational performance goals such as production and proved reserve growth.
For PSUs granted in 2012, each of the TSR and operational payout components can range from 0% to 125% resulting in a maximum total payout of 250%. For PSUs granted in 2013, the TSR component can range from 0% to 125% and each of the two operational components can range from 0% to 62.5%; however, the maximum total payout is capped at 200%. For PSUs granted in 2014, the TSR component can range from 0% to 200%, with no operational components. For the 2013 and 2014 PSUs, the payout percentage is capped at 100% if the Company’s absolute TSR is less than zero. Compensation expense associated with the PSU grants is recognized over the service period. The number of units settled is dependent upon the Company’s estimates of the underlying performance measures. For the 2014 awards, the Company utilized the Monte Carlo simulation for the TSR performance measure, and the following assumptions to determine the grant date fair value of the PSUs:
Volatility		41.37	%
Risk-free interest rate		0.76	%
Dividend yield for value of awards		1.36	%
The following table presents a summary of our PSU awards:
		Units			Fair Value			Fair Value(a)				Liability for
					as of							Vested
					Grant Date							Amount
					($ in millions)
2012 Awards (b)
Payable 2015		884,507			$	23		$	12			$	12
2013 Awards
Payable 2016		1,701,941			$	35		$	42			$	39
2014 Awards
Payable 2017		609,637			$	16		$	10			$	7
___________________________________________
(a)	As of December 31, 2014.
(b)	In 2014 and 2013, we paid $11 million and $2 million, respectively, related to 2012 PSU awards.
PSU Compensation. We recognized the following compensation costs related to PSUs for the years ended December 31, 2014, 2013 and 2012:
		Years Ended December 31,
		2014				2013			2012
		($ in millions)
General and administrative expenses		$	(4	)		$	34		$	8
Oil and natural gas properties		3				9			4
Oil, natural gas and NGL production expenses		—				2			1
Marketing, gathering and compression expenses		—				2			1
Oilfield services expenses		—				1			—
Total		$	(1	)		$	48		$	14
Effect of the Spin-off on Share-Based Compensation
The employee matters agreement entered into in connection with the spin-off of our oilfield services business (see Note 13) addresses the treatment of holders of Chesapeake stock options, restricted stock and PSUs. Unvested equity-based compensation awards held by COO employees were canceled and replaced with new awards of SSE, and unvested equity-based compensation awards held by Chesapeake employees were adjusted to account for the spin-off, each as of the spin-off date. The employee matters agreement provides that employees of SSE ceased to participate in benefit plans sponsored or maintained by Chesapeake as of the spin-off date. In addition, the employee matters agreement provides that as of the spin-off date, each party is responsible for the compensation of its current employees and for all liabilities relating to its former employees, as determined by their respective employer on the date of termination.

Employee_Benefit_Plans_Note

Employee Benefit Plans (Note)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Compensation and Employee Benefit Plans [Text Block]	Employee Benefit Plans
	Our qualified 401(k) profit sharing plan (401(k) Plan) is the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, which is open to employees of Chesapeake and all our subsidiaries except certain employees of Chesapeake Appalachia, L.L.C. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. Through December 31, 2014, Chesapeake matched employee contributions dollar for dollar (subject to a maximum contribution of 15% of an employee's base salary and performance bonus) with Chesapeake common stock purchased in the open market. The Company contributed $61 million, $81 million and $91 million to the 401(k) Plan in 2014, 2013 and 2012, respectively. Beginning January 1, 2015, Chesapeake will match employee contributions in cash.
	Chesapeake also maintains a nonqualified deferred compensation plan (DC Plan). To be eligible to participate in the DC Plan, an active employee must have a base salary of at least $150,000, have a hire date on or before the December 1 immediately preceding the year in which the employee is able to participate, or be designated as eligible to participate. Only the top 10% of Company wage earners are eligible to participate. Additionally, the employee has to have made the maximum contribution allowable under the 401(k) Plan. Chesapeake matches 100% of employee contributions up to 15% of base salary and performance bonus in the aggregate for the DC Plan with Chesapeake common stock, and an employee who is at least age 55 may elect for the matching contributions to be made in any one of the DC Plan’s investment options. The maximum compensation that can be deferred by employees under all Company deferred compensation plans, including the Chesapeake 401(k) Plan, is a total of 75% of base salary and 100% of performance bonus. The Company contributed $7 million, $14 million and $16 million to the DC Plan during 2014, 2013 and 2012, respectively, to fund the match. In addition, in 2012 the Board of Directors adopted a deferred compensation plan for non-employee directors (Director DC Plan). The Company's non-employee directors are able to defer up to 100% of director cash compensation into the Director DC Plan and invest in Chesapeake common stock, but the plan does not provide for Company matching contributions.
	Any assets placed in trust by Chesapeake to fund future obligations of the Company's nonqualified deferred compensation plans are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their deferred compensation in the plans. Chesapeake maintains no post-employment benefit plans except those sponsored by its wholly owned subsidiary Chesapeake Appalachia, L.L.C. Participation in these plans is limited to existing employees who are union members and former employees who were union members. The Chesapeake Appalachia, L.L.C. benefit plans provide health care and life insurance benefits to eligible employees upon retirement. We account for these benefits on an accrual basis. As of December 31, 2014, the Company had accrued approximately $3 million in accumulated post-employment benefit liability.

Derivative_and_Hedging_Activit

Derivative and Hedging Activities (Note)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative and Hedging Activities Disclosure [Text Block]	Derivative and Hedging Activities
	Chesapeake uses commodity derivative instruments to secure attractive pricing and margins on expected production, to reduce its exposure to fluctuations in future commodity prices and to protect its expected operating cash flow against significant market movements or volatility. Chesapeake also uses derivative instruments to mitigate a portion of its exposure to interest rate and foreign currency exchange rate fluctuations. 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.
	Oil and Natural Gas Derivatives
	As of December 31, 2014 and 2013, our oil and natural gas derivative instruments consisted 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 prices, 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 call option. This eliminates the counterparty’s downside exposure below the second put option strike price.
	•	Options: Chesapeake sells, and occasionally buys, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options, and Chesapeake receives the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
	•	Call Swaptions: Chesapeake sells call swaptions in exchange for a premium that allows a counterparty, on a specific date, to enter into a fixed-price swap for a certain period of time.
	•	Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. Chesapeake receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity.
	The estimated fair values of our oil and natural gas derivative instrument assets (liabilities) as of December 31, 2014 and 2013 are provided below.
			31-Dec-14							31-Dec-13
			Volume			Fair Value				Volume			Fair Value
						($ in millions)							($ in millions)
	Oil (mmbbl):
	Fixed-price swaps		12.5			471				25.3			(50		)
	Three-way collars		4.4			40				—			—
	Call options		35.8			(89		)		42.5			(265		)
	Basis protection swaps		—			—				0.4			1
	Total oil		52.7			422				68.2			(314		)
	Natural gas (tbtu):
	Fixed-price swaps		275			$	281			448			$	(23	)
	Three-way collars		207			165				288			(7		)
	Call options		193			(170		)		193			(210		)
	Call swaptions		—			—				12			—
	Basis protection swaps		60			23				68			3
	Total natural gas		735			299				1,009			(237		)
	Total estimated fair value					$	721						$	(551	)
	We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. See further discussion below under Effect of Derivative Instruments - Accumulated Other Comprehensive Income (Loss).
	Interest Rate Derivatives
	As of December 31, 2014 and 2013, our interest rate derivative instruments consisted of swaps. We enter 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 facility borrowings.
	The notional amount of our interest rate derivatives, associated with our long-term debt, as of December 31, 2014 and 2013 was $850 million and $2.250 billion, respectively. The estimated fair value of our interest rate derivative liabilities as of December 31, 2014 and 2013 was $17 million and $98 million, respectively.
	We have terminated certain fair value hedges related to senior notes. Gains and losses related to these terminated hedges will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next six years, we will recognize $10 million in net gains related to these transactions.
	Foreign Currency Derivatives
	We are party to cross currency swaps to mitigate our exposure to foreign currency exchange rate fluctuations that may result from the €344 million principal amount of our euro-denominated senior notes. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Under the terms of the cross currency swaps we currently hold, on each semi-annual interest payment date, the counterparties pay us €11 million and we pay the counterparties $17 million, which yields an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay us €344 million and we will pay the counterparties $459 million. The swaps are designated as cash flow hedges and, because they are entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value do not impact earnings. The fair values of the cross currency swaps are recorded on the consolidated balance sheet as a liability of $53 million and an asset of $2 million as of December 31, 2014 and 2013, respectively. The euro-denominated debt in long-term debt has been adjusted to $416 million as of December 31, 2014 using an exchange rate of $1.2098 to €1.00.
	Effect of Derivative Instruments – Consolidated Balance Sheets
	The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2014 and 2013 on a gross basis and after same-counterparty netting:
	Balance Sheet Classification		Gross				Amounts Netted				Net Fair Value Presented
			Fair Value				in Consolidated				in Consolidated
							Balance Sheet				Balance Sheet
			($ in millions)
	As of December 31, 2014
	Commodity Contracts
	Short-term derivative asset		$	974			$	(95	)		$	879
	Long-term derivative asset		16				(10		)		6
	Short-term derivative liability		(105		)		95				(10		)
	Long-term derivative liability		(163		)		10				(153		)
	Total commodity contracts		722				—				722
	Interest Rate Contracts
	Short-term derivative liability		(5		)		—				(5		)
	Long-term derivative liability		(12		)		—				(12		)
	Total interest rate contracts		(17		)		—				(17		)
	Foreign Currency Contracts(a)
	Long-term derivative liability		(53		)		—				(53		)
	Total foreign currency contracts		(53		)		—				(53		)
	Total Derivatives		$	652			$	—			$	652
	As of December 31, 2013
	Commodity Contracts
	Short-term derivative asset		$	29			$	(29	)		$	—
	Long-term derivative asset		11				(9		)		2
	Short-term derivative liability		(231		)		29				(202		)
	Long-term derivative liability		(362		)		9				(353		)
	Total commodity contracts		(553		)		—				(553		)
	Interest Rate Contracts
	Short-term derivative liability		(6		)		—				(6		)
Long-term derivative liability		(92		)		—				(92		)
Total interest rate contracts		(98		)		—				(98		)
Foreign Currency Contracts(a)
Long-term derivative asset		2				—				2
Total foreign currency contracts		2				—				2
Total Derivatives		$	(649	)		$	—			$	(649	)
____________________________________________
(a)	Designated as cash flow hedging instruments.
As of December 31, 2014 and 2013, we did not have any cash collateral balances for these derivatives.
Effect of Derivative Instruments – Consolidated Statements of Operations
The components of oil, natural gas and NGL sales for the years ended December 31, 2014, 2013 and 2012 are presented below.
		Years Ended December 31,
		2014				2013				2012
		($ in millions)
Oil, natural gas and NGL sales		$	7,162			$	6,923			$	5,359
Gains on undesignated oil and natural gas derivatives		1,055				443				857
Gains (losses) on terminated cash flow hedges		(37		)		(314		)		62
Total oil, natural gas and NGL sales		$	8,180			$	7,052			$	6,278
The components of interest expense for the years ended December 31, 2014, 2013 and 2012 are presented below.
		Years Ended December 31,
		2014				2013				2012
		($ in millions)
Interest expense on senior notes		$	704			$	740			$	732
Interest expense on term loans		36				116				173
Amortization of loan discount, issuance costs and other		42				91				89
Interest expense on credit facilities		28				38				70
Gains on terminated fair value hedges		(3		)		(5		)		(8		)
(Gains) losses on undesignated interest rate derivatives		(81		)		63				1
Capitalized interest		(637		)		(816		)		(980		)
Total interest expense		$	89			$	227			$	77
Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss)
A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
		Years Ended December 31,
		2014								2013							2012
		Before				After				Before				After			Before			After
		Tax				Tax				Tax				Tax			Tax			Tax
		($ in millions)
Balance, beginning of period		$	(269	)		$	(167	)		$	(304	)		$	(189	)	$	(287	)	$	(178	)
Net change in fair value		1				1				3				2			10			6
Gains (losses) reclassified to income		37				23				32				20			(27		)	(17		)
Balance, end of period		$	(231	)		$	(143	)		$	(269	)		$	(167	)	$	(304	)	$	(189	)
Approximately $136 million of the $143 million of accumulated other comprehensive loss as of December 31, 2014 represents the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. These amounts will be recognized in earnings in the month in which the originally forecasted hedged production occurs. As of December 31, 2014, we expect to transfer approximately $23 million of net loss included in accumulated other comprehensive income to net income during the next 12 months. The remaining amounts will be transferred by December 31, 2022.
Credit Risk Considerations
Over-the-counter traded derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment grade and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2014, our oil, natural gas and interest rate derivative instruments were spread among 18 counterparties.
Hedging Facility
Our secured commodity hedging facility with 17 counterparties provides approximately 1.031 bboe of hedging capacity for oil, natural gas and NGL price derivatives and 1.031 bboe for basis derivatives with an aggregate mark-to-market capacity of $16.5 billion. The facility is secured by proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times at semi-annual collateral redetermination dates and 1.30 times in between those dates, and guarantees by certain subsidiaries that also guarantee our revolving credit facility and indentures. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain requirements are met including maintaining specified collateral coverage ratios as well as maintaining credit ratings with either of the designated rating agencies at or above current levels. 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 Chesapeake exceed defined thresholds. As of December 31, 2014, we had hedged under the facility 164 mmboe of our future production with price derivatives and 10 mmboe with basis derivatives.
Fair Value
The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil and natural gas forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by our counterparties for reasonableness. Since oil, natural gas, interest rate and cross currency swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into 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.
The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:
		Quoted				Significant				Significant				Total
		Prices in				Other				Unobservable				Fair Value
		Active				Observable				Inputs
		Markets				Inputs				(Level 3)
		(Level 1)				(Level 2)
						($ in millions)
As of December 31, 2014
Derivative Assets (Liabilities):
Commodity assets		$	—			$	785			$	205			$	990
Commodity liabilities		—				(9		)		(259		)		(268		)
Interest rate liabilities		—				(17		)		—				(17		)
Foreign currency liabilities		—				(53		)		—				(53		)
Total derivatives		$	—			$	706			$	(54	)		$	652
As of December 31, 2013
Derivative Assets (Liabilities):
Commodity assets		$	—			$	25			$	15			$	40
Commodity liabilities		—				(100		)		(493		)		(593		)
Interest rate liabilities		—				(98		)		—				(98		)
Foreign currency assets		—				2				—				2
Total derivatives		$	—			$	(171	)		$	(478	)		$	(649	)
A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2014 and 2013 is presented below.
		Derivatives
		Commodity				Interest Rate
		($ in millions)
Beginning Balance as of January 1, 2014		$	(478	)		$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)		292				—
Total purchases, issuances, sales and settlements:
Settlements		136				—
Transfers(b)		(4		)		—
Ending Balance as of December 31, 2014		$	(54	)		$	—
Beginning Balance as of January 1, 2013		$	(1,016	)		$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)		410				(1		)
Total purchases, issuances, sales and settlements:
Sales		—				1
Settlements		128				—
Ending Balance as of December 31, 2013		$	(478	)		$	—
___________________________________________
(a)		Oil, Natural Gas and								Interest Expense
		NGL Sales
		2014				2013				2014				2013
		($ in millions)
Total gains (losses) included in earnings for the period		$	292			$	410			$	—			$	(1	)
Change in unrealized gains (losses) related to		$	262			$	382			$	—			$	—
assets still held at reporting date
(b)	The values related to basis swaps were transferred from Level 3 to Level 2 as a result of our ability to begin using data readily available in the public market to corroborate our estimated fair values.
Qualitative and Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements
The significant unobservable inputs for Level 3 derivative contracts include unpublished forward prices of oil and natural gas, market volatility and credit risk of counterparties. Changes in these inputs impact the fair value measurement of our derivative contracts. For example, an increase (decrease) in the forward prices and volatility of oil and natural gas prices decreases (increases) the fair value of oil and natural gas derivatives and adverse changes to our counterparties’ creditworthiness decreases the fair value of our derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of December 31, 2014:
Instrument		Unobservable		Range		Weighted		Fair Value
Type		Input				Average		December 31, 2014(a)
								($ in millions)
Oil trades		Oil price volatility curves		27.33% - 43.56%		34.09%		$	(49	)
Natural gas trades		Natural gas price volatility		18.71% - 63.70%		34.38%		$	(5	)
		curves
___________________________________________
(a)	Fair value is based on an estimate derived from option models.

Natural_Gas_and_Oil_Property_T

Natural Gas and Oil Property Transactions (Note)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Mergers, Acquisitions and Dispositions Disclosure [Text Block]	Oil and Natural Gas Property Transactions
	Under full cost accounting rules, we have accounted for the sale of oil and natural gas properties as an adjustment to capitalized costs, with no recognition of gain or loss as the sales have not involved a significant change in proved reserves or significantly altered the relationship between costs and proved reserves.
	2014 Transactions
	We sold certain assets in the southern Marcellus Shale and a portion of the eastern Utica Shale to a subsidiary of Southwestern Energy Company for aggregate net proceeds of approximately $4.975 billion. We sold approximately 413,000 net acres and approximately 1,500 wells in northern West Virginia and southern Pennsylvania, of which 435 wells are in the Marcellus or Utica formations, along with related gathering assets and property, plant and equipment.
	We exchanged interests in approximately 440,000 gross acres in the Powder River Basin in southeastern Wyoming with RKI Exploration & Production, LLC (RKI). Under the agreement, we conveyed to RKI approximately 137,000 net acres and our interest in 67 gross wells with an average working interest of approximately 22% in the northern portion of the Powder River Basin, where RKI is currently designated operator. In exchange, RKI conveyed to us approximately 203,000 net acres and its interest in 186 gross wells with an average working interest of 48% in the southern portion of the Powder River Basin, where we are currently designated operator. In addition to the exchange, we paid RKI approximately $450 million in cash.
	We sold noncore leasehold interests in the Marcellus Shale to a subsidiary of Rice Energy Inc. for net proceeds of approximately $233 million.
	We sold noncore leasehold interests, producing properties and 61 wellhead compressor units in South Texas to Hilcorp Energy Company for net proceeds of approximately $133 million. All commitments related to VPP #5 were also transferred. See Volumetric Production Payments below.
	We sold noncore leasehold interests and producing properties in East Texas and Louisiana for net proceeds of approximately $63 million. All commitments related to VPP #6 were also transferred. See Volumetric Production Payments below.
	Excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds of approximately $379 million related to the divestiture of various other oil and natural gas properties.
	2013 Transactions
	We sold a wholly owned subsidiary, MKR Holdings, L.L.C. (MKR), to Chief Oil and Gas and two of its working interest partners, Enerplus Corporation and Tug Hill Operating. Net proceeds from the transaction were approximately $490 million. MKR held producing wells and undeveloped acreage in the Marcellus Shale.
	We sold assets in the Haynesville Shale to EXCO Operating Company, LP (EXCO) for net proceeds of approximately $257 million. Subsequent to closing, we received approximately $47 million of additional net proceeds for post-closing adjustments. The assets sold included our operated and non-operated interests in approximately 9,600 net acres in DeSoto and Caddo parishes, Louisiana.
	We sold noncore leasehold interests and producing properties in the northern Eagle Ford Shale to EXCO for net proceeds of approximately $617 million. Subsequent to closing, we received approximately $57 million and $32 million in 2014 and 2013, respectively, of additional net proceeds and for post-closing adjustments. The assets sold included approximately 55,000 net acres in Zavala, Dimmit, La Salle and Frio counties, Texas.
	2012 Transactions
	We sold the vast majority of our Permian Basin assets, representing approximately 6% of our total proved reserves as of June 30, 2012, in three separate transactions for total net cash proceeds of approximately $3.091 billion. Following the closing, we received $466 million of additional consideration that was withheld subject to certain title, environmental and other standard contingencies. Of the total proceeds, we allocated approximately $42 million to our Permian Basin midstream and other fixed assets. The remaining proceeds were allocated to our Permian Basin oil and natural gas properties.
	We sold approximately 40,000 net acres of noncore leasehold in the Chitwood Knox play in Oklahoma for approximately $540 million in cash.
	We sold approximately 72,000 net acres of noncore leasehold in the Utica Shale play in Ohio to affiliates of EnerVest, Ltd. for approximately $358 million in cash.
	We sold approximately 60,000 net acres of leasehold in the Texoma Woodford play in Oklahoma to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation, for net proceeds of approximately $572 million.
	Joint Ventures
	Between July 2008 and June 2013, we entered into eight significant joint ventures with other leading energy companies including Sinopec International Petroleum Exploration and Production (Sinopec), Total S.A. (Total), CNOOC Limited, Statoil, BP America and Freeport-McMoRan Copper & Gold (formerly known as Plains Exploration & Production Company), pursuant to which we sold portions ranging from 20% to 50% of certain leasehold, producing properties and other assets located in eight different resource plays. In return, we received aggregate cash proceeds of $8.0 billion and commitments by our joint venture partners to pay, in the aggregate, our share of future drilling and completion costs of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all drilling, completion and operations, the majority of leasing and, in certain transactions, marketing activities for the project. Each joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner and, if applicable, pays a specified percentage of our drilling and completion costs in designated wells. As of December 31, 2014, we had utilized all drilling carries from our joint venture partners except for Total’s remaining $51 million commitment to pay 60% of our drilling and completion costs for wells drilled in the Utica Shale play. We fully expect to use this drilling carry commitment prior to its expiration in December 2018.
	In 2014, 2013 and 2012, our drilling and completion costs included the benefit of approximately $679 million, $884 million and $784 million, respectively, in drilling and completion carries paid by our joint venture partners.
	In 2013, we entered into a joint venture with Sinopec in which Sinopec purchased a 50% undivided interest in approximately 850,000 acres in the Mississippian Lime play in northern Oklahoma for $1.11 billion, including $90 million we received for closing adjustments and $71 million placed in escrow with respect to certain post-closing adjustments. As of December 31, 2014, we had received $64 million of the $71 million held in escrow. There was no drilling and completion carry associated with this transaction.
	In addition, in 2014, 2013 and 2012, we sold interests in additional leasehold we acquired in the Marcellus, Barnett, Utica, Eagle Ford and Mid-Continent plays to our joint venture partners for approximately $33 million, $58 million and $272 million, respectively.
	Volumetric Production Payments
	From time to time, we have sold certain of our producing assets located in more mature producing regions through the sale of VPPs. A VPP is a limited-term overriding royalty interest in oil and natural gas reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain all production beyond the specified volumes, if any, after the scheduled production volumes have been delivered. For all of our VPP transactions, we have novated hedges to each of the respective VPP buyers and these hedges covered all VPP volumes sold. If contractually scheduled volumes exceed the actual volumes produced from the VPP wellbores that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores (or, at our option, from our retained interest in the wellbores) through an adjustment mechanism, or the initial term of the VPP will be extended until all scheduled volumes, to the extent produced, are delivered from the VPP wellbores to the VPP buyer. We retain drilling rights on the properties below currently producing intervals and outside of producing wellbores.
	As the operator of the properties from which the VPP volumes have been sold, we bear the cost of producing the reserves attributable to these interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods these costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining our full cost ceiling test for impairment purposes and in determining our standardized measure. Pursuant to SEC guidelines, the estimates used for purposes of determining the cost center ceiling and the standardized measure are based on current costs. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. The costs that will apply in the future will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which the production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all.
	For accounting purposes, cash proceeds from the sale of VPPs were reflected as a reduction of oil and natural gas properties with no gain or loss recognized, and our proved reserves were reduced accordingly. We have also committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.
	As of December 31, 2014, our outstanding VPPs consisted of the following:
									Volume Sold
	VPP #		Date of VPP	Location		Proceeds			Oil		Natural Gas	NGL	Total
						($ in millions)			(mmbbl)		(bcf)	(mmbbl)	(bcfe)
	10		Mar-12	Anadarko Basin Granite		$	744		3		87	9.2	160
				Wash
	9		May-11	Mid-Continent		853			1.7		138	4.8	177
	8		September 2010	Barnett Shale		1,150			—		390	—	390
	4		December 2008	Anadarko and Arkoma		412			0.5		95	—	98
				Basins
	3		Aug-08	Anadarko Basin		600			—		93	—	93
	2		May-08	Texas, Oklahoma and		622			—		94	—	94
				Kansas
	1		December 2007	Kentucky and West		1,100			—		208	—	208
				Virginia
						$	5,481		5.2		1,105	14	1,220
	The volumes produced on behalf of our VPP buyers during 2014, 2013 and 2012 were as follows:
			Year Ended December 31, 2014
	VPP #		Oil		Natural Gas			NGL		Total
			(mbbl)		(bcf)			(mbbl)		(bcfe)
	10		403		10.6			1,296.50		20.7
	9		187.5		15.4			411		19
	8		—		60.1			—		60.1
	6(a)		23.1		4.2			—		4.3
	5(a)		16.5		4.6			—		4.7
	4		48.1		9			—		9.2
	3		—		7.2			—		7.2
	2		—		6.2			—		6.2
	1		—		13.8			—		13.8
			678.2		131.1			1,707.50		145.2
			Year Ended December 31, 2013
	VPP #		Oil		Natural Gas			NGL		Total
			(mbbl)		(bcf)			(mbbl)		(bcfe)
	10		547		13.5			1,509.00		25.8
	9		213.2		17			455.7		21
	8		—		68.1			—		68.1
	6		24		4.8			—		4.9
5		25.4		7.5			—		7.7
4		54.7		10.2			—		10.5
3		—		8.1			—		8.1
2		—		10.3			—		10.3
1		—		14.5			—		14.5
		864.3		154			1,964.70		170.9
		Year Ended December 31, 2012
VPP #		Oil		Natural Gas			NGL		Total
		(mbbl)		(bcf)			(mbbl)		(bcfe)
10		727		18.1			1,729.10		32.8
9		249.3		18.4			643.6		23.7
8		—		79.7			—		79.7
7(b)		490.3		0.4			—		3.4
6		24		5.3			—		5.5
5		27.4		8.8			—		9
4		62.8		11.7			—		12.2
3		—		9.3			—		9.3
2		—		11.4			—		11.3
1		—		15.3			—		15.3
		1,580.80		178.4			2,372.70		202.2
____________________________________________
(a)	In 2014, we divested the properties associated with VPP #5 and VPP #6.
(b)	In 2012, to facilitate the sales process associated with our Permian Basin divestiture packages, we purchased the remaining reserves from our Permian Basin VPP (VPP #7). The reserves purchased were subsequently sold to the buyers of our Permian Basin assets.
The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2014 were as follows:
			Volume Remaining as of December 31, 2014
VPP #		Term Remaining	Oil			Natural Gas		NGL		Total
		(in months)	(mmbbl)			(bcf)		(mmbbl)		(bcfe)
10		86	1.3			38		4.7		74
9		74	0.8			73.2		1.9		89.9
8		8	—			36.6		—		36.6
4		24	0.1			15.3		—		15.8
3		55	—			23.9		—		23.9
2		52	—			13.8		—		13.8
1		96	—			91.5		—		91.5
			2.2			292.3		6.6		345.5

SpinOff_of_Oilfield_Services_B

Spin-Off of Oilfield Services Business (Note)	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	Spin-Off of Oilfield Services Business
	On June 30, 2014, we completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary COO, into an independent, publicly traded company called SSE. Following the close of business on June 30, 2014, we distributed to Chesapeake shareholders one share of SSE common stock and cash in lieu of fractional shares for every 14 shares of Chesapeake common stock held on June 19, 2014, the record date for the distribution.
	Prior to the completion of the spin-off, we and COO and its affiliates engaged in the following series of transactions:
	•	COO and certain of its subsidiaries entered into a $275 million senior secured revolving credit facility and a $400 million secured term loan, the proceeds of which were used to repay in full and terminate COO’s existing credit facility.
	•	COO distributed to us its compression unit manufacturing business, its geosteering business and the proceeds from the sale of substantially all of its crude oil hauling business. See Note 16 for further discussion of the sale.
	•	We transferred to a subsidiary of COO, at carrying value, certain of our buildings and land, most of which COO had been leasing from us prior to the spin-off.
	•	COO issued $500 million of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility and for general corporate purposes.
	•	COO converted from a limited liability company into a corporation named Seventy Seven Energy Inc.
	•	We distributed all of SSE’s outstanding shares to our shareholders, which resulted in SSE becoming an independent, publicly traded company.
	Following the spin-off, we have no ownership interest in SSE. Therefore, we ceased to consolidate SSE’s assets and liabilities as of the spin-off date. Because we expect to have significant continued involvement associated with SSE’s future operations through the various agreements described below, our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations. For segment disclosures, we have labeled our oilfield services segment as “former oilfield services”. See Note 21 for additional information regarding our segments.
	In connection with the spin-off, we entered into several agreements to define the terms and conditions of the spin-off and our ongoing relationship with SSE after the spin-off, including a master separation agreement, a tax sharing agreement, an employee matters agreement, a transition services agreement, a services agreement and certain commercial agreements. These agreements, among other things, allocate responsibility for obligations arising before and after the distribution date, including obligations relating to taxes, employees, various transition services and oilfield services.
	•	The master separation agreement sets forth the agreements between SSE and Chesapeake regarding the principal transactions that were necessary to effect the spin-off and also sets forth other agreements that govern certain aspects of SSE’s relationship with Chesapeake after completion of the spin-off.
	•	The tax sharing agreement governs the respective rights, responsibilities and obligations of SSE and Chesapeake with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings, and certain other matters regarding taxes.
	•	The employee matters agreement addresses employee compensation and benefit plans and programs, and other related matters in connection with the spin-off, including the treatment of holders of Chesapeake common stock options, restricted stock and performance share units, and the cooperation between SSE and Chesapeake in the sharing of employee information and maintenance of confidentiality. See Note 9 for additional information regarding the effect of the spin-off on outstanding equity compensation.
	•	The transition services agreement sets forth the terms on which we provide SSE certain services. Transition services include marketing and corporate communication, human resources, information technology, security, legal, risk management, tax, environmental health and safety, maintenance, internal audit, accounting, treasury and certain other services specified in the agreement. SSE pays Chesapeake a negotiated fee for providing those services.
	•	The services agreement requires us to utilize, at market-based pricing, certain SSE pressure pumping services. See Note 4 for a summary of the terms of the services agreement.
	•	We have also entered into drilling agreements that are rig-specific daywork drilling contracts with terms ranging from three months to three years and at market-based rates. We have the right to terminate a drilling agreement in certain circumstances. As of December 31, 2014, the aggregate undiscounted minimum future payments under these drilling agreements were approximately $410 million.
	In 2014, our stockholders’ equity decreased by $270 million, net of $151 million of associated deferred tax liabilities, as the result of the spin-off, and we recognized $15 million of charges associated with the spin-off that are included in restructuring and other termination costs on our consolidated statement of operations. See Note 18 for further details regarding these charges.

Investments_Note

Investments (Note)	12 Months Ended
	Dec. 31, 2014
Investments [Abstract]
Investments Disclosure [Text Block]	Investments
	A summary of our investments, including our approximate ownership percentage and carrying value as of December 31, 2014 and 2013, is presented below.
			Approximate		Carrying
			Ownership %		Value
		Accounting	December 31,		December 31,
		Method	2014	2013	2014		2013
					($ in millions)
	FTS International, Inc.	Equity	30%	30%	$	116	$	138
	Sundrop Fuels, Inc.	Equity	56%	56%	130		135
	Chaparral Energy, Inc.	Equity	—%	20%	—		143
	Other	—	—%	—%	19		61
	Total investments				$	265	$	477
	FTS International, Inc. FTS, based in Fort Worth, Texas, is a privately held company that, through its subsidiaries, provides hydraulic fracturing and other services to oil and gas companies. In 2014, we recorded negative equity method and other adjustments of $32 million for our share of FTS’s net loss and recorded an accretion adjustment of $10 million related to the excess of our underlying equity in net assets of FTS over our carrying value.
	As of December 31, 2014, the carrying value of our investment in FTS was less than our underlying equity in net assets by approximately $44 million, of which $14 million was attributed to non-depreciable assets. The value attributed to depreciable assets is being accreted over the estimated useful lives of the underlying assets.
	Sundrop Fuels, Inc. Sundrop Fuels, Inc. (Sundrop), based in Longmont, Colorado, is a privately held cellulosic biofuels company that is constructing a nonfood biomass-based “green gasoline” plant. In 2014, we recorded a $21 million charge related to our share of Sundrop's net loss and $16 million of capitalized interest associated with the construction of Sundrop’s plant. The carrying value of our investment in Sundrop was in excess of our underlying equity in net assets by approximately $78 million as of December 31, 2014 and will be amortized over the life of the plant once it is placed into service.
	Sold Investments
	Chaparral Energy, Inc. Chaparral Energy, Inc. (Chaparral), based in Oklahoma City, Oklahoma, is a private independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. In 2014, we sold all of our interest in Chaparral for net cash proceeds of $209 million. We recorded a $73 million gain related to the sale.
	Clean Energy Fuels Corp. In 2013, we sold all of our shares of Clean Energy Fuels Corp. (Clean Energy) common stock for cash proceeds of approximately $13 million. We recorded a $3 million gain related to the sale. In 2013, we sold our $100 million investment in convertible notes of Clean Energy for cash proceeds of $85 million. The buyer also assumed our commitment to purchase the third and final $50 million tranche of Clean Energy convertible notes. We recorded a $15 million loss related to this sale.
	Gastar Exploration Ltd. In 2013, we sold our investment in Gastar Exploration Ltd. for cash proceeds of $10 million.
	Chesapeake Midstream Partners, L.P. In 2012, we sold all of our common and subordinated units representing limited partner interests in Chesapeake Midstream Partners, L.P., now named Access Midstream Partners, L.P., and all of our limited liability company interests in the sole member of its general partner to funds affiliated with Global Infrastructure Partners for cash proceeds of $2.0 billion. We recorded a $1.032 billion gain associated with the transaction.
	Glass Mountain Pipeline, LLC. In 2012, our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.L.C. (CMD), entered into an agreement with two other parties to form Glass Mountain Pipeline, LLC to construct a 210 mile pipeline in western and north central Oklahoma in which CMD had a 50% ownership interest. In 2012, CMD sold its interest for $99 million and recorded a gain of $62 million.
	Other. In 2014, we sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction.
	In 2013, we sold an equity investment for cash proceeds of $6 million and recorded a $5 million gain associated with the transaction.

Variable_Interest_Entities_Not

Variable Interest Entities (Note)	12 Months Ended
	Dec. 31, 2014
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Variable Interest Entities Disclosure [Text Block]	Variable Interest Entities
	We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.
	Consolidated VIE
	Chesapeake Granite Wash Trust. For a discussion of the formation, operations and presentation of the Trust, see Noncontrolling Interests in Note 8. The Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust. Our ownership in the Trust and our obligations under the development agreement and related drilling support lien constitute variable interests. We have determined that we are the primary beneficiary of the Trust because (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our obligations to perform under the development agreement, and (ii) as a result of the subordination and incentive thresholds applicable to the subordinated units we hold in the Trust, we have the obligation to absorb losses and the right to receive residual returns that could potentially be significant to the Trust. As a result, we consolidate the Trust in our financial statements, and the common units of the Trust owned by third parties are reflected as a noncontrolling interest.
	The Trust is a consolidated entity whose legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake; however, we have certain obligations to the Trust through the development agreement that are secured by a drilling support lien on our retained interest in the development wells up to a specified maximum amount recoverable by the Trust, which could result in the Trust acquiring all or a portion of our retained interest in the undeveloped portion of an area of mutual interest, if we do not meet our drilling commitment. In consolidation, as of December 31, 2014, $1 million of cash and cash equivalents, $16 million of short-term derivative assets, $488 million of proved oil and natural gas properties, $251 million of accumulated depreciation, depletion and amortization and $15 million of other current liabilities were attributable to the Trust. We have presented parenthetically on the face of the consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake.
	Unconsolidated VIE
	Mineral Acquisition Company I, L.P. In 2012, MAC-LP, L.L.C., a wholly owned non-guarantor unrestricted subsidiary of Chesapeake, entered into a partnership agreement with KKR Royalty Aggregator LLC (KKR) to form Mineral Acquisition Company I, L.P. The purpose of the partnership is to acquire mineral interests, or royalty interests carved out of mineral interests, in oil and natural gas basins in the continental United States. We are committed to acquire for our own account (outside the partnership) 10% of any acquisition agreed upon by the partnership up to a maximum of $25 million, and the partnership will acquire the remaining 90% up to a maximum of $225 million, funded entirely by KKR, making KKR the sole equity investor. We have significant influence over the decisions made by the partnership, as we hold two of five seats on the board of directors. We will receive proportionate distributions from the partnership of any cash received from royalties in excess of expenses paid, ranging from 7% to 22.5%. The partnership is considered a VIE because KKR’s control over the partnership is disproportionate to its economic interest. This VIE remains unconsolidated as the power to direct the activities of the partnership is shared between the Company and KKR. We are using the equity method to account for this investment. The carrying value of our investment was $9 million as of December 31, 2014.

Other_Property_and_Equipment_N

Other Property and Equipment (Note)	12 Months Ended
	Dec. 31, 2014
Gain (Loss) on Disposition of Property Plant Equipment [Abstract]
Other Property and Equipment Disclosure [Text Block]	Other Property and Equipment
	Other Property and Equipment
	A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:
		December 31,						Estimated
								Useful
		2014			2013			Life
		($ in millions)						(in years)
	Buildings and improvements	$	1,242		$	1,433		Oct-39
	Natural gas compressors	551			368			20-Mar
	Land	296			212			—
	Gathering systems and treating plants	218			292			20
	Oilfield services equipment	—			2,192			15-Mar
	Other	776			898			20-Feb
	Total other property and equipment, at cost	3,083			5,395
	Less: accumulated depreciation	(804		)	(1,584		)
	Total other property and equipment, net	$	2,279		$	3,811
	Net Gains on Sales of Fixed Assets
	A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2014, 2013 and 2012 is as follows:
		Years Ended December 31,
		2014			2013			2012
		($ in millions)
	Natural gas compressors	$	(195	)	$	—		$	—
	Gathering systems and treating plants	8			(326		)	(286		)
	Oilfield services equipment	(7		)	2			10
	Buildings and land	(2		)	27			7
	Other	(3		)	(5		)	2
	Total net gains on sales of fixed assets	$	(199	)	$	(302	)	$	(267	)
	Natural Gas Compressors. In 2014, as part of a divestiture of noncore oil and natural gas properties in South Texas, we sold 61 compressors and related equipment to Hilcorp Energy Company for $19 million. We recorded a $6 million gain associated with the compressors sold. Also in 2014, we sold 499 compressors and related equipment to Exterran Partners, L.P. for approximately $495 million. We recorded a $161 million gain associated with the compressors sold. In 2014, we also sold 102 compressors and related equipment to Access Midstream Partners, L.P. (ACMP) for proceeds of approximately $159 million. We recorded a $24 million gain associated with the transaction.
	Gathering Systems and Treating Plants. In 2013, we sold our wholly owned midstream subsidiary Mid-America Midstream Gas Services, L.L.C. to SemGas, L.P., a wholly owned subsidiary of SemGroup Corporation, for net proceeds of approximately $306 million. We recorded a $141 million gain associated with the transaction. In 2013, we also sold our wholly owned subsidiary Granite Wash Midstream Gas Services, L.L.C. to MarkWest Oklahoma Gas Company, L.L.C. (MW), a wholly owned subsidiary of MarkWest Energy Partners, L.P., for net proceeds of approximately $252 million. We recorded a $105 million gain associated with this transaction. The transaction with MW included long-term fixed fee arrangements for gas gathering, compression, treating and processing services in the Anadarko Basin. In 2013, we also sold our interest in certain gathering system assets in Pennsylvania to Western Gas Partners, LP for proceeds of approximately $134 million. We recorded a $55 million gain associated with this transaction.
	In 2012, CMD sold its wholly owned subsidiary, CMO, which held a majority of our midstream business, to ACMP for total consideration of $2.16 billion in cash. In connection with the sale, Chesapeake entered into new long-term agreements in which ACMP agreed to perform certain natural gas gathering and related services for us within specified acreage dedication areas in exchange for (i) cost-of-service based fees redetermined annually beginning January 2014 in the Niobrara and Marcellus Shale plays, (ii) cost-of-service based fees redetermined annually beginning October 2013 for the wet gas gathering systems and January 2014 for the dry gas gathering systems in the Utica Shale play, (iii) tiered fees based on volumes delivered relative to scheduled volumes through 2015 and thereafter cost-of-service based fees redetermined annually in the Eagle Ford Shale play, and (iv) annual minimum volume commitments and a fixed fee per mmbtu of natural gas gathered, subject to an annual 2.5% rate escalation, through 2017 and thereafter tiered fees based on volumes delivered relative to scheduled volumes in the Haynesville Shale play. We recorded a $289 million gain associated with this transaction.
	In 2012, we sold our oil gathering business and related assets in the Eagle Ford Shale to Plains Pipeline, L.P. for cash proceeds of approximately $115 million. Subsequent to December 31, 2012, we received an additional $10 million of proceeds upon satisfaction of a certain closing contingency. We recorded a $3 million gain associated with this transaction. In connection with the sale, we entered into new gathering and transportation agreements covering acreage dedication areas.
	Oilfield Services Equipment. In 2014, we sold substantially all of our crude oil hauling assets for approximately $44 million. We recorded a $23 million gain associated with the transaction. Also, in 2014, we sold 14 rigs for approximately $14 million and recorded a $14 million loss.
	Buildings and Land. The net gains in 2014 and the net losses in 2013 on sales of buildings and land were mainly from the sale of certain buildings and land located primarily in our Oklahoma City and Barnett Shale operating area.
	Assets Held for Sale
	In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. In addition, as of December 31, 2014, we were continuing to pursue the sale of land located in the Fort Worth, Texas area. Land and buildings are recorded within our other segment. These Oklahoma City and Fort Worth assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets are reflected as held for sale as of December 31, 2014. Oil and natural gas properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. A summary of the assets held for sale on our consolidated balance sheets as of December 31, 2014 and 2013 is detailed below.
		December 31,
		2014			2013
		($ in millions)
	Buildings and land, net of accumulated depreciation	$	93		$	405
	Compressors, net of accumulated depreciation	—			285
	Oilfield services equipment, net of accumulated depreciation	—			29
	Gathering systems and treating plants, net of accumulated depreciation	—			11
	Property and equipment held for sale, net	$	93		$	730
	In 2014, management determined that certain properties in the Fort Worth area of the Barnett Shale, previously classified as held for sale as of December 31, 2013, would be reclassified as held for use. As of December 31, 2013, management’s development plan for the Barnett Shale did not contemplate the need for the underlying properties (for pad drilling in certain urban locations around Fort Worth) and the properties were marketed for sale. Management modified its development plan and consequently these properties no longer met the criteria to be classified as held for sale. The properties were measured at the lesser of their fair value at the date of the decision not to sell or their carrying amount before being classified as held for sale. During 2014, we reclassified $120 million of these properties to held for use classification. There was no impact to the statement of operations related to this reclassification.
	During 2014, we sold compressors previously classified as held for sale to Hilcorp Energy Company and Exterran Partners, L.P. The oilfield services equipment was included in the spin-off of our oilfield services business. See Note 13 for further discussion of the spin-off.

Impairments_Note

Impairments (Note)	12 Months Ended
	Dec. 31, 2014
Asset Impairment Charges [Abstract]
Asset Impairment Charges [Text Block]	Impairments
	Impairments of Oil and Natural Gas Properties
	Our oil and natural gas properties are subject to quarterly full cost ceiling tests. As of September 30, 2012, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment in the carrying value of oil and natural gas properties of $3.315 billion. Cash flow hedges as of September 30, 2012, which related to future periods, increased the ceiling test impairment by $279 million. We were not required to record impairments of oil and natural gas properties for any other quarter in 2012 or for any quarters in 2013 or 2014. Based on the decline in oil and natural gas prices in the second half of 2014 and into 2015, we expect to have a material write-down of the carrying value of our oil and natural gas properties in the 2015 first quarter. Further material write-downs in subsequent quarters will occur if the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters.
	Impairments of Fixed Assets and Other
	We review our long-lived assets, other than oil and natural gas properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable. We recognize an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2014, 2013 and 2012 is as follows:
		Years Ended December 31,
		2014		2013		2012
		($ in millions)
	Natural gas compressors	$	11	$	—	$	—
	Gathering systems and treating plants	13		22		6
	Oilfield services equipment	23		71		60
	Buildings and land	18		366		248
	Other	23		87		26
	Total impairments of fixed assets and other	$	88	$	546	$	340
	Oilfield Services Equipment. In 2014, we purchased 31 leased rigs and equipment from various lessors for an aggregate purchase price of $140 million. In connection with these purchases, we paid $8 million in early lease termination costs, which are included in impairments of fixed assets and other in the consolidated statement of operations. We recognized an impairment loss of approximately $15 million related to leasehold improvements associated with these assets. In 2013, we purchased 23 leased rigs (two of which were classified as held for sale assets as of December 31, 2013) from various lessors for an aggregate purchase price of $141 million and paid approximately $22 million in early lease termination costs, which is included in impairments of fixed assets and other in the consolidated statement of operations. In addition, we impaired approximately $22 million related to leasehold improvements and other costs associated with these assets. In 2013, we also recognized $27 million of impairment losses on certain of our drilling rigs that qualified as held for sale during 2013 for the difference between the carrying amount and fair value, less the anticipated costs to sell. We estimated the fair value using prices expected to be received. In 2012, we purchased 25 leased rigs from various lessors for an aggregate purchase price of $36 million and paid approximately $25 million in early lease termination costs, which is included in impairments of fixed assets and other in the consolidated statement of operations. In addition, in 2012, we recognized $26 million of impairment losses on certain of our drilling rigs that we expected would have insufficient cash flow to recover carrying values because of a change in business climate resulting from depressed natural gas prices. In 2012, we also recognized $9 million of impairment losses primarily related to drill pipe and other oilfield services equipment.
	Buildings and Land. In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. We recognized an impairment loss of $186 million on these assets for the difference between the carrying amount and fair value of the assets, less the anticipated costs to sell. Given the impairment losses associated with these assets, we tested other noncore buildings and land that we owned in the Oklahoma City area for recoverability. As a result of this test, we recognized an impairment loss of $69 million on these assets in 2013.
	Due to a decrease in the estimated market prices of certain property classified as held for sale in the Fort Worth area, we recognized an additional impairment loss of $86 million in 2013. We tested other noncore surface land that we owned in the Fort Worth area for recoverability in 2013 and recognized an additional impairment loss of $10 million on these assets for the difference between the carrying amount and fair value of the assets. In addition, in 2012, we recognized $248 million of impairment losses associated with an office building and surface land located in our Barnett Shale operating area. The change in business climate in the Barnett Shale in 2012, evidenced by our significant reduction in Barnett Shale operations and depressed natural gas prices, required us to test these long-lived assets for recoverability.
	Finally, we recorded an impairment loss of approximately $15 million on certain of our buildings and land outside of the Oklahoma City and Fort Worth areas in 2013. All the buildings and land for which impairment losses were recognized in 2014, 2013 and 2012 are included in our other segment.
	Other. Under the terms of our joint venture agreements (see Note 12), 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. In 2014, we revised our estimate of our net acreage shortfall as of December 31, 2012 under the terms of our Barnett Shale joint venture agreement with Total and recorded an additional $22 million charge. See Note 4 for additional discussion regarding our net acreage maintenance commitments. In 2013, we recorded approximately $87 million of other charges, including $26 million for the termination of a gas gathering agreement, $28 million for the impairment of certain assets used to promote natural gas demand, $15 million for the termination of a contract drilling agreement with a third party, $2 million related to the estimated 2012 shortfall of our net acreage maintenance commitment with Total in the Barnett Shale and $16 million related to various other assets. In 2012, we recorded a $26 million charge related to the estimated 2012 shortfall of our net acreage maintenance commitment with Total in the Barnett Shale.
	Nonrecurring Fair Value Measurements. Fair value measurements for certain of the impairments discussed above were based on recent sales information for comparable assets. As the fair value was estimated using the market approach based on recent prices from orderly sales transactions for comparable assets between market participants, the values were classified as Level 2 in the fair value hierarchy. Fair value measurements of the buildings and land discussed above were based on prices from orderly sales transactions for comparable properties between market participants, purchase offers we received from third parties and, in certain cases, discounted cash flows. As some inputs used were not observable in the market, these values were classified as Level 3 in the fair value hierarchy.

Restructuring_and_Other_Termin

Restructuring and Other Termination Benefits (Note)	12 Months Ended
	Dec. 31, 2014
Restructuring and Related Activities [Abstract]
Restructuring and Related Activities Disclosure [Text Block]	Restructuring and Other Termination Costs
	On June 30, 2014, we completed the spin-off of our oilfield services business through a pro rata distribution of SSE common stock to holders of Chesapeake common stock. In connection with the spin-off, in 2014, we incurred restructuring charges of $15 million consisting of transaction costs, stock-based compensation adjustments and debt extinguishment costs. See Note 13 for further discussion of the spin-off.
	On September 9, 2013, we committed to a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs. The reduction was communicated to affected employees on various dates within the months of September and October, and all notifications were completed by October 11, 2013. The plan resulted in a reduction of approximately 900 employees. In connection with the reduction, we incurred a charge of approximately $66 million.
	On April 1, 2013, Aubrey K. McClendon, the co-founder of the Company, ceased serving as President and CEO and as a director of the Company pursuant to his agreement with the Board of Directors announced on January 29, 2013. Mr. McClendon’s departure from the Company was treated as a termination without cause under his employment agreement. On April 18, 2013, the Company and Mr. McClendon entered into a Founder Separation and Services Agreement, effective January 29, 2013, regarding his separation from employment and to facilitate the relationship between the Company and Mr. McClendon as joint working interest owners of oil and gas wells, leases and acreage. In 2013, we incurred charges of approximately $69 million related to Mr. McClendon’s departure.
	During 2013, we also incurred charges of approximately $50 million related to other workforce reductions, including separations of executive officers other than the former CEO. Substantially all of the restructuring and other termination costs in 2013 are in the exploration and production operating segment.
	In December 2012, Chesapeake announced that it had offered a voluntary separation program (VSP) to certain employees as part of the Company's ongoing efforts to improve efficiencies and reduce costs. The VSP was offered to approximately 275 employees who met criteria based upon a combination of age and years of Chesapeake service, and 211 accepted prior to the expiration of the offer in February 2013. We recognized the expense related to their termination benefits over their remaining service period, which resulted in $63 million of expense for 2013.
	Below is a summary of our restructuring and other termination costs for the years ended December 31, 2014, 2013 and 2012:
			Years Ended December 31,
			2014			2013		2012
			($ in millions)
	Oilfield services spin-off costs:
	Transaction costs		$	17		$	—	$	—
	Stock-based compensation adjustments for Chesapeake employees		5			—		—
	Stock-based compensation forfeitures for SSE employees		(10		)	—		—
	Debt extinguishment costs		3			—		—
	Total oilfield services spin-off costs		15			—		—
	Restructuring charges under workforce reduction plan:
	Salary expense		—			20		—
	Acceleration of stock-based compensation		—			45		—
	Other termination benefits		—			1		—
	Total restructuring changes under workforce reduction plan		—			66		—
	Termination benefits provided to Mr. McClendon:
	Salary and bonus expense		—			11		—
	Acceleration of 2008 performance bonus clawback		—			11		—
	Acceleration of stock-based compensation		—			22		—
	Acceleration of performance share unit awards(a)		(8		)	18		—
	Estimated aircraft usage benefits		—			7		—
	Total termination benefits provided to Mr. McClendon		(8		)	69		—
	Termination benefits provided to VSP participants:
	Salary and bonus expense		—			33		1
	Acceleration of stock-based compensation		—			29		1
	Other termination benefits		—			1		—
	Total termination benefits provided to VSP participants		—			63		2
	Other termination benefits(a)		—			50		5
	Total restructuring and other termination costs		$	7		$	248	$	7
	____________________________________________
	(a)	Amounts for the year ended December 31, 2014 are primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 9.

Fair_Value_Measurements_Note

Fair Value Measurements (Note)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements Disclosure [Text Block]	Fair Value Measurements
	Recurring Fair Value Measurements
	Other Current Assets. Assets related to Company matches of employee contributions to Chesapeake’s employee benefit plans are included in other current assets. The fair value of these assets is determined using quoted market prices as they consist of exchange-traded securities.
	Other Current Liabilities. Liabilities related to Chesapeake’s deferred compensation plan are included in other current liabilities. The fair values of these liabilities are determined using quoted market prices as the plan consists of exchange-traded mutual funds.
	Financial Assets (Liabilities). The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:
		Quoted			Significant		Significant		Total
		Prices in			Other		Unobservable		Fair Value
		Active			Observable		Inputs
		Markets			Inputs		(Level 3)
		(Level 1)			(Level 2)
					($ in millions)
	As of December 31, 2014
	Financial Assets (Liabilities):
	Other current assets	$	57		$	—	$	—	$	57
	Other current liabilities	(58		)	—		—		(58		)
	Total	$	(1	)	$	—	$	—	$	(1	)
	As of December 31, 2013
	Financial Assets (Liabilities):
	Other current assets	$	80		$	—	$	—	$	80
	Other current liabilities	(82		)	—		—		(82		)
	Total	$	(2	)	$	—	$	—	$	(2	)
	See Note 3 for information regarding fair value of other financial instruments. See Note 11 for information regarding fair value measurement of derivatives.
	Nonrecurring Fair Value Measurements
	See Note 17 regarding nonrecurring fair value measurements.

Asset_Retirement_Obligation_No

Asset Retirement Obligation (Note)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	Asset Retirement Obligations
	The components of the change in our asset retirement obligations are shown below.
			Years Ended December 31,
			2014			2013
			($ in millions)
	Asset retirement obligations, beginning of period		$	405		$	375
	Additions		29			20
	Revisions(a)		101			8
	Settlements and disposals		(92		)	(20		)
	Accretion expense		22			22
	Asset retirement obligations, end of period		465			405
	Less current portion (b)		18			—
	Asset retirement obligation, long-term		$	447		$	405
	_________________________________________
	(a)	Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settlement.
	(b)	Balance is included in other current liabilities on the consolidated balance sheet.

Major_Customers_and_Segment_In

Major Customers and Segment Information (Note)	12 Months Ended
	Dec. 31, 2014
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]
Segment Information Disclosure [Text Block]	Major Customers and Segment Information
	Sales to ExxonMobil Corporation and Plains Marketing, L.P. constituted approximately 12% and 11%, respectively, of our total revenues (before the effects of hedging) for the years ended December 31, 2014 and 2012, respectively. There were no sales to individual customers constituting 10% or more of total revenues (before the effects of hedging) for the year ended December 31, 2013.
	As of December 31, 2014, we have two reportable operating segments, each of which is managed separately because of the nature of its operations. The exploration and production operating segment is responsible for finding and producing oil, natural gas and NGL. The marketing, gathering and compression operating segment is responsible for marketing, gathering and compression of oil, natural gas and NGL. In addition, prior to the spin-off described in Note 13, our former oilfield services operating segment was responsible for drilling, oilfield trucking, oilfield rentals, hydraulic fracturing and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations, as reflected in the table below.
	Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the sale of oil, natural gas and NGL related to Chesapeake’s ownership interests by our marketing, gathering and compression operating segment are reflected as revenues within our exploration and production operating segment. These amounts totaled $8.565 billion, $7.570 billion and $5.464 billion for the years ended December 31, 2014, 2013 and 2012, respectively. Revenues generated by our former oilfield services operating segment for work performed for Chesapeake’s exploration and production operating segment were reclassified to the full cost pool based on Chesapeake’s ownership interest. Revenues reclassified totaled $544 million, $1.309 billion and $1.315 billion for the years ended December 31, 2014, 2013 and 2012, respectively. No income was recognized in our consolidated statements of operations related to oilfield services performed for Chesapeake-operated wells.
	The following tables present selected financial information for Chesapeake’s operating segments:
		Exploration			Marketing,			Former			Other			Intercompany			Consolidated
		and			Gathering			Oilfield						Eliminations			Total
		Production			and			Services
					Compression
		($ in millions)
	Year Ended December 31, 2014:
	Revenues	$	8,180		$	20,790		$	1,060		$	30		$	(9,109	)	$	20,951
	Intersegment revenues	—			(8,565		)	(544		)	—			9,109			—
	Total revenues	$	8,180		$	12,225		$	516		$	30		$	—		$	20,951
	Unrealized gains on commodity derivatives	$	(1,394	)	$	—		$	—		$	—		$	—		$	(1,394	)
	Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,756		$	38		$	145		$	42		$	(66	)	$	2,915
	Impairments of fixed assets and other	$	22		$	24		$	23		$	19		$	—		$	88
	Net gains on sales of fixed assets	$	(2	)	$	(187	)	$	(8	)	$	(2	)	$	—		$	(199	)
	Interest expense	$	(709	)	$	(21	)	$	(42	)	$	3		$	680		$	(89	)
	Earnings (losses) on investments	$	2		$	—		$	(6	)	$	(76	)	$	—		$	(80	)
	Net gain (loss) on sales of investments	$	(6	)	$	—		$	—		$	73		$	—		$	67
	Losses on purchases of debt	$	(197	)	$	—		$	—		$	—		$	—		$	(197	)
	Income (Loss) Before	$	2,874		$	326		$	(16	)	$	(30	)	$	46		$	3,200
	Income Taxes
	Total Assets	$	35,381		$	1,978		$	—		$	4,283		$	(891	)	$	40,751
	Capital Expenditures	$	6,173		$	298		$	158		$	38		$	—		$	6,667
		Exploration			Marketing,			Former			Other			Intercompany			Consolidated
		and			Gathering			Oilfield						Eliminations			Total
		Production			and			Services
					Compression
		($ in millions)
	Year Ended December 31, 2013:
	Revenues	$	7,052		$	17,129		$	2,188		$	29		$	(8,892	)	$	17,506
	Intersegment revenues	—			(7,570		)	(1,309		)	(13		)	8,892			—
	Total revenues	$	7,052		$	9,559		$	879		$	16		$	—		$	17,506
	Unrealized gains on commodity derivatives	$	(228	)	$	—		$	—		$	—		$	—		$	(228	)
	Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,674		$	46		$	289		$	49		$	(155	)	$	2,903
	Impairments of fixed assets and other	$	27		$	50		$	75		$	394		$	—		$	546
	Net (gains) losses on sales of fixed assets	$	2		$	(329	)	$	(1	)	$	26		$	—		$	(302	)
	Interest expense	$	(918	)	$	(24	)	$	(82	)	$	(74	)	$	871		$	(227	)
	Earnings (losses) on investments	$	3		$	—		$	(1	)	$	(229	)	$	1		$	(226	)
	Net gain (loss) on sales of investments	$	—		$	—		$	—		$	(7	)	$	—		$	(7	)
	Losses on purchases of debt	$	(193	)	$	—		$	—		$	—		$	—		$	(193	)
	Income (Loss) Before	$	2,997		$	511		$	(51	)	$	(727	)	$	(1,288	)	$	1,442
	Income Taxes
	Total Assets	$	35,341		$	2,430		$	2,018		$	5,750		$	(3,757	)	$	41,782
	Capital Expenditures	$	6,198		$	299		$	272		$	421		$	—		$	7,190
		Exploration			Marketing,			Former			Other			Intercompany			Consolidated
		and			Gathering			Oilfield						Eliminations			Total
		Production			and			Services
					Compression
		($ in millions)
	Year Ended December 31, 2012:
	Revenues	$	6,278		$	10,895		$	1,917		$	21		$	(6,795	)	$	12,316
	Intersegment revenues	—			(5,464		)	(1,315		)	(16		)	6,795			—
	Total revenues	$	6,278		$	5,431		$	602		$	5		$	—		$	12,316
	Unrealized losses on commodity derivatives	$	(561	)	$	—		$	—		$	—		$	—		$	(561	)
	Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,624		$	54		$	232		$	46		$	(145	)	$	2,811
	Impairment of oil and natural gas properties	$	3,315		$	—		$	—		$	—		$	—		$	3,315
	Impairments of fixed assets and other	$	28		$	6		$	60		$	246		$	—		$	340
	Net (gains) losses on sales of fixed assets	$	14		$	(298	)	$	10		$	7		$	—		$	(267	)
	Interest expense	$	(47	)	$	(20	)	$	(76	)	$	(364	)	$	430		$	(77	)
	Earnings (losses) on investments	$	—		$	49		$	—		$	(152	)	$	—		$	(103	)
	Net gain (loss) on sales of investments	$	(2	)	$	1,094		$	—		$	—		$	—		$	1,092
Losses on purchases of debt	$	(200	)	$	—		$	—		$	—		$	—		$	(200	)
Income (Loss) Before	$	(1,798	)	$	1,665		$	112		$	(478	)	$	(475	)	$	(974	)
Income Taxes
Total Assets	$	37,004		$	2,291		$	2,115		$	2,529		$	(2,328	)	$	41,611
Capital Expenditures	$	12,044		$	852		$	658		$	554		$	—		$	14,108

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information (Note)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Financial Information of Parent Company Only Disclosure [Text Block]	Condensed Consolidating Financial Information
	Chesapeake Energy Corporation is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes and contingent convertible senior notes listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries are non-guarantors. Our former oilfield services subsidiaries were separately capitalized and were not guarantors of our debt obligations.
	The tables 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 December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012. This financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.
	CONDENSED CONSOLIDATING BALANCE SHEET
	AS OF DECEMBER 31, 2014
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	4,100		$	2		$	84		$	(78	)	$	4,108
	Restricted cash		—			—			38			—			38
	Other		55			3,174			93			—			3,322
	Intercompany receivable, net		24,527			—			341			(24,868		)	—
	Total Current Assets		28,682			3,176			556			(24,946		)	7,468
	PROPERTY AND EQUIPMENT:
	Oil and natural gas properties, at cost based on full cost accounting, net		—			28,358			1,112			673			30,143
	Other property and equipment, net		—			2,276			3			—			2,279
	Property and equipment held for		—			93			—			—			93
	sale, net
	Total Property and Equipment,		—			30,727			1,115			673			32,515
	Net
	LONG-TERM ASSETS:
	Other assets		153			618			26			(29		)	768
	Investments in subsidiaries and		126			467			—			(593		)	—
	intercompany advances
	TOTAL ASSETS		$	28,961		$	34,988		$	1,697		$	(24,895	)	$	40,751
	CURRENT LIABILITIES:
	Current liabilities		$	792		$	5,084		$	68		$	(81	)	$	5,863
	Intercompany payable, net		—			24,937			—			(24,937		)	—
	Total Current Liabilities		792			30,021			68			(25,018		)	5,863
	LONG-TERM LIABILITIES:
	Long-term debt, net		11,154			—			—			—			11,154
	Deferred income tax liabilities		—			3,751			234			200			4,185
	Other long-term liabilities		112			1,090			142			—			1,344
	Total Long-Term Liabilities		11,266			4,841			376			200			16,683
	EQUITY:
	Chesapeake stockholders’ equity		16,903			126			1,253			(1,379		)	16,903
	Noncontrolling interests		—			—			—			1,302			1,302
	Total Equity		16,903			126			1,253			(77		)	18,205
	TOTAL LIABILITIES AND EQUITY		$	28,961		$	34,988		$	1,697		$	(24,895	)	$	40,751
	CONDENSED CONSOLIDATING BALANCE SHEET
	YEAR ENDED DECEMBER 31, 2013
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	799		$	8		$	38		$	(8	)	$	837
	Restricted cash		—			37			38			—			75
	Other		103			2,465			524			(348		)	2,744
	Intercompany receivable, net		25,549			—			860			(26,409		)	—
	Total Current Assets		26,451			2,510			1,460			(26,765		)	3,656
	PROPERTY AND EQUIPMENT:
	Oil and natural gas properties, at cost based on full cost accounting, net		—			30,933			1,471			189			32,593
	Other property and equipment, net		—			2,360			1,452			(1		)	3,811
	Property and equipment held for		—			701			29			—			730
	sale, net
	Total Property and Equipment,		—			33,994			2,952			188			37,134
	Net
	LONG-TERM ASSETS:
	Other assets		111			1,161			96			(376		)	992
	Investments in subsidiaries and		2,169			(209		)	—			(1,960		)	—
	intercompany advances
	TOTAL ASSETS		$	28,731		$	37,456		$	4,508		$	(28,913	)	$	41,782
	CURRENT LIABILITIES:
Current liabilities		$	300		$	5,262		$	309		$	(356	)	$	5,515
Intercompany payable, net		—			26,409			—			(26,409		)	—
Total Current Liabilities		300			31,671			309			(26,765		)	5,515
LONG-TERM LIABILITIES:
Long-term debt, net		11,831			—			1,055			—			12,886
Deferred income tax liabilities		209			2,338			773			87			3,407
Other long-term liabilities		396			1,278			504			(344		)	1,834
Total Long-Term Liabilities		12,436			3,616			2,332			(257		)	18,127
EQUITY:
Chesapeake stockholders’ equity		15,995			2,169			1,867			(4,036		)	15,995
Noncontrolling interests		—			—			—			2,145			2,145
Total Equity		15,995			2,169			1,867			(1,891		)	18,140
TOTAL LIABILITIES AND EQUITY		$	28,731		$	37,456		$	4,508		$	(28,913	)	$	41,782
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2014
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Oil, natural gas and NGL		$	—		$	7,765		$	418		$	(3	)	$	8,180
Marketing, gathering and compression		—			12,220			5			—			12,225
Oilfield services		—			41			983			(478		)	546
Total Revenues		—			20,026			1,406			(481		)	20,951
OPERATING EXPENSES:
Oil, natural gas and NGL production		—			1,166			42			—			1,208
Production taxes		—			227			5			—			232
Marketing, gathering and compression		—			12,232			4			—			12,236
Oilfield services		—			53			769			(391		)	431
General and administrative		—			273			49			—			322
Restructuring and other termination costs		—			4			3			—			7
Provision for legal contingencies		100			134			—			—			234
Oil, natural gas and NGL depreciation,		—			2,523			162			(2		)	2,683
depletion and amortization
Depreciation and amortization of other		—			153			143			(64		)	232
assets
Impairment of oil and natural gas properties		—			—			349			(349		)	—
Impairments of fixed assets and other		—			65			23			—			88
Net gains on sales of fixed assets		—			(192		)	(7		)	—			(199		)
Total Operating Expenses		100			16,638			1,542			(806		)	17,474
INCOME (LOSS) FROM OPERATIONS		(100		)	3,388			(136		)	325			3,477
OTHER INCOME (EXPENSE):
Interest expense		(657		)	(37		)	(42		)	647			(89		)
Losses on investments		—			(77		)	(5		)	2			(80		)
Net gain on sales of investments		—			67			—			—			67
Losses on purchases of debt		(195		)	(2		)	—			—			(197		)
Other income (expense)		502			198			(2		)	(676		)	22
Equity in net earnings (losses) of subsidiary		2,206			(258		)	—			(1,948		)	—
Total Other Income (Expense)		1,856			(109		)	(49		)	(1,975		)	(277		)
INCOME (LOSS) BEFORE INCOME TAXES		1,756			3,279			(185		)	(1,650		)	3,200
INCOME TAX EXPENSE (BENEFIT)		(161		)	1,264			(66		)	107			1,144
NET INCOME (LOSS)		1,917			2,015			(119		)	(1,757		)	2,056
Net income attributable to		—			—			—			(139		)	(139		)
noncontrolling interests
NET INCOME ATTRIBUTABLE		1,917			2,015			(119		)	(1,896		)	1,917
TO CHESAPEAKE
Other comprehensive income		1			18			—			—			19
COMPREHENSIVE INCOME (LOSS)		$	1,918		$	2,033		$	(119	)	$	(1,896	)	$	1,936
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Oil, natural gas and NGL		$	—		$	6,439		$	553		$	60		$	7,052
Marketing, gathering and compression		—			9,547			12			—			9,559
Oilfield services		—			221			1,836			(1,162		)	895
Total Revenues		—			16,207			2,401			(1,102		)	17,506
OPERATING EXPENSES:
Oil, natural gas and NGL production		—			1,112			47			—			1,159
Production taxes		—			222			7			—			229
Marketing, gathering and compression		—			9,455			6			—			9,461
Oilfield services		—			239			1,434			(937		)	736
General and administrative		—			375			83			(1		)	457
Restructuring and other termination costs		—			244			4			—			248
Oil, natural gas and NGL depreciation,		—			2,336			253			—			2,589
depletion and amortization
Depreciation and amortization of other		—			180			281			(147		)	314
assets
Impairment of oil and natural gas		—			(2		)	313			(311		)	—
properties
Impairments of fixed assets and other		—			417			129			—			546
Net gains on sales of fixed assets		—			(301		)	(1		)	—			(302		)
Total Operating Expenses		—			14,277			2,556			(1,396		)	15,437
INCOME (LOSS) FROM OPERATIONS		—			1,930			(155		)	294			2,069
OTHER INCOME (EXPENSE):
Interest expense		(921		)	(4		)	(85		)	783			(227		)
Losses on investments		—			(225		)	(1		)	—			(226		)
Net loss on sales of investments		—			(7		)	—			—			(7		)
Losses on purchases of debt		(70		)	(123		)	—			—			(193		)
Other income		3,979			(603		)	13			(3,363		)	26
Equity in net earnings (losses) of		(1,129		)	(383		)	—			1,512			—
subsidiary
Total Other Income (Expense)		1,859			(1,345		)	(73		)	(1,068		)	(627		)
INCOME (LOSS) BEFORE INCOME TAXES		1,859			585			(228		)	(774		)	1,442
INCOME TAX EXPENSE (BENEFIT)		1,135			370			(87		)	(870		)	548
NET INCOME (LOSS)		724			215			(141		)	96			894
Net income attributable to		—			—			—			(170		)	(170		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		724			215			(141		)	(74		)	724
TO CHESAPEAKE
Other comprehensive income (loss)		3			19			(2		)	—			20
COMPREHENSIVE INCOME		$	727		$	234		$	(143	)	$	(74	)	$	744
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2012
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Oil, natural gas and NGL		$	—		$	5,920		$	351		$	7		$	6,278
Marketing, gathering and compression		—			5,218			212			1			5,431
Oilfield services		—			154			1,553			(1,100		)	607
Total Revenues		—			11,292			2,116			(1,092		)	12,316
OPERATING EXPENSES:
Oil, natural gas and NGL production		—			1,278			26			—			1,304
Production taxes		—			182			6			—			188
Marketing, gathering and compression		—			5,197			115			—			5,312
Oilfield services		—			301			1,096			(932		)	465
General and administrative		—			431			105			(1		)	535
Restructuring and other termination costs		—			5			2			—			7
Oil, natural gas and NGL depreciation,		—			2,353			154			—			2,507
depletion and amortization
Depreciation and amortization of other		—			187			266			(149		)	304
assets
Impairment of oil and natural gas properties		—			3,192			123			—			3,315
Impairments of fixed assets and other		—			275			65			—			340
Net gains (losses) on sales of fixed assets		—			(269		)	2			—			(267		)
Total Operating Expenses		—			13,132			1,960			(1,082		)	14,010
INCOME (LOSS) FROM OPERATIONS		—			(1,840		)	156			(10		)	(1,694		)
OTHER INCOME (EXPENSE):
Interest expense		(879		)	45			(84		)	841			(77		)
Losses on investments		—			(167		)	55			9			(103		)
Net gain on sales of investments		—			29			1,063			—			1,092
Losses on purchases of debt		(200		)	—			—			—			(200		)
Other income (loss)		819			203			14			(1,028		)	8
Equity in net earnings (losses) of subsidiary		(610		)	436			—			174			—
Total Other Income (Expense)		(870		)	546			1,048			(4		)	720
INCOME (LOSS) BEFORE INCOME TAXES		(870		)	(1,294		)	1,204			(14		)	(974		)
INCOME TAX EXPENSE (BENEFIT)		(101		)	(675		)	470			(74		)	(380		)
NET INCOME (LOSS)		(769		)	(619		)	734			60			(594		)
Net income attributable to		—			—			—			(175		)	(175		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		(769		)	(619		)	734			(115		)	(769		)
TO CHESAPEAKE
Other comprehensive income (loss)		6			(22		)	—			—			(16		)
COMPREHENSIVE INCOME		$	(763	)	$	(641	)	$	734		$	(115	)	$	(785	)
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2014
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING		$	—		$	4,201		$	462		$	(29	)	$	4,634
ACTIVITIES
CASH FLOWS FROM INVESTING
ACTIVITIES:
Drilling and completion costs		—			(4,445		)	(136		)	—			(4,581		)
Acquisitions of proved and unproved properties		—			(1,306		)	(5		)	—			(1,311		)
Proceeds from divestitures of proved and unproved properties		—			5,812			1			—			5,813
Additions to other property and equipment		—			(480		)	(246		)	—			(726		)
Other investing activities		—			1,199			60			—			1,259
Net Cash Provided By (Used In) Investing Activities		—			780			(326		)	—			454
CASH FLOWS FROM FINANCING
ACTIVITIES:
Proceeds from credit facilities borrowings		—			6,689			717			—			7,406
Payments on credit facilities borrowings		—			(6,689		)	(1,099		)	—			(7,788		)
Proceeds from issuance of senior notes, net of discount and offering costs		2,966			—			494			—			3,460
Proceeds from issuance of term loans, net of discount and offering costs		—			—			394			—			394
Cash paid to purchase debt		(3,362		)	—			—			—			(3,362		)
Other financing activities		(439		)	(1,278		)	(169		)	(41		)	(1,927		)
Intercompany advances, net		4,136			(3,709		)	(427		)	—			—
Net Cash Provided By (Used In)		3,301			(4,987		)	(90		)	(41		)	(1,817		)
Financing Activities
Net increase (decrease) in cash and cash		3,301			(6		)	46			(70		)	3,271
equivalents
Cash and cash equivalents, beginning of		799			8			38			(8		)	837
period
Cash and cash equivalents, end of period		$	4,100		$	2		$	84		$	(78	)	$	4,108
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING		$	—		$	4,218		$	439		$	(43	)	$	4,614
ACTIVITIES
CASH FLOWS FROM INVESTING
ACTIVITIES:
Drilling and completion costs		—			(4,838		)	(766		)	—			(5,604		)
Acquisitions of proved and unproved properties		—			(1,378		)	346			—			(1,032		)
Proceeds from divestitures of proved and unproved properties		—			3,466			1			—			3,467
Additions to other property and equipment		—			(271		)	(701		)	—			(972		)
Other investing activities		—			246			765			163			1,174
Net Cash Provided By (Used In) Investing Activities		—			(2,775		)	(355		)	163			(2,967		)
CASH FLOWS FROM FINANCING
ACTIVITIES:
Proceeds from credit facilities borrowings		—			6,452			1,217			—			7,669
Payments on credit facilities borrowings		—			(6,452		)	(1,230		)	—			(7,682		)
Proceeds from issuance of senior notes, net of discount and offering costs		2,274			—			—			—			2,274
Cash paid to purchase debt		(2,141		)	—			—			—			(2,141		)
Proceeds from sales of noncontrolling interests		—			—			6			—			6
Other financing activities		1,819			(2,897		)	(17		)	(128		)	(1,223		)
Intercompany advances, net		(1,381		)	1,462			(81		)	—			—
Net Cash Provided By (Used		571			(1,435		)	(105		)	(128		)	(1,097		)
In) Financing Activities
Net increase (decrease) in cash and cash		571			8			(21		)	(8		)	550
equivalents
Cash and cash equivalents, beginning of		228			—			59			—			287
period
Cash and cash equivalents, end of period		$	799		$	8		$	38		$	(8	)	$	837
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2012
($ in millions)
		Parent(a)			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries(a)			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING		$	—		$	1,711		$	1,182		$	(56	)	$	2,837
ACTIVITIES
CASH FLOWS FROM INVESTING
ACTIVITIES:
Drilling and completion costs		—			(8,605		)	(325		)	—			(8,930		)
Acquisitions of proved and unproved properties		—			(3,622		)	461			—			(3,161		)
Proceeds from divestitures of proved and unproved properties		—			5,884			—			—			5,884
Additions to other property and equipment		—			(1,736		)	(915		)	—			(2,651		)
Other investing activities		—			5,083			(316		)	(893		)	3,874
Net Cash Used In Investing		—			(2,996		)	(1,095		)	(893		)	(4,984		)
Activities
CASH FLOWS FROM FINANCING
ACTIVITIES:
Proceeds from credit facilities borrowings		—			18,930			1,388			—			20,318
Payments on credit facilities borrowings		—			(20,651		)	(999		)	—			(21,650		)
Proceeds from issuance of senior notes, net of discount and offering costs		1,263			—			—			—			1,263
Proceeds from issuance of term loans, net of discount and offering costs		5,722			—			—			—			5,722
Cash paid to purchase debt		(4,000		)	—			—			—			(4,000		)
Proceeds from sales of noncontrolling interests		—			63			1,014			—			1,077
Other financing activities		(477		)	(299		)	(820		)	949			(647		)
Intercompany advances, net		(2,282		)	3,242			(960		)	—			—
Net Cash Provided By (Used		226			1,285			(377		)	949			2,083
In) Financing Activities
Net increase (decrease) in cash and cash		226			—			(290		)	—			(64		)
equivalents
Cash and cash equivalents, beginning of		2			—			349			—			351
period
Cash and cash equivalents, end of period		$	228		$	—		$	59		$	—		$	287
___________________________________________
(a)	We have revised the amounts presented as cash and cash equivalents in the Guarantor Subsidiaries and Parent columns to properly reflect the cash of the Parent. As of December 31, 2012, $228 million was incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.

Recently_Issued_Accounting_Sta

Recently Issued Accounting Standards (Note)	12 Months Ended
	Dec. 31, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Recently Issued Accounting Standards
	In April 2014, the FASB issued an accounting standards update that raises the threshold for a disposal or classification as held for sale to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. This accounting standards update is effective for us beginning on January 1, 2015, and it is not expected to have a material impact on our consolidated financial statements.
	In May 2014, the FASB issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the company expects to receive in the exchange. The accounting standards update is effective for us beginning January 1, 2017, including retrospective application to comparative periods, and we are evaluating the impact on our consolidated financial statements.

Basis_of_Presentation_and_Summ1

Basis of Presentation and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

Basis of Presentation

The accompanying consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated.

Use of Estimates, Policy [Policy Text Block]

Accounting Estimates

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

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates.

Consolidation, Policy [Policy Text Block]

Consolidation

Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Investments in securities not accounted for under the equity method have been designated as available-for-sale and, as such, are carried at fair value whenever this value is readily determinable. Otherwise, the investment is carried at cost. See Note 14 for further discussion of our investments. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis.

Noncontrolling Interests

Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests.

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

Variable Interest Entities

VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both our consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs.

We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.

Cash and Cash Equivalents, Policy [Policy Text Block]

Accounts Payable

Included in accounts payable as of December 31, 2014 and 2013 are liabilities of approximately $333 million and $397 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.

Cash and Cash Equivalents and Restricted Cash

For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. Restricted cash consists of the balance required to be maintained by the terms of the agreement governing the activities of CHK Cleveland Tonkawa, L.L.C. (CHK C-T) and, prior to our repurchase of all of the outstanding preferred shares of CHK Utica, L.L.C. (CHK Utica) in 2014, also consisted of a balance required to be maintained by the terms of the agreement governing the activities of CHK Utica. The repurchase of outstanding preferred shares of CHK Utica eliminated the restricted cash maintenance requirement related to this entity. See Note 8 for further discussion of these entities.

Receivables, Policy [Policy Text Block]

Accounts Receivable

Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables we believe may be uncollectible. During 2014, 2013 and 2012, we recognized $2 million, $2 million and a nominal amount of bad debt expense related to potentially uncollectible receivables, and we reduced our allowance by $3 million in 2013 as we wrote off specific receivables against our allowance. Accounts receivable as of December 31, 2014 and 2013 are detailed below.

December 31,

2014

2013

($ in millions)

Oil, natural gas and NGL sales

$

1,340

$

1,548

Joint interest

691

417

Oilfield services(a)

—

63

Related parties(b)

—

62

Other

226

150

Allowance for doubtful accounts

(21

)

(18

)

Total accounts receivable, net

$

2,236

$

2,222

___________________________________________

(a)

In 2014, in connection with the spin-off of our oilfield services business, accounts receivable related to oilfield services were removed from our consolidated balance sheet.

(b)

See Note 7 for discussion of related party transactions.

Oil and Gas Properties Policy [Policy Text Block]

Oil and Natural Gas Properties

Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information - Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. Estimates of our proved reserves as of December 31, 2014 were prepared by independent engineering firms and Chesapeake's internal staff. Approximately 79% of these proved reserves estimates (by volume) as of December 31, 2014 were prepared by independent engineering firms. In addition, our internal engineers review and update our reserves on a quarterly basis.

Proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized.

The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties leasehold that can be associated with proved reserves, leasehold that expired in the quarter or leasehold that is not a part of our development strategy and will be abandoned.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2014 and the year in which the associated costs were incurred.

Year of Acquisition

2014

2013

2012

Prior

Total

($ in millions)

Leasehold acquisition cost

$

577

$

199

$

1,462

$

5,149

$

7,387

Exploration cost

340

90

244

42

716

Capitalized interest

492

421

325

447

1,685

Total

$

1,409

$

710

$

2,031

$

5,638

$

9,788

We also review, on a quarterly basis, the carrying value of our oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission (SEC). This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for oil and natural gas derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of oil, natural gas and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2014, none of our open derivative instruments were designated as cash flow hedges. Our oil and natural gas hedging activities are discussed in Note 11.

Two primary factors impacting the ceiling test are reserves levels and oil, natural gas and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an extended increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value over the ceiling is written off as an expense.

We account for seismic costs as part of our oil and natural gas properties. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. These costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred.

Property, Plant and Equipment, Policy [Policy Text Block]

Other Property and Equipment

Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computer and office equipment, oil and natural gas gathering systems and treating plants. We have no remaining oilfield services equipment as a result of the spin-off of our oilfield services business in 2014 as discussed in Note 13, and substantially all of our natural gas gathering systems and treating plants were sold in 2013 and 2012 as discussed in Note 16. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating costs. See Note 16 for further discussion of our gains and losses on the sales of other property and equipment and a summary of our other property and equipment held for sale as of December 31, 2014 and 2013. Other property and equipment costs, excluding land, are depreciated on a straight-line basis.

Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. During 2014, 2013 and 2012, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 17 for further discussion of these impairments.

Interest Capitalization, Policy [Policy Text Block]

Capitalized Interest

Interest from external borrowings is capitalized on significant projects until the asset is ready for service using the weighted average cost of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.

Goodwill and Intangible Assets, Policy [Policy Text Block]

Goodwill

Goodwill represents the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment at least annually. This test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. When the qualitative assessment indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, the quantitative assessment is then performed. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense.

Our goodwill, which is included in other long-term assets on our consolidated balance sheets, was $15 million and $43 million, respectively, as of December 31, 2014 and 2013. The 2014 amount consists of $15 million of excess consideration over the fair value of assets acquired in our Horizon Drilling Services acquisition in 2011. The 2013 amount also included $28 million of excess consideration over the fair value of assets acquired in our Bronco Drilling Company acquisition in 2011. We no longer have the goodwill balance related to Bronco Drilling Company as a result of the spin-off of our oilfield services business in June 2014. We performed annual impairment tests of goodwill in the fourth quarters of 2014 and 2013. Based on these assessments, no impairment of goodwill was required. Goodwill was included in our exploration and production segment as of December 31, 2014 and as of December 31, 2013 was included in our former oilfield services segment.

Cash and Cash Equivalents, Accounts Payable, Policy [Policy Text Block]

Accounts Payable

Included in accounts payable as of December 31, 2014 and 2013 are liabilities of approximately $333 million and $397 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.

Cash and Cash Equivalents and Restricted Cash

For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. Restricted cash consists of the balance required to be maintained by the terms of the agreement governing the activities of CHK Cleveland Tonkawa, L.L.C. (CHK C-T) and, prior to our repurchase of all of the outstanding preferred shares of CHK Utica, L.L.C. (CHK Utica) in 2014, also consisted of a balance required to be maintained by the terms of the agreement governing the activities of CHK Utica. The repurchase of outstanding preferred shares of CHK Utica eliminated the restricted cash maintenance requirement related to this entity. See Note 8 for further discussion of these entities.

Debt, Policy [Policy Text Block]

Debt Issuance and Hedging Facility Costs

Included in other long-term assets are costs associated with the issuance of our senior notes, revolving credit facility, hedging facility and, as of December 31, 2013, costs associated with our former term loan and former oilfield services credit facility. The remaining unamortized issuance costs as of December 31, 2014 and 2013 totaled $130 million and $145 million, respectively, and are being amortized over the life of the applicable debt or facility using the effective interest method.

Environmental Costs, Policy [Policy Text Block]

Environmental Remediation Costs

Chesapeake records environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Asset Retirement Obligations, Policy [Policy Text Block]

Asset Retirement Obligations

We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. See Note 20 for further discussion of asset retirement obligations.

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

Oil, Natural Gas and NGL Sales. Revenue from the sale of oil, natural gas and NGL is recognized when title passes, net of royalties due to third parties and gathering and transportation charges.

Natural Gas Imbalances. We follow the "sales method" of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining natural gas reserves on the underlying properties. The natural gas imbalance net liability position as of December 31, 2014 and 2013 was $12 million and $11 million, respectively.

Marketing, Gathering and Compression Sales. Chesapeake takes title to the oil, natural gas and NGL it purchases from other interest owners in operated wells at defined delivery points and delivers the product to third parties, at which time revenues are recorded. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. In circumstances where we act as a principal rather than an agent, Chesapeake's results of operations related to its oil, natural gas and NGL marketing activities are presented on a "gross" basis. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated.

Oilfield Services Revenue. Prior to the spin-off of our oilfield services business in June 2014, we reported oilfield services revenue. Our former oilfield services operating segment was responsible for contract drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Our oilfield services revenues prior to the spin-off were as follows:

•

Drilling. Revenues were generated by drilling oil and natural gas wells for our customers under daywork contracts and recognized for the days completed based on the dayrate specified in each contract. Revenue generated and costs incurred for mobilization services were recognized over the days of actual mobilization.

•

Hydraulic Fracturing. Revenue was recognized upon the completion of each fracturing stage. Typically, one or more fracturing stages per day per active crew was completed during the course of a job. A stage was considered complete when the customer requested or the job design dictated that pumping discontinue for that stage. Invoices typically included a lump sum equipment charge determined by the rate per stage specified in each contract and product charges for sand, chemicals and other products actually consumed during the course of providing fracturing services.

•

Oilfield Rentals. Oilfield equipment rentals included drill pipe, drill collars, tubing, blowout preventers, and frac and mud tanks, and services included air drilling services and services associated with the transfer of fresh water to the wellsite. Rentals and services were priced by the day or hour based on the type of equipment rented and the service job performed. Revenue was recognized ratably over the term of the rental.

•

Oilfield Trucking. Oilfield trucking provided rig relocation and logistics services as well as fluid handling services. Trucks moved drilling rigs, crude oil, other fluids and construction materials to and from the wellsites and also transported produced water from the wellsites. These services were priced on a per barrel basis based on mileage and revenue was recognized as services were performed.

•

Other Operations. A manufacturing subsidiary designed, engineered and fabricated natural gas compressor packages that were purchased primarily by Chesapeake. Compression units were priced based on certain specifications such as horsepower, stages and additional options. Revenue was recognized upon completion and transfer of ownership of the natural gas compression unit.

Fair Value Measurement, Policy [Policy Text Block]

Fair Value Measurements

Certain financial instruments are reported at fair value on our 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 asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

The carrying values of financial instruments comprising cash and cash equivalents, restricted cash, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments.

Derivatives, Policy [Policy Text Block]

Derivatives

Derivative instruments are recorded on our consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Locked-in gains and losses of settled cash flow hedges are recorded in accumulated other comprehensive income and are transferred to earnings in the month of production. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge ineffectiveness and are recognized currently in earnings. Locked-in gains and losses related to settled fair value hedges are amortized as an adjustment to interest expense over the remaining term of the related senior notes. We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in our consolidated statements of operations within oil, natural gas and NGL sales and interest expense, respectively.

Derivative instruments reflected as current in the 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 respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type (i.e., commodity, interest rate and cross currency contracts) which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.

We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 11 for further discussion of our derivative instruments.

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only be settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as compensation expense in the consolidated statements of operations.

To the extent compensation cost relates to employees directly involved in the acquisition of oil and natural gas leasehold and exploration and development activities, these amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses, oil, natural gas and NGL production expenses, or marketing, gathering and compression expenses, based on the employees involved in those activities.

Cash inflows resulting from tax deductions in excess of compensation expense recognized for stock options and restricted stock are classified as financing cash inflows, while reductions in tax benefits are classified as operating cash outflows in our consolidated statements of cash flows. See Note 9 for further discussion of share-based compensation.

Reclassification, Policy [Policy Text Block]

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for 2012 and 2013 to conform to the presentation used for the 2014 consolidated financial statements.

Variable_Interest_Entities_Pol

Variable Interest Entities (Policies)	12 Months Ended
	Dec. 31, 2014
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Consolidation, Variable Interest Entity, Policy [Policy Text Block]	Variable Interest Entities
	VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
	Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both our consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs.
	We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.

Impairments_Policies

Impairments (Policies)	12 Months Ended
	Dec. 31, 2014
Asset Impairment Charges [Abstract]
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]	Our oil and natural gas properties are subject to quarterly full cost ceiling tests.

Basis_of_Presentation_and_Summ2

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]	Accounts receivable as of December 31, 2014 and 2013 are detailed below.
			December 31,
			2014			2013
			($ in millions)
	Oil, natural gas and NGL sales		$	1,340		$	1,548
	Joint interest		691			417
	Oilfield services(a)		—			63
	Related parties(b)		—			62
	Other		226			150
	Allowance for doubtful accounts		(21		)	(18		)
	Total accounts receivable, net		$	2,236		$	2,222
	___________________________________________
	(a)	In 2014, in connection with the spin-off of our oilfield services business, accounts receivable related to oilfield services were removed from our consolidated balance sheet.
	(b)	See Note 7 for discussion of related party transactions.
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization [Table Text Block]	The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2014 and the year in which the associated costs were incurred.
			Year of Acquisition
			2014			2013			2012		Prior		Total
			($ in millions)
	Leasehold acquisition cost		$	577		$	199		$	1,462	$	5,149	$	7,387
	Exploration cost		340			90			244		42		716
	Capitalized interest		492			421			325		447		1,685
	Total		$	1,409		$	710		$	2,031	$	5,638	$	9,788

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Table Text Block]	For the years ended December 31, 2014, 2013 and 2012, shares of the following securities and associated adjustments to net income, representing dividends on preferred stock and allocated earnings on participating securities, were excluded from the calculation of diluted EPS as the effect was antidilutive. The impact of our stock options was immaterial in the calculation of diluted EPS for these periods.
		Net Income		Shares
		Adjustments
		($ in millions)		(in millions)
	Year Ended December 31, 2014
	Participating securities	$	22	3
	Year Ended December 31, 2013
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	86	56
	5.75% cumulative convertible preferred stock (series A)	$	63	40
	5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
	4.50% cumulative convertible preferred stock	$	12	6
	Participating securities	$	10	5
	Year Ended December 31, 2012
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	86	56
	5.75% cumulative convertible preferred stock (series A)	$	63	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
	4.50% cumulative convertible preferred stock	$	12	6
	Participating securities	$	—	5
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	A reconciliation of basic EPS and diluted EPS for the year ended December 31, 2014 is as follows:
		Income (Numerator)		Weighted	Per
				Average	Share
				Shares	Amount
				(Denominator)
		(in millions, except per share data)
	For the Year Ended December 31, 2014:
	Basic EPS	$	1,273	659	$	1.93
	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	86		59
	Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)	63		42
	Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)	10		6
	Common shares assumed issued for 4.50% cumulative convertible preferred stock	12		6
	Diluted EPS	$	1,444	772	$	1.87

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of Debt [Table Text Block]	Our long-term debt consisted of the following as of December 31, 2014 and 2013:
			December 31,
			2014				2013
			($ in millions)
	Term loan due 2017(a)		$	—			$	2,000
	9.5% senior notes due 2015(b)		—				1,265
	3.25% senior notes due 2016		500				500
	6.25% euro-denominated senior notes due 2017(c)		416				473
	6.5% senior notes due 2017		660				660
	6.875% senior notes due 2018(d)		—				97
	7.25% senior notes due 2018		669				669
	Floating rate senior notes due 2019		1,500				—
	6.625% senior notes due 2019(e)		—				650
	6.625% senior notes due 2020		1,300				1,300
	6.875% senior notes due 2020		500				500
	6.125% senior notes due 2021		1,000				1,000
	5.375% senior notes due 2021		700				700
	4.875% senior notes due 2022		1,500				—
	5.75% senior notes due 2023		1,100				1,100
	2.75% contingent convertible senior notes due 2035(f)		396				396
	2.5% contingent convertible senior notes due 2037(f)		1,168				1,168
	2.25% contingent convertible senior notes due 2038(f)		347				347
	Revolving credit facility		—				—
	Oilfield services revolving credit facility(g)		—				405
	Discount on senior notes and term loan(h)		(231		)		(357		)
	Interest rate derivatives(i)		10				13
	Total debt, net		11,535				12,886
	Less current maturities of long-term debt, net(j)		(381		)		—
	Total long-term debt, net		$	11,154			$	12,886
	___________________________________________
	(a)	In 2014, we repaid the borrowings outstanding under and terminated the term loan due 2017.
	(b)	In 2014, we completed a tender offer for a portion of the 9.5% Senior Notes due 2015, and we redeemed the remaining balance of the notes.
	(c)	The principal amount shown is based on the exchange rate of $1.2098 to €1.00 and $1.3743 to €1.00 as of December 31, 2014 and 2013, respectively. See Note 11 for information on our related foreign currency derivatives.
	(d)	In 2014, we redeemed all outstanding 6.875% Senior Notes due 2018.
	(e)	Initial issuers were Chesapeake Oilfield Operating, L.L.C. (COO) and Chesapeake Oilfield Finance, Inc., a wholly owned subsidiary of COO. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes. In 2014, in connection with the spin-off of our oilfield services business, the obligations with respect to the COO senior notes were removed from our consolidated balance sheet. See Note 13 for further discussion of the spin-off.
	(f)	The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows:
	Holders’ Demand Repurchase Rights. 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.
	Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, the notes are convertible 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 quarterly. During the specified period in the fourth quarter of 2014, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the first quarter of 2015 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. The notes were not convertible under this provision in 2014, 2013 or 2012. 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 the principal amount.
	Contingent Interest. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years during certain periods if the average trading price of the notes exceeds the threshold defined in the indenture.
	The holders’ demand repurchase dates, the common stock price conversion threshold amounts (as adjusted to give effect to the dividend of SSE common stock paid in the spin-off of our oilfield services business and cash dividends on our common stock) and the ending date of the first six-month period in which contingent interest may be payable for the contingent convertible senior notes are as follows:
	Contingent		Holders' Demand		Common Stock				Contingent Interest
	Convertible		Repurchase Dates		Price Conversion				First Payable
	Senior  Notes				Thresholds				(if applicable)
	2.75% due 2035		November 15, 2015, 2020, 2025, 2030		$	45.14			May 14, 2016
	2.5% due 2037		May 15, 2017, 2022, 2027, 2032		$	59.71			November 14, 2017
	2.25% due 2038		December 15, 2018, 2023, 2028, 2033		$	100.35			June 14, 2019
	Optional Redemption by the Company. We may redeem the contingent 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.
	(g)	In 2014, in connection with the spin-off of our oilfield services business, we terminated our oilfield services credit facility. See Note 13 for further discussion of the spin-off.
	(h)	Discount as of December 31, 2014 and 2013 included $224 million and $303 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. Discount also included $33 million as of December 31, 2013 associated with our term loan due 2017 discussed below.
	(i)	See Note 11 for further discussion related to these instruments.
	(j)	As of December 31, 2014, there was $15 million of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035. As discussed in footnote (f) above, the holders of our 2.75% Contingent Convertible Senior Notes due 2035 could exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the principal amount of the notes.
Schedule of Maturities of Long-term Debt [Table Text Block]	Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes, for the five years ended after December 31, 2014 and thereafter are as follows:
			Principal Amount
			of Debt Securities
			($ in millions)
	2015		$	396
	2016		500
	2017		2,244
	2018		1,016
	2019		1,500
	2020 and thereafter		6,100
	Total		$	11,756
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.
			31-Dec-14							31-Dec-13
			Carrying				Estimated			Carrying		Estimated
			Amount				Fair Value			Amount		Fair Value
							($ in millions)
	Long-term debt (Level 1)		$	11,525			$	12,052		$	10,501	$	11,557
	Long-term debt (Level 2)		$	—			$	—		$	2,372	$	2,369

Contingencies_and_Commitments_1

Contingencies and Commitments (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Operating Leases [Table Text Block]	The aggregate undiscounted minimum future lease payments are presented below.
		31-Dec-14
		($ in millions)
	2015	$	5
	2016	4
	2017	1
	2018	1
	Total	$	11
Gathering, Processing and Transportation Commitments [Table Text Block]	The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners or credits for third-party volumes, are presented below.
		December 31, 2014
		($ in millions)
	2015	$	1,855
	2016	1,987
	2017	2,003
	2018	1,802
	2019	1,516
	2020 - 2099	6,880
	Total	$	16,043
Drilling Contract Commitments [Table Text Block]	As of December 31, 2014, the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below.
		December 31,
		2014
		($ in millions)
	2015	$	232
	2016	179
	2017	91
	Total	$	502
Pressure Pumping Contract Commitments [Table Text Block]	The aggregate undiscounted minimum future payments under this agreement are detailed below.
		31-Dec-14
		($ in millions)
	2015	$	245
	2016	162
	2017	59
	Total	$	466

Other_Liabilities_Tables

Other Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Other Liabilities Disclosure [Abstract]
Other Current Liabilities [Table Text Block]	Other current liabilities as of December 31, 2014 and 2013 are detailed below.
			December 31,
			2014		2013
			($ in millions)
	Revenues and royalties due others		$	1,176	$	1,409
	Accrued oil, natural gas and NGL drilling and production costs		385		457
	Joint interest prepayments received		189		464
	Accrued compensation and benefits		344		320
	Other accrued taxes		55		161
	Accrued dividends		101		101
	Other		811		599
	Total other current liabilities		$	3,061	$	3,511
Other Long-Term Liabilities [Table Text Block]	Other long-term liabilities as of December 31, 2014 and 2013 are detailed below.
			December 31,
			2014		2013
			($ in millions)
	CHK Utica ORRI conveyance obligation(a)		$	220	$	250
	CHK C-T ORRI conveyance obligation(b)		135		149
	Financing obligations		30		31
	Unrecognized tax benefits		45		317
	Other		249		237
	Total other long-term liabilities		$	679	$	984
	____________________________________________
	(a)	$14 million and $13 million of the total $234 million and $263 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction.
	(b)	$23 million and $12 million of the total $158 million and $161 million obligations are recorded in other current liabilities as of December 31, 2014 and 2013, respectively. See Noncontrolling Interests in Note 8 for further discussion of the transaction.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The components of the income tax provision (benefit) for each of the periods presented below are as follows:
		Years Ended December 31,
		2014			2013			2012
		($ in millions)
	Current
	Federal	$	—		$	—		$	—
	State	47			22			47
	Current Income Taxes	47			22			47
	Deferred
	Federal	1,115			502			(358		)
	State	(18		)	24			(69		)
	Deferred Income Taxes	1,097			526			(427		)
	Total	$	1,144		$	548		$	(380	)
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:
		Years Ended December 31,
		2014			2013			2012
		($ in millions)
	Income tax expense (benefit) at the federal statutory rate (35%)	$	1,120		$	505		$	(341	)
	State income taxes (net of federal income tax benefit)	68			88			(38		)
	Remeasurement of state deferred tax liabilities	(114		)	(38		)	(19		)
	Change in valuation allowance	74			(12		)	—
	Other	(4		)	5			18
	Total	$	1,144		$	548		$	(380	)
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:
		Years Ended December 31,
		2014			2013
		($ in millions)
	Deferred tax liabilities:
	Oil and natural gas properties	$	(3,950	)	$	(2,631	)
	Other property and equipment	(14		)	(371		)
	Volumetric production payments	(920		)	(1,216		)
	Contingent convertible debt	(443		)	(439		)
	Deferred revenue	(102		)	—
	Derivative instruments	(428		)	—
	Deferred tax liabilities	(5,857		)	(4,657		)
	Deferred tax assets:
	Net operating loss carryforwards (carrybacks)	945			535
	Derivative instruments	—			108
	Asset retirement obligations	165			153
	Investments	88			130
	Deferred stock compensation	50			66
	Accrued liabilities	214			120
	Noncontrolling interest liabilities	135			152
	Alternative minimum tax credits	34			317
	Other	56			40
	Deferred tax assets	1,687			1,621
	Valuation allowance	(222		)	(148		)
	Net deferred tax assets	1,465			1,473
	Net deferred tax assets (liabilities)	$	(4,392	)	$	(3,184	)
	Reflected in accompanying balance sheets as:
	Current deferred income tax asset	—			223
	Current deferred income tax liability	(207		)	—
	Non-current deferred income tax liability	(4,185		)	(3,407		)
	Total	$	(4,392	)	$	(3,184	)
Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Table Text Block]	A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
		2014			2013			2012
		($ in millions)
	Unrecognized tax benefits at beginning of period	$	644		$	599		$	369
	Additions based on tax positions related to the current year	13			15			134
	Additions to tax positions of prior years	—			30			96
	Reductions to tax positions of prior years	(354		)	—			—
	Unrecognized tax benefits at end of period	$	303		$	644		$	599

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule of Related Party Transactions [Table Text Block]	During 2014, 2013 and 2012, we had the following transactions with our equity method investees:
			Years Ended December 31,
			2014		2013		2012
			($ in millions)
	Purchases(a)		$	—	$	—	$	73
	Sales(b)		$	—	$	666	$	392
	Services(c)		$	220	$	397	$	480
	___________________________________________
	(a)	Purchase of equipment from FTS International, Inc. (FTS).
	(b)	In 2013 and 2012, Chesapeake sold produced gas to our 30%-owned investee, Twin Eagle Resource Management LLC (Twin Eagle). We sold our investment in Twin Eagle in 2014.
	(c)	Hydraulic fracturing and other services provided to us by FTS in the ordinary course of business. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs.
	The table below shows the total amounts due from and due to our equity method investees.
			December 31,
			2014		2013		2012
			($ in millions)
	Amounts due from equity method investees		$	—	$	47	$	67
	Amounts due to equity method investees		$	—	$	1	$	42

Equity_Tables

Equity (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Common Stock [Table Text Block]	The following is a summary of the changes in our common shares issued for the years ended December 31, 2014, 2013 and 2012:
			Years Ended December 31,
			2014			2013			2012
			(in thousands)
	Shares issued as of January 1		666,192			666,468			660,888
	Restricted stock issuances (net of forfeitures and cancellations)(a)		(2,529	)		(599	)		5,038
	Stock option exercises		1,281			323			542
	Shares issued as of December 31		664,944			666,192			666,468
	___________________________________________
	(a)	In the second quarter of 2013, we began granting restricted stock units (RSUs) in lieu of restricted stock awards (RSAs) to non-employee directors and employees. Shares of common stock underlying RSUs are issued when the units vest, whereas shares of common stock are issued on the date the RSAs are granted. We refer to RSAs and RSUs collectively as restricted stock.
Schedule of Preferred Stock Summary and Conversion Terms [Table Text Block]	Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2014:
	Preferred Stock Series		Issue Date		Liquidation				Holder's Conversion Right		Conversion Rate		Conversion Price				Company's	Company's Market Conversion Trigger(a)
					Preference												Conversion
					per Share												Right From
	5.75% cumulative		May and		$	1,000			Any time		39.5856		$	25.2617			May 17, 2015	$	32.8402
	convertible		Jun-10
	non-voting
	5.75% (series A)		May		$	1,000			Any time		38.2538		$	26.1412			May 17, 2015	$	33.9836
	cumulative		2010
	convertible
	non-voting
	4.50% cumulative convertible		Sep-05		$	100			Any time		2.4468		$	40.8693			September 15, 2010	$	53.1301
	5.00% cumulative convertible (series 2005B)		Nov-05		$	100			Any time		2.7669		$	36.1415			November 15, 2010	$	46.984
	___________________________________________
	(a)	Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding.
Schedule of Stock by Class [Table Text Block]	The following reflects the shares outstanding of our preferred stock for the years ended December 31, 2014, 2013 and 2012:
			5.75%			5.75% (A)			4.50%			5.00%
												(2005B)
			(in thousands)
	Shares outstanding as of January 1, 2014, 2013 and 2012 and shares outstanding as of December 31, 2014, 2013 and 2012		1,497			1,100			2,559			2,096
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	For the years ended December 31, 2014 and 2013, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.
			Net Gains				Net Gains				Total
			(Losses) on				(Losses)
			Cash Flow				on
			Hedges				Investments
			($ in millions)
	Balance, December 31, 2013		$	(167	)		$	5			$	(162	)
	Other comprehensive income before reclassifications		1				—				1
	Amounts reclassified from accumulated other comprehensive income		23				(5		)		18
	Net other comprehensive income		24				(5		)		19
	Balance, December 31, 2014		$	(143	)		$	—			$	(143	)
	Balance, December 31, 2012		$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications		2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income		20				4				24
	Net other comprehensive income		22				(2		)		20
	Balance, December 31, 2013		$	(167	)		$	5			$	(162	)
	A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
			Years Ended December 31,
			2014								2013							2012
			Before				After				Before				After			Before			After
			Tax				Tax				Tax				Tax			Tax			Tax
			($ in millions)
	Balance, beginning of period		$	(269	)		$	(167	)		$	(304	)		$	(189	)	$	(287	)	$	(178	)
	Net change in fair value		1				1				3				2			10			6
	Gains (losses) reclassified to income		37				23				32				20			(27		)	(17		)
	Balance, end of period		$	(231	)		$	(143	)		$	(269	)		$	(167	)	$	(304	)	$	(189	)
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	For the years ended December 31, 2014 and 2013, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statements of operations are detailed below.
	Details About Accumulated		Affected Line Item		Year Ended
	Other Comprehensive		in the Statement		December 31,
	Income (Loss) Components		Where Net Income is Presented		2014
					($ in millions)
	Year Ended December 31, 2014:
	Net losses on cash flow hedges:
	Commodity contracts		Oil, natural gas and NGL revenues		$	23
	Investments:
	Sale of investment		Net gain on sale of investment		(5		)
	Total reclassifications for the period, net of tax				$	18
	Year Ended December 31, 2013:
	Net losses on cash flow hedges:
	Commodity contracts		Oil, natural gas and NGL revenues		$	20
	Investments:
	Impairment of investment		Losses on investments		6
	Sale of investment		Net gain on sale of investment		(2		)
	Total reclassifications for the period, net of tax				$	24
Distributions Made to Limited Partner, by Distribution [Table Text Block]	For the years ended December 31, 2014, 2013 and 2012, the Trust declared and paid the following distributions:
	Production Period		Distribution Date		Cash Distribution				Cash Distribution
					per				per
					Common Unit				Subordinated Unit
	June 2014 - August 2014		December 1, 2014		$	0.5079			$	—
	March 2014 - May 2014		August 29, 2014		$	0.5796			$	—
	December 2013 - February 2014		May 30, 2014		$	0.6454			$	—
	September 2013 - November 2013		March 3, 2014		$	0.6624			$	—
	June 2013 - August 2013		November 29, 2013		$	0.6671			$	—
	March 2013 - May 2013		August 29, 2013		$	0.69			$	0.1432
	December 2012 - February 2013		May 31, 2013		$	0.69			$	0.301
	September 2012 - November 2012		March 1, 2013		$	0.67			$	0.3772
	June 2012 - August 2012		November 29, 2012		$	0.63			$	0.2208
	March 2012 - May 2012		August 30, 2012		$	0.61			$	0.4819
	December 2011 - February 2012		May 31, 2012		$	0.6588			$	0.6588
	September 2011 - November 2011		March 1, 2012		$	0.7277			$	0.7277

ShareBased_Compensation_Tables

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Unvested Restricted Stock Units Roll Forward [Table Text Block]	A summary of the changes in unvested restricted stock during 2014, 2013 and 2012 is presented below.
			Shares of			Weighted Average
			Unvested			Grant Date
			Restricted Stock			Fair Value
			(in thousands)
	Unvested restricted stock as of January 1, 2014		13,400			$	23.38
	Granted		5,049			$	25.92
	Vested		(4,803	)		$	27.17
	Forfeited		(3,555	)		$	28.09
	Unvested restricted stock as of December 31, 2014		10,091			$	21.2
	Unvested restricted stock as of January 1, 2013		18,899			$	23.72
	Granted		9,189			$	19.68
	Vested		(12,897	)		$	21.32
	Forfeited		(1,791	)		$	22.86
	Unvested restricted stock as of December 31, 2013		13,400			$	23.38
	Unvested restricted stock as of January 1, 2012		19,544			$	26.97
	Granted		9,480			$	21.13
	Vested		(8,620	)		$	28.08
	Forfeited		(1,505	)		$	24.57
	Unvested restricted stock as of December 31, 2012		18,899			$	23.72
Equity-Classified Share-Based Payment Award Valuation Assumptions [Table Text Block]	The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2014:
	Expected option life - years		5.9
	Volatility		48.63	%
	Risk-free interest rate		1.93	%
	Dividend yield		1.33	%
	For the 2014 awards, the Company utilized the Monte Carlo simulation for the TSR performance measure, and the following assumptions to determine the grant date fair value of the PSUs:
	Volatility		41.37	%
	Risk-free interest rate		0.76	%
	Dividend yield for value of awards		1.36	%
Schedule of Share-Based Compensation, Stock Options, Activity [Table Text Block]	The following table provides information related to stock option activity for 2014, 2013 and 2012:
			Number of			Weighted			Weighted		Aggregate
			Shares			Average			Average		Intrinsic
			Underlying			Exercise			Contract		Value(a)
			Options			Price			Life in
						Per Share			Years
			(in thousands)								($ in millions)
	Outstanding at January 1, 2014		5,268			$	19.28		6.66		$	41
	Granted		994			$	24.43
	Exercised		(1,322	)		$	18.71				$	11
	Expired		(28	)		$	18.97
	Forfeited		(313	)		$	21.05
	Outstanding at December 31, 2014		4,599			$	19.55		7.03		$	5
	Exercisable at December 31, 2014		1,304			$	18.71		5.7		$	1
	Outstanding at January 1, 2013		481			$	12.69		0.96		$	2
	Granted		5,264			$	19.32
	Exercised		(346	)		$	10.82				$	3
	Expired		(131	)		$	19.31
	Outstanding at December 31, 2013		5,268			$	19.28		6.66		$	41
	Exercisable at December 31, 2013		1,552			$	18.82		1.97		$	13
	Outstanding at January 1, 2012		1,051			$	9.84		1.41		$	13
	Exercised		(570	)		$	7.45				$	7
	Outstanding and exercisable at December 31, 2012		481			$	12.69		0.96		$	2
	___________________________________________
	(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.
Equity-Classified Stock-Based Compensation [Table Text Block]	We recognized the following compensation costs related to PSUs for the years ended December 31, 2014, 2013 and 2012:
			Years Ended December 31,
			2014				2013			2012
			($ in millions)
	General and administrative expenses		$	(4	)		$	34		$	8
	Oil and natural gas properties		3				9			4
	Oil, natural gas and NGL production expenses		—				2			1
	Marketing, gathering and compression expenses		—				2			1
	Oilfield services expenses		—				1			—
	Total		$	(1	)		$	48		$	14
	We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2014, 2013 and 2012:
			Years Ended December 31,
			2014				2013			2012
			($ in millions)
	General and administrative expenses		$	46			$	60		$	71
	Oil and natural gas properties		29				52			71
	Oil, natural gas and NGL production expenses		18				21			24
	Marketing, gathering and compression expenses		6				7			15
	Oilfield services expenses		5				10			10
	Total		$	104			$	150		$	191
Liability-Classified Share-Based Payment Award Valuation Assumptions [Table Text Block]	The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2014:
	Expected option life - years		5.9
	Volatility		48.63	%
	Risk-free interest rate		1.93	%
	Dividend yield		1.33	%
	For the 2014 awards, the Company utilized the Monte Carlo simulation for the TSR performance measure, and the following assumptions to determine the grant date fair value of the PSUs:
	Volatility		41.37	%
	Risk-free interest rate		0.76	%
	Dividend yield for value of awards		1.36	%
Schedule of Nonvested Performance-based Units Activity [Table Text Block]	The following table presents a summary of our PSU awards:
			Units			Fair Value			Fair Value(a)				Liability for
						as of							Vested
						Grant Date							Amount
						($ in millions)
	2012 Awards (b)
	Payable 2015		884,507			$	23		$	12			$	12
	2013 Awards
	Payable 2016		1,701,941			$	35		$	42			$	39
	2014 Awards
	Payable 2017		609,637			$	16		$	10			$	7
	___________________________________________
	(a)	As of December 31, 2014.
	(b)	In 2014 and 2013, we paid $11 million and $2 million, respectively, related to 2012 PSU awards.
Liability-Classified Stock-Based Compensation [Table Text Block]	We recognized the following compensation costs related to PSUs for the years ended December 31, 2014, 2013 and 2012:
			Years Ended December 31,
			2014				2013			2012
			($ in millions)
	General and administrative expenses		$	(4	)		$	34		$	8
	Oil and natural gas properties		3				9			4
	Oil, natural gas and NGL production expenses		—				2			1
	Marketing, gathering and compression expenses		—				2			1
	Oilfield services expenses		—				1			—
	Total		$	(1	)		$	48		$	14
	We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2014, 2013 and 2012:
			Years Ended December 31,
			2014				2013			2012
			($ in millions)
	General and administrative expenses		$	46			$	60		$	71
	Oil and natural gas properties		29				52			71
	Oil, natural gas and NGL production expenses		18				21			24
	Marketing, gathering and compression expenses		6				7			15
	Oilfield services expenses		5				10			10
	Total		$	104			$	150		$	191

Derivative_and_Hedging_Activit1

Derivative and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments Included in Trading Activities [Table Text Block]	The estimated fair values of our oil and natural gas derivative instrument assets (liabilities) as of December 31, 2014 and 2013 are provided below.
			31-Dec-14							31-Dec-13
			Volume			Fair Value				Volume			Fair Value
						($ in millions)							($ in millions)
	Oil (mmbbl):
	Fixed-price swaps		12.5			471				25.3			(50		)
	Three-way collars		4.4			40				—			—
	Call options		35.8			(89		)		42.5			(265		)
	Basis protection swaps		—			—				0.4			1
	Total oil		52.7			422				68.2			(314		)
	Natural gas (tbtu):
	Fixed-price swaps		275			$	281			448			$	(23	)
	Three-way collars		207			165				288			(7		)
	Call options		193			(170		)		193			(210		)
	Call swaptions		—			—				12			—
	Basis protection swaps		60			23				68			3
	Total natural gas		735			299				1,009			(237		)
	Total estimated fair value					$	721						$	(551	)
Schedule Of Derivative Instruments In Condensed Consolidated Balance Sheets [Table Text Block]	The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2014 and 2013 on a gross basis and after same-counterparty netting:
	Balance Sheet Classification		Gross				Amounts Netted				Net Fair Value Presented
			Fair Value				in Consolidated				in Consolidated
							Balance Sheet				Balance Sheet
			($ in millions)
	As of December 31, 2014
	Commodity Contracts
	Short-term derivative asset		$	974			$	(95	)		$	879
	Long-term derivative asset		16				(10		)		6
	Short-term derivative liability		(105		)		95				(10		)
	Long-term derivative liability		(163		)		10				(153		)
	Total commodity contracts		722				—				722
	Interest Rate Contracts
	Short-term derivative liability		(5		)		—				(5		)
	Long-term derivative liability		(12		)		—				(12		)
	Total interest rate contracts		(17		)		—				(17		)
	Foreign Currency Contracts(a)
	Long-term derivative liability		(53		)		—				(53		)
	Total foreign currency contracts		(53		)		—				(53		)
	Total Derivatives		$	652			$	—			$	652
	As of December 31, 2013
	Commodity Contracts
	Short-term derivative asset		$	29			$	(29	)		$	—
	Long-term derivative asset		11				(9		)		2
	Short-term derivative liability		(231		)		29				(202		)
	Long-term derivative liability		(362		)		9				(353		)
	Total commodity contracts		(553		)		—				(553		)
	Interest Rate Contracts
	Short-term derivative liability		(6		)		—				(6		)
	Long-term derivative liability		(92		)		—				(92		)
	Total interest rate contracts		(98		)		—				(98		)
	Foreign Currency Contracts(a)
	Long-term derivative asset		2				—				2
	Total foreign currency contracts		2				—				2
	Total Derivatives		$	(649	)		$	—			$	(649	)
	____________________________________________
	(a)	Designated as cash flow hedging instruments.
Schedule of Derivative Instruments [Table Text Block]	The components of oil, natural gas and NGL sales for the years ended December 31, 2014, 2013 and 2012 are presented below.
			Years Ended December 31,
			2014				2013				2012
			($ in millions)
	Oil, natural gas and NGL sales		$	7,162			$	6,923			$	5,359
	Gains on undesignated oil and natural gas derivatives		1,055				443				857
	Gains (losses) on terminated cash flow hedges		(37		)		(314		)		62
	Total oil, natural gas and NGL sales		$	8,180			$	7,052			$	6,278
Interest Income And Interest Expense Disclosure [Table Text Block]	The components of interest expense for the years ended December 31, 2014, 2013 and 2012 are presented below.
			Years Ended December 31,
			2014				2013				2012
			($ in millions)
	Interest expense on senior notes		$	704			$	740			$	732
	Interest expense on term loans		36				116				173
	Amortization of loan discount, issuance costs and other		42				91				89
	Interest expense on credit facilities		28				38				70
	Gains on terminated fair value hedges		(3		)		(5		)		(8		)
	(Gains) losses on undesignated interest rate derivatives		(81		)		63				1
	Capitalized interest		(637		)		(816		)		(980		)
	Total interest expense		$	89			$	227			$	77
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	For the years ended December 31, 2014 and 2013, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.
			Net Gains				Net Gains				Total
			(Losses) on				(Losses)
			Cash Flow				on
			Hedges				Investments
			($ in millions)
	Balance, December 31, 2013		$	(167	)		$	5			$	(162	)
	Other comprehensive income before reclassifications		1				—				1
	Amounts reclassified from accumulated other comprehensive income		23				(5		)		18
	Net other comprehensive income		24				(5		)		19
	Balance, December 31, 2014		$	(143	)		$	—			$	(143	)
	Balance, December 31, 2012		$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications		2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income		20				4				24
	Net other comprehensive income		22				(2		)		20
	Balance, December 31, 2013		$	(167	)		$	5			$	(162	)
	A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
			Years Ended December 31,
			2014								2013							2012
			Before				After				Before				After			Before			After
			Tax				Tax				Tax				Tax			Tax			Tax
			($ in millions)
	Balance, beginning of period		$	(269	)		$	(167	)		$	(304	)		$	(189	)	$	(287	)	$	(178	)
	Net change in fair value		1				1				3				2			10			6
	Gains (losses) reclassified to income		37				23				32				20			(27		)	(17		)
	Balance, end of period		$	(231	)		$	(143	)		$	(269	)		$	(167	)	$	(304	)	$	(189	)
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:
			Quoted				Significant				Significant				Total
			Prices in				Other				Unobservable				Fair Value
			Active				Observable				Inputs
			Markets				Inputs				(Level 3)
			(Level 1)				(Level 2)
							($ in millions)
	As of December 31, 2014
	Derivative Assets (Liabilities):
	Commodity assets		$	—			$	785			$	205			$	990
	Commodity liabilities		—				(9		)		(259		)		(268		)
	Interest rate liabilities		—				(17		)		—				(17		)
	Foreign currency liabilities		—				(53		)		—				(53		)
	Total derivatives		$	—			$	706			$	(54	)		$	652
	As of December 31, 2013
	Derivative Assets (Liabilities):
	Commodity assets		$	—			$	25			$	15			$	40
	Commodity liabilities		—				(100		)		(493		)		(593		)
	Interest rate liabilities		—				(98		)		—				(98		)
	Foreign currency assets		—				2				—				2
	Total derivatives		$	—			$	(171	)		$	(478	)		$	(649	)
	The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:
			Quoted				Significant				Significant				Total
			Prices in				Other				Unobservable				Fair Value
			Active				Observable				Inputs
			Markets				Inputs				(Level 3)
			(Level 1)				(Level 2)
							($ in millions)
	As of December 31, 2014
	Financial Assets (Liabilities):
	Other current assets		$	57			$	—			$	—			$	57
	Other current liabilities		(58		)		—				—				(58		)
	Total		$	(1	)		$	—			$	—			$	(1	)
	As of December 31, 2013
	Financial Assets (Liabilities):
	Other current assets		$	80			$	—			$	—			$	80
	Other current liabilities		(82		)		—				—				(82		)
	Total		$	(2	)		$	—			$	—			$	(2	)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2014 and 2013 is presented below.
			Derivatives
			Commodity				Interest Rate
			($ in millions)
	Beginning Balance as of January 1, 2014		$	(478	)		$	—
	Total gains (losses) (realized/unrealized):
	Included in earnings(a)		292				—
	Total purchases, issuances, sales and settlements:
	Settlements		136				—
	Transfers(b)		(4		)		—
	Ending Balance as of December 31, 2014		$	(54	)		$	—
	Beginning Balance as of January 1, 2013		$	(1,016	)		$	—
	Total gains (losses) (realized/unrealized):
	Included in earnings(a)		410				(1		)
	Total purchases, issuances, sales and settlements:
	Sales		—				1
	Settlements		128				—
	Ending Balance as of December 31, 2013		$	(478	)		$	—
	___________________________________________
	(a)		Oil, Natural Gas and								Interest Expense
			NGL Sales
			2014				2013				2014				2013
			($ in millions)
	Total gains (losses) included in earnings for the period		$	292			$	410			$	—			$	(1	)
	Change in unrealized gains (losses) related to		$	262			$	382			$	—			$	—
	assets still held at reporting date
	(b)	The values related to basis swaps were transferred from Level 3 to Level 2 as a result of our ability to begin using data readily available in the public market to corroborate our estimated fair values.
Fair Value Inputs, Assets, Quantitative Information [Table Text Block]	The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of December 31, 2014:
	Instrument		Unobservable		Range		Weighted		Fair Value
	Type		Input				Average		December 31, 2014(a)
									($ in millions)
	Oil trades		Oil price volatility curves		27.33% - 43.56%		34.09%		$	(49	)
	Natural gas trades		Natural gas price volatility		18.71% - 63.70%		34.38%		$	(5	)
			curves
	___________________________________________
	(a)	Fair value is based on an estimate derived from option models.

Natural_Gas_and_Oil_Property_T1

Natural Gas and Oil Property Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
VPP Transactions [Table Text Block]	As of December 31, 2014, our outstanding VPPs consisted of the following:
									Volume Sold
	VPP #		Date of VPP	Location		Proceeds			Oil		Natural Gas	NGL	Total
						($ in millions)			(mmbbl)		(bcf)	(mmbbl)	(bcfe)
	10		Mar-12	Anadarko Basin Granite		$	744		3		87	9.2	160
				Wash
	9		May-11	Mid-Continent		853			1.7		138	4.8	177
	8		September 2010	Barnett Shale		1,150			—		390	—	390
	4		December 2008	Anadarko and Arkoma		412			0.5		95	—	98
				Basins
	3		Aug-08	Anadarko Basin		600			—		93	—	93
	2		May-08	Texas, Oklahoma and		622			—		94	—	94
				Kansas
	1		December 2007	Kentucky and West		1,100			—		208	—	208
				Virginia
						$	5,481		5.2		1,105	14	1,220
VPP Volumes Produced During Period [Table Text Block]	The volumes produced on behalf of our VPP buyers during 2014, 2013 and 2012 were as follows:
			Year Ended December 31, 2014
	VPP #		Oil		Natural Gas			NGL		Total
			(mbbl)		(bcf)			(mbbl)		(bcfe)
	10		403		10.6			1,296.50		20.7
	9		187.5		15.4			411		19
	8		—		60.1			—		60.1
	6(a)		23.1		4.2			—		4.3
	5(a)		16.5		4.6			—		4.7
	4		48.1		9			—		9.2
	3		—		7.2			—		7.2
	2		—		6.2			—		6.2
	1		—		13.8			—		13.8
			678.2		131.1			1,707.50		145.2
			Year Ended December 31, 2013
	VPP #		Oil		Natural Gas			NGL		Total
			(mbbl)		(bcf)			(mbbl)		(bcfe)
	10		547		13.5			1,509.00		25.8
	9		213.2		17			455.7		21
	8		—		68.1			—		68.1
	6		24		4.8			—		4.9
	5		25.4		7.5			—		7.7
	4		54.7		10.2			—		10.5
	3		—		8.1			—		8.1
	2		—		10.3			—		10.3
	1		—		14.5			—		14.5
			864.3		154			1,964.70		170.9
			Year Ended December 31, 2012
	VPP #		Oil		Natural Gas			NGL		Total
			(mbbl)		(bcf)			(mbbl)		(bcfe)
	10		727		18.1			1,729.10		32.8
	9		249.3		18.4			643.6		23.7
	8		—		79.7			—		79.7
	7(b)		490.3		0.4			—		3.4
	6		24		5.3			—		5.5
	5		27.4		8.8			—		9
	4		62.8		11.7			—		12.2
	3		—		9.3			—		9.3
	2		—		11.4			—		11.3
	1		—		15.3			—		15.3
			1,580.80		178.4			2,372.70		202.2
	____________________________________________
	(a)	In 2014, we divested the properties associated with VPP #5 and VPP #6.
	(b)	In 2012, to facilitate the sales process associated with our Permian Basin divestiture packages, we purchased the remaining reserves from our Permian Basin VPP (VPP #7). The reserves purchased were subsequently sold to the buyers of our Permian Basin assets.
	The v
VPP Volumes Remaining to be Delivered [Table Text Block]	The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2014 were as follows:
				Volume Remaining as of December 31, 2014
	VPP #		Term Remaining	Oil			Natural Gas		NGL		Total
			(in months)	(mmbbl)			(bcf)		(mmbbl)		(bcfe)
	10		86	1.3			38		4.7		74
	9		74	0.8			73.2		1.9		89.9
	8		8	—			36.6		—		36.6
	4		24	0.1			15.3		—		15.8
	3		55	—			23.9		—		23.9
	2		52	—			13.8		—		13.8
	1		96	—			91.5		—		91.5
				2.2			292.3		6.6		345.5

Investments_Tables

Investments (Tables)	12 Months Ended
	Dec. 31, 2014
Investments [Abstract]
Equity Method Investments [Table Text Block]	A summary of our investments, including our approximate ownership percentage and carrying value as of December 31, 2014 and 2013, is presented below.
			Approximate		Carrying
			Ownership %		Value
		Accounting	December 31,		December 31,
		Method	2014	2013	2014		2013
					($ in millions)
	FTS International, Inc.	Equity	30%	30%	$	116	$	138
	Sundrop Fuels, Inc.	Equity	56%	56%	130		135
	Chaparral Energy, Inc.	Equity	—%	20%	—		143
	Other	—	—%	—%	19		61
	Total investments				$	265	$	477

Other_Property_and_Equipment_T

Other Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Gain (Loss) on Disposition of Property Plant Equipment [Abstract]
Property, Plant and Equipment [Table Text Block]	A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:
		December 31,						Estimated
								Useful
		2014			2013			Life
		($ in millions)						(in years)
	Buildings and improvements	$	1,242		$	1,433		Oct-39
	Natural gas compressors	551			368			20-Mar
	Land	296			212			—
	Gathering systems and treating plants	218			292			20
	Oilfield services equipment	—			2,192			15-Mar
	Other	776			898			20-Feb
	Total other property and equipment, at cost	3,083			5,395
	Less: accumulated depreciation	(804		)	(1,584		)
	Total other property and equipment, net	$	2,279		$	3,811
Property, Plant and Equipment, Schedule of Significant Acquisitions and Disposals [Table Text Block]	A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2014, 2013 and 2012 is as follows:
		Years Ended December 31,
		2014			2013			2012
		($ in millions)
	Natural gas compressors	$	(195	)	$	—		$	—
	Gathering systems and treating plants	8			(326		)	(286		)
	Oilfield services equipment	(7		)	2			10
	Buildings and land	(2		)	27			7
	Other	(3		)	(5		)	2
	Total net gains on sales of fixed assets	$	(199	)	$	(302	)	$	(267	)
Disclosure of Long Lived Assets Held-for-Sale [Table Text Block]	A summary of the assets held for sale on our consolidated balance sheets as of December 31, 2014 and 2013 is detailed below.
		December 31,
		2014			2013
		($ in millions)
	Buildings and land, net of accumulated depreciation	$	93		$	405
	Compressors, net of accumulated depreciation	—			285
	Oilfield services equipment, net of accumulated depreciation	—			29
	Gathering systems and treating plants, net of accumulated depreciation	—			11
	Property and equipment held for sale, net	$	93		$	730

Impairments_Tables

Impairments (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Impairment Charges [Abstract]
Details of Impairment of Long-Lived Assets Held and Used by Asset [Table Text Block]	A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2014, 2013 and 2012 is as follows:
		Years Ended December 31,
		2014		2013		2012
		($ in millions)
	Natural gas compressors	$	11	$	—	$	—
	Gathering systems and treating plants	13		22		6
	Oilfield services equipment	23		71		60
	Buildings and land	18		366		248
	Other	23		87		26
	Total impairments of fixed assets and other	$	88	$	546	$	340

Recovered_Sheet1

Restructuring and other Termination Benefits (Tables)	12 Months Ended
	Dec. 31, 2014
Restructuring and Related Activities [Abstract]
Restructuring and Related Costs [Table Text Block]	Below is a summary of our restructuring and other termination costs for the years ended December 31, 2014, 2013 and 2012:
			Years Ended December 31,
			2014			2013		2012
			($ in millions)
	Oilfield services spin-off costs:
	Transaction costs		$	17		$	—	$	—
	Stock-based compensation adjustments for Chesapeake employees		5			—		—
	Stock-based compensation forfeitures for SSE employees		(10		)	—		—
	Debt extinguishment costs		3			—		—
	Total oilfield services spin-off costs		15			—		—
	Restructuring charges under workforce reduction plan:
	Salary expense		—			20		—
	Acceleration of stock-based compensation		—			45		—
	Other termination benefits		—			1		—
	Total restructuring changes under workforce reduction plan		—			66		—
	Termination benefits provided to Mr. McClendon:
	Salary and bonus expense		—			11		—
	Acceleration of 2008 performance bonus clawback		—			11		—
	Acceleration of stock-based compensation		—			22		—
	Acceleration of performance share unit awards(a)		(8		)	18		—
	Estimated aircraft usage benefits		—			7		—
	Total termination benefits provided to Mr. McClendon		(8		)	69		—
	Termination benefits provided to VSP participants:
	Salary and bonus expense		—			33		1
	Acceleration of stock-based compensation		—			29		1
	Other termination benefits		—			1		—
	Total termination benefits provided to VSP participants		—			63		2
	Other termination benefits(a)		—			50		5
	Total restructuring and other termination costs		$	7		$	248	$	7
	____________________________________________
	(a)	Amounts for the year ended December 31, 2014 are primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 9.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:
		Quoted			Significant			Significant			Total
		Prices in			Other			Unobservable			Fair Value
		Active			Observable			Inputs
		Markets			Inputs			(Level 3)
		(Level 1)			(Level 2)
					($ in millions)
	As of December 31, 2014
	Derivative Assets (Liabilities):
	Commodity assets	$	—		$	785		$	205		$	990
	Commodity liabilities	—			(9		)	(259		)	(268		)
	Interest rate liabilities	—			(17		)	—			(17		)
	Foreign currency liabilities	—			(53		)	—			(53		)
	Total derivatives	$	—		$	706		$	(54	)	$	652
	As of December 31, 2013
	Derivative Assets (Liabilities):
	Commodity assets	$	—		$	25		$	15		$	40
	Commodity liabilities	—			(100		)	(493		)	(593		)
	Interest rate liabilities	—			(98		)	—			(98		)
	Foreign currency assets	—			2			—			2
	Total derivatives	$	—		$	(171	)	$	(478	)	$	(649	)
	The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2014 and 2013:
		Quoted			Significant			Significant			Total
		Prices in			Other			Unobservable			Fair Value
		Active			Observable			Inputs
		Markets			Inputs			(Level 3)
		(Level 1)			(Level 2)
					($ in millions)
	As of December 31, 2014
	Financial Assets (Liabilities):
	Other current assets	$	57		$	—		$	—		$	57
	Other current liabilities	(58		)	—			—			(58		)
	Total	$	(1	)	$	—		$	—		$	(1	)
	As of December 31, 2013
	Financial Assets (Liabilities):
	Other current assets	$	80		$	—		$	—		$	80
	Other current liabilities	(82		)	—			—			(82		)
	Total	$	(2	)	$	—		$	—		$	(2	)

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	The components of the change in our asset retirement obligations are shown below.
			Years Ended December 31,
			2014			2013
			($ in millions)
	Asset retirement obligations, beginning of period		$	405		$	375
	Additions		29			20
	Revisions(a)		101			8
	Settlements and disposals		(92		)	(20		)
	Accretion expense		22			22
	Asset retirement obligations, end of period		465			405
	Less current portion (b)		18			—
	Asset retirement obligation, long-term		$	447		$	405
	_________________________________________
	(a)	Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settlement.

Major_Customers_and_Segment_In1

Major Customers and Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	The following tables present selected financial information for Chesapeake’s operating segments:
		Exploration			Marketing,			Former			Other			Intercompany			Consolidated
		and			Gathering			Oilfield						Eliminations			Total
		Production			and			Services
					Compression
		($ in millions)
	Year Ended December 31, 2014:
	Revenues	$	8,180		$	20,790		$	1,060		$	30		$	(9,109	)	$	20,951
	Intersegment revenues	—			(8,565		)	(544		)	—			9,109			—
	Total revenues	$	8,180		$	12,225		$	516		$	30		$	—		$	20,951
	Unrealized gains on commodity derivatives	$	(1,394	)	$	—		$	—		$	—		$	—		$	(1,394	)
	Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,756		$	38		$	145		$	42		$	(66	)	$	2,915
	Impairments of fixed assets and other	$	22		$	24		$	23		$	19		$	—		$	88
	Net gains on sales of fixed assets	$	(2	)	$	(187	)	$	(8	)	$	(2	)	$	—		$	(199	)
	Interest expense	$	(709	)	$	(21	)	$	(42	)	$	3		$	680		$	(89	)
	Earnings (losses) on investments	$	2		$	—		$	(6	)	$	(76	)	$	—		$	(80	)
	Net gain (loss) on sales of investments	$	(6	)	$	—		$	—		$	73		$	—		$	67
	Losses on purchases of debt	$	(197	)	$	—		$	—		$	—		$	—		$	(197	)
	Income (Loss) Before	$	2,874		$	326		$	(16	)	$	(30	)	$	46		$	3,200
	Income Taxes
	Total Assets	$	35,381		$	1,978		$	—		$	4,283		$	(891	)	$	40,751
	Capital Expenditures	$	6,173		$	298		$	158		$	38		$	—		$	6,667
		Exploration			Marketing,			Former			Other			Intercompany			Consolidated
		and			Gathering			Oilfield						Eliminations			Total
		Production			and			Services
					Compression
		($ in millions)
	Year Ended December 31, 2013:
	Revenues	$	7,052		$	17,129		$	2,188		$	29		$	(8,892	)	$	17,506
	Intersegment revenues	—			(7,570		)	(1,309		)	(13		)	8,892			—
	Total revenues	$	7,052		$	9,559		$	879		$	16		$	—		$	17,506
	Unrealized gains on commodity derivatives	$	(228	)	$	—		$	—		$	—		$	—		$	(228	)
	Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,674		$	46		$	289		$	49		$	(155	)	$	2,903
	Impairments of fixed assets and other	$	27		$	50		$	75		$	394		$	—		$	546
	Net (gains) losses on sales of fixed assets	$	2		$	(329	)	$	(1	)	$	26		$	—		$	(302	)
	Interest expense	$	(918	)	$	(24	)	$	(82	)	$	(74	)	$	871		$	(227	)
	Earnings (losses) on investments	$	3		$	—		$	(1	)	$	(229	)	$	1		$	(226	)
	Net gain (loss) on sales of investments	$	—		$	—		$	—		$	(7	)	$	—		$	(7	)
	Losses on purchases of debt	$	(193	)	$	—		$	—		$	—		$	—		$	(193	)
	Income (Loss) Before	$	2,997		$	511		$	(51	)	$	(727	)	$	(1,288	)	$	1,442
	Income Taxes
	Total Assets	$	35,341		$	2,430		$	2,018		$	5,750		$	(3,757	)	$	41,782
	Capital Expenditures	$	6,198		$	299		$	272		$	421		$	—		$	7,190
		Exploration			Marketing,			Former			Other			Intercompany			Consolidated
		and			Gathering			Oilfield						Eliminations			Total
		Production			and			Services
					Compression
		($ in millions)
	Year Ended December 31, 2012:
	Revenues	$	6,278		$	10,895		$	1,917		$	21		$	(6,795	)	$	12,316
	Intersegment revenues	—			(5,464		)	(1,315		)	(16		)	6,795			—
	Total revenues	$	6,278		$	5,431		$	602		$	5		$	—		$	12,316
	Unrealized losses on commodity derivatives	$	(561	)	$	—		$	—		$	—		$	—		$	(561	)
	Oil, natural gas, NGL and other depreciation, depletion and amortization	$	2,624		$	54		$	232		$	46		$	(145	)	$	2,811
	Impairment of oil and natural gas properties	$	3,315		$	—		$	—		$	—		$	—		$	3,315
	Impairments of fixed assets and other	$	28		$	6		$	60		$	246		$	—		$	340
	Net (gains) losses on sales of fixed assets	$	14		$	(298	)	$	10		$	7		$	—		$	(267	)
	Interest expense	$	(47	)	$	(20	)	$	(76	)	$	(364	)	$	430		$	(77	)
	Earnings (losses) on investments	$	—		$	49		$	—		$	(152	)	$	—		$	(103	)
	Net gain (loss) on sales of investments	$	(2	)	$	1,094		$	—		$	—		$	—		$	1,092
	Losses on purchases of debt	$	(200	)	$	—		$	—		$	—		$	—		$	(200	)
	Income (Loss) Before	$	(1,798	)	$	1,665		$	112		$	(478	)	$	(475	)	$	(974	)
	Income Taxes
	Total Assets	$	37,004		$	2,291		$	2,115		$	2,529		$	(2,328	)	$	41,611
Capital Expenditures	$	12,044		$	852		$	658		$	554		$	—		$	14,108

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule of Condensed Balance Sheet [Table Text Block]	CONDENSED CONSOLIDATING BALANCE SHEET
	AS OF DECEMBER 31, 2014
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	4,100		$	2		$	84		$	(78	)	$	4,108
	Restricted cash		—			—			38			—			38
	Other		55			3,174			93			—			3,322
	Intercompany receivable, net		24,527			—			341			(24,868		)	—
	Total Current Assets		28,682			3,176			556			(24,946		)	7,468
	PROPERTY AND EQUIPMENT:
	Oil and natural gas properties, at cost based on full cost accounting, net		—			28,358			1,112			673			30,143
	Other property and equipment, net		—			2,276			3			—			2,279
	Property and equipment held for		—			93			—			—			93
	sale, net
	Total Property and Equipment,		—			30,727			1,115			673			32,515
	Net
	LONG-TERM ASSETS:
	Other assets		153			618			26			(29		)	768
	Investments in subsidiaries and		126			467			—			(593		)	—
	intercompany advances
	TOTAL ASSETS		$	28,961		$	34,988		$	1,697		$	(24,895	)	$	40,751
	CURRENT LIABILITIES:
	Current liabilities		$	792		$	5,084		$	68		$	(81	)	$	5,863
	Intercompany payable, net		—			24,937			—			(24,937		)	—
	Total Current Liabilities		792			30,021			68			(25,018		)	5,863
	LONG-TERM LIABILITIES:
	Long-term debt, net		11,154			—			—			—			11,154
	Deferred income tax liabilities		—			3,751			234			200			4,185
	Other long-term liabilities		112			1,090			142			—			1,344
	Total Long-Term Liabilities		11,266			4,841			376			200			16,683
	EQUITY:
	Chesapeake stockholders’ equity		16,903			126			1,253			(1,379		)	16,903
	Noncontrolling interests		—			—			—			1,302			1,302
	Total Equity		16,903			126			1,253			(77		)	18,205
	TOTAL LIABILITIES AND EQUITY		$	28,961		$	34,988		$	1,697		$	(24,895	)	$	40,751
	CONDENSED CONSOLIDATING BALANCE SHEET
	YEAR ENDED DECEMBER 31, 2013
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	799		$	8		$	38		$	(8	)	$	837
	Restricted cash		—			37			38			—			75
	Other		103			2,465			524			(348		)	2,744
	Intercompany receivable, net		25,549			—			860			(26,409		)	—
	Total Current Assets		26,451			2,510			1,460			(26,765		)	3,656
	PROPERTY AND EQUIPMENT:
	Oil and natural gas properties, at cost based on full cost accounting, net		—			30,933			1,471			189			32,593
	Other property and equipment, net		—			2,360			1,452			(1		)	3,811
	Property and equipment held for		—			701			29			—			730
	sale, net
	Total Property and Equipment,		—			33,994			2,952			188			37,134
	Net
	LONG-TERM ASSETS:
	Other assets		111			1,161			96			(376		)	992
	Investments in subsidiaries and		2,169			(209		)	—			(1,960		)	—
	intercompany advances
	TOTAL ASSETS		$	28,731		$	37,456		$	4,508		$	(28,913	)	$	41,782
	CURRENT LIABILITIES:
	Current liabilities		$	300		$	5,262		$	309		$	(356	)	$	5,515
	Intercompany payable, net		—			26,409			—			(26,409		)	—
	Total Current Liabilities		300			31,671			309			(26,765		)	5,515
LONG-TERM LIABILITIES:
Long-term debt, net		11,831			—			1,055			—			12,886
Deferred income tax liabilities		209			2,338			773			87			3,407
Other long-term liabilities		396			1,278			504			(344		)	1,834
Total Long-Term Liabilities		12,436			3,616			2,332			(257		)	18,127
EQUITY:
Chesapeake stockholders’ equity		15,995			2,169			1,867			(4,036		)	15,995
Noncontrolling interests		—			—			—			2,145			2,145
Total Equity		15,995			2,169			1,867			(1,891		)	18,140
TOTAL LIABILITIES AND EQUITY		$	28,731		$	37,456		$	4,508		$	(28,913	)	$	41,782
Schedule of Condensed Income Statement [Table Text Block]	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	YEAR ENDED DECEMBER 31, 2014
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	REVENUES:
	Oil, natural gas and NGL		$	—		$	7,765		$	418		$	(3	)	$	8,180
	Marketing, gathering and compression		—			12,220			5			—			12,225
	Oilfield services		—			41			983			(478		)	546
	Total Revenues		—			20,026			1,406			(481		)	20,951
	OPERATING EXPENSES:
	Oil, natural gas and NGL production		—			1,166			42			—			1,208
	Production taxes		—			227			5			—			232
	Marketing, gathering and compression		—			12,232			4			—			12,236
	Oilfield services		—			53			769			(391		)	431
	General and administrative		—			273			49			—			322
	Restructuring and other termination costs		—			4			3			—			7
	Provision for legal contingencies		100			134			—			—			234
	Oil, natural gas and NGL depreciation,		—			2,523			162			(2		)	2,683
	depletion and amortization
	Depreciation and amortization of other		—			153			143			(64		)	232
	assets
	Impairment of oil and natural gas properties		—			—			349			(349		)	—
	Impairments of fixed assets and other		—			65			23			—			88
	Net gains on sales of fixed assets		—			(192		)	(7		)	—			(199		)
	Total Operating Expenses		100			16,638			1,542			(806		)	17,474
	INCOME (LOSS) FROM OPERATIONS		(100		)	3,388			(136		)	325			3,477
	OTHER INCOME (EXPENSE):
	Interest expense		(657		)	(37		)	(42		)	647			(89		)
	Losses on investments		—			(77		)	(5		)	2			(80		)
	Net gain on sales of investments		—			67			—			—			67
	Losses on purchases of debt		(195		)	(2		)	—			—			(197		)
	Other income (expense)		502			198			(2		)	(676		)	22
	Equity in net earnings (losses) of subsidiary		2,206			(258		)	—			(1,948		)	—
	Total Other Income (Expense)		1,856			(109		)	(49		)	(1,975		)	(277		)
	INCOME (LOSS) BEFORE INCOME TAXES		1,756			3,279			(185		)	(1,650		)	3,200
	INCOME TAX EXPENSE (BENEFIT)		(161		)	1,264			(66		)	107			1,144
	NET INCOME (LOSS)		1,917			2,015			(119		)	(1,757		)	2,056
	Net income attributable to		—			—			—			(139		)	(139		)
	noncontrolling interests
	NET INCOME ATTRIBUTABLE		1,917			2,015			(119		)	(1,896		)	1,917
	TO CHESAPEAKE
	Other comprehensive income		1			18			—			—			19
	COMPREHENSIVE INCOME (LOSS)		$	1,918		$	2,033		$	(119	)	$	(1,896	)	$	1,936
	ATTRIBUTABLE TO CHESAPEAKE
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	YEAR ENDED DECEMBER 31, 2013
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	REVENUES:
	Oil, natural gas and NGL		$	—		$	6,439		$	553		$	60		$	7,052
	Marketing, gathering and compression		—			9,547			12			—			9,559
	Oilfield services		—			221			1,836			(1,162		)	895
	Total Revenues		—			16,207			2,401			(1,102		)	17,506
	OPERATING EXPENSES:
	Oil, natural gas and NGL production		—			1,112			47			—			1,159
	Production taxes		—			222			7			—			229
	Marketing, gathering and compression		—			9,455			6			—			9,461
	Oilfield services		—			239			1,434			(937		)	736
	General and administrative		—			375			83			(1		)	457
	Restructuring and other termination costs		—			244			4			—			248
Oil, natural gas and NGL depreciation,		—			2,336			253			—			2,589
depletion and amortization
Depreciation and amortization of other		—			180			281			(147		)	314
assets
Impairment of oil and natural gas		—			(2		)	313			(311		)	—
properties
Impairments of fixed assets and other		—			417			129			—			546
Net gains on sales of fixed assets		—			(301		)	(1		)	—			(302		)
Total Operating Expenses		—			14,277			2,556			(1,396		)	15,437
INCOME (LOSS) FROM OPERATIONS		—			1,930			(155		)	294			2,069
OTHER INCOME (EXPENSE):
Interest expense		(921		)	(4		)	(85		)	783			(227		)
Losses on investments		—			(225		)	(1		)	—			(226		)
Net loss on sales of investments		—			(7		)	—			—			(7		)
Losses on purchases of debt		(70		)	(123		)	—			—			(193		)
Other income		3,979			(603		)	13			(3,363		)	26
Equity in net earnings (losses) of		(1,129		)	(383		)	—			1,512			—
subsidiary
Total Other Income (Expense)		1,859			(1,345		)	(73		)	(1,068		)	(627		)
INCOME (LOSS) BEFORE INCOME TAXES		1,859			585			(228		)	(774		)	1,442
INCOME TAX EXPENSE (BENEFIT)		1,135			370			(87		)	(870		)	548
NET INCOME (LOSS)		724			215			(141		)	96			894
Net income attributable to		—			—			—			(170		)	(170		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		724			215			(141		)	(74		)	724
TO CHESAPEAKE
Other comprehensive income (loss)		3			19			(2		)	—			20
COMPREHENSIVE INCOME		$	727		$	234		$	(143	)	$	(74	)	$	744
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2012
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Oil, natural gas and NGL		$	—		$	5,920		$	351		$	7		$	6,278
Marketing, gathering and compression		—			5,218			212			1			5,431
Oilfield services		—			154			1,553			(1,100		)	607
Total Revenues		—			11,292			2,116			(1,092		)	12,316
OPERATING EXPENSES:
Oil, natural gas and NGL production		—			1,278			26			—			1,304
Production taxes		—			182			6			—			188
Marketing, gathering and compression		—			5,197			115			—			5,312
Oilfield services		—			301			1,096			(932		)	465
General and administrative		—			431			105			(1		)	535
Restructuring and other termination costs		—			5			2			—			7
Oil, natural gas and NGL depreciation,		—			2,353			154			—			2,507
depletion and amortization
Depreciation and amortization of other		—			187			266			(149		)	304
assets
Impairment of oil and natural gas properties		—			3,192			123			—			3,315
Impairments of fixed assets and other		—			275			65			—			340
Net gains (losses) on sales of fixed assets		—			(269		)	2			—			(267		)
Total Operating Expenses		—			13,132			1,960			(1,082		)	14,010
INCOME (LOSS) FROM OPERATIONS		—			(1,840		)	156			(10		)	(1,694		)
OTHER INCOME (EXPENSE):
Interest expense		(879		)	45			(84		)	841			(77		)
Losses on investments		—			(167		)	55			9			(103		)
Net gain on sales of investments		—			29			1,063			—			1,092
Losses on purchases of debt		(200		)	—			—			—			(200		)
Other income (loss)		819			203			14			(1,028		)	8
Equity in net earnings (losses) of subsidiary		(610		)	436			—			174			—
Total Other Income (Expense)		(870		)	546			1,048			(4		)	720
INCOME (LOSS) BEFORE INCOME TAXES		(870		)	(1,294		)	1,204			(14		)	(974		)
INCOME TAX EXPENSE (BENEFIT)		(101		)	(675		)	470			(74		)	(380		)
NET INCOME (LOSS)		(769		)	(619		)	734			60			(594		)
Net income attributable to		—			—			—			(175		)	(175		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		(769		)	(619		)	734			(115		)	(769		)
TO CHESAPEAKE
Other comprehensive income (loss)		6			(22		)	—			—			(16		)
COMPREHENSIVE INCOME		$	(763	)	$	(641	)	$	734		$	(115	)	$	(785	)
ATTRIBUTABLE TO CHESAPEAKE
Schedule of Condensed Cash Flow Statement [Table Text Block]	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	YEAR ENDED DECEMBER 31, 2014
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	CASH FLOWS FROM OPERATING		$	—		$	4,201		$	462		$	(29	)	$	4,634
	ACTIVITIES
	CASH FLOWS FROM INVESTING
	ACTIVITIES:
	Drilling and completion costs		—			(4,445		)	(136		)	—			(4,581		)
	Acquisitions of proved and unproved properties		—			(1,306		)	(5		)	—			(1,311		)
	Proceeds from divestitures of proved and unproved properties		—			5,812			1			—			5,813
	Additions to other property and equipment		—			(480		)	(246		)	—			(726		)
	Other investing activities		—			1,199			60			—			1,259
	Net Cash Provided By (Used In) Investing Activities		—			780			(326		)	—			454
	CASH FLOWS FROM FINANCING
	ACTIVITIES:
	Proceeds from credit facilities borrowings		—			6,689			717			—			7,406
	Payments on credit facilities borrowings		—			(6,689		)	(1,099		)	—			(7,788		)
	Proceeds from issuance of senior notes, net of discount and offering costs		2,966			—			494			—			3,460
	Proceeds from issuance of term loans, net of discount and offering costs		—			—			394			—			394
	Cash paid to purchase debt		(3,362		)	—			—			—			(3,362		)
	Other financing activities		(439		)	(1,278		)	(169		)	(41		)	(1,927		)
	Intercompany advances, net		4,136			(3,709		)	(427		)	—			—
	Net Cash Provided By (Used In)		3,301			(4,987		)	(90		)	(41		)	(1,817		)
	Financing Activities
	Net increase (decrease) in cash and cash		3,301			(6		)	46			(70		)	3,271
	equivalents
	Cash and cash equivalents, beginning of		799			8			38			(8		)	837
	period
	Cash and cash equivalents, end of period		$	4,100		$	2		$	84		$	(78	)	$	4,108
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	YEAR ENDED DECEMBER 31, 2013
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	CASH FLOWS FROM OPERATING		$	—		$	4,218		$	439		$	(43	)	$	4,614
	ACTIVITIES
	CASH FLOWS FROM INVESTING
	ACTIVITIES:
	Drilling and completion costs		—			(4,838		)	(766		)	—			(5,604		)
	Acquisitions of proved and unproved properties		—			(1,378		)	346			—			(1,032		)
	Proceeds from divestitures of proved and unproved properties		—			3,466			1			—			3,467
	Additions to other property and equipment		—			(271		)	(701		)	—			(972		)
	Other investing activities		—			246			765			163			1,174
	Net Cash Provided By (Used In) Investing Activities		—			(2,775		)	(355		)	163			(2,967		)
	CASH FLOWS FROM FINANCING
	ACTIVITIES:
	Proceeds from credit facilities borrowings		—			6,452			1,217			—			7,669
	Payments on credit facilities borrowings		—			(6,452		)	(1,230		)	—			(7,682		)
	Proceeds from issuance of senior notes, net of discount and offering costs		2,274			—			—			—			2,274
	Cash paid to purchase debt		(2,141		)	—			—			—			(2,141		)
	Proceeds from sales of noncontrolling interests		—			—			6			—			6
	Other financing activities		1,819			(2,897		)	(17		)	(128		)	(1,223		)
	Intercompany advances, net		(1,381		)	1,462			(81		)	—			—
	Net Cash Provided By (Used		571			(1,435		)	(105		)	(128		)	(1,097		)
	In) Financing Activities
	Net increase (decrease) in cash and cash		571			8			(21		)	(8		)	550
	equivalents
	Cash and cash equivalents, beginning of		228			—			59			—			287
	period
	Cash and cash equivalents, end of period		$	799		$	8		$	38		$	(8	)	$	837
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2012
($ in millions)
		Parent(a)			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries(a)			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING		$	—		$	1,711		$	1,182		$	(56	)	$	2,837
ACTIVITIES
CASH FLOWS FROM INVESTING
ACTIVITIES:
Drilling and completion costs		—			(8,605		)	(325		)	—			(8,930		)
Acquisitions of proved and unproved properties		—			(3,622		)	461			—			(3,161		)
Proceeds from divestitures of proved and unproved properties		—			5,884			—			—			5,884
Additions to other property and equipment		—			(1,736		)	(915		)	—			(2,651		)
Other investing activities		—			5,083			(316		)	(893		)	3,874
Net Cash Used In Investing		—			(2,996		)	(1,095		)	(893		)	(4,984		)
Activities
CASH FLOWS FROM FINANCING
ACTIVITIES:
Proceeds from credit facilities borrowings		—			18,930			1,388			—			20,318
Payments on credit facilities borrowings		—			(20,651		)	(999		)	—			(21,650		)
Proceeds from issuance of senior notes, net of discount and offering costs		1,263			—			—			—			1,263
Proceeds from issuance of term loans, net of discount and offering costs		5,722			—			—			—			5,722
Cash paid to purchase debt		(4,000		)	—			—			—			(4,000		)
Proceeds from sales of noncontrolling interests		—			63			1,014			—			1,077
Other financing activities		(477		)	(299		)	(820		)	949			(647		)
Intercompany advances, net		(2,282		)	3,242			(960		)	—			—
Net Cash Provided By (Used		226			1,285			(377		)	949			2,083
In) Financing Activities
Net increase (decrease) in cash and cash		226			—			(290		)	—			(64		)
equivalents
Cash and cash equivalents, beginning of		2			—			349			—			351
period
Cash and cash equivalents, end of period		$	228		$	—		$	59		$	—		$	287
___________________________________________
(a)	We have revised the amounts presented as cash and cash equivalents in the Guarantor Subsidiaries and Parent columns to properly reflect the cash of the Parent. As of December 31, 2012, $228 million was incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.

Basis_of_Presentation_and_Summ3

Basis of Presentation and Summary of Significant Accounting Policies - Receivables Table (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Accounts, Notes, Loans and Financing Receivable [Line Items]
Other Receivables	$226	$150
Oil and Gas Joint Interest Billing Receivables, Current	691	417
Accounts Receivable, Related Parties	0	62
Allowance for Doubtful Accounts Receivable	-21	-18
Accounts receivable, net	2,236	2,222
Oil And Gas Exploration And Production [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Other Receivables	1,340	1,548
Oilfield Services [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Other Receivables	$0	$63

Basis_of_Presentation_and_Summ4

Basis of Presentation and Summary of Significant Accounting Policies - Unproved Properties Excluded From Amortization Table (Details) (USD $)	12 Months Ended			170 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]
Acquisition Costs, Period Cost	$577	$199	$1,462	$5,149
Acquisition Costs, Cumulative	7,387
Exploration Costs, Period Cost	340	90	244	42
Exploration Costs, Cumulative	716
Capitalized Interest of Unproved Properties Excluded from Amortization	492	421	325	447
Capitalized Interest Of Unproved Properties Excluded From Amortization Cumulative	1,685
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	1,409	710	2,031	5,638
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative	$9,788	$12,013

Basis_of_Presentation_and_Summ5

Basis of Presentation and Summary of Significant Accounting Policies - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary of Significant Accounting Policies Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	50.00%
Provision for Doubtful Accounts	$2	$2	$0
Premiums Receivable, Allowance for Doubtful Accounts, Write Offs Against Allowance		3
Percentage of Reserve Estimates (by Volume) Prepared by Independent Engineering Firm	79.00%
Goodwill	15	43
Bank Overdrafts	333	397
Unamortized Debt Issuance Expense	130	145
Gas Balancing Asset (Liability)	12	11
Director [Member]
Summary of Significant Accounting Policies Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Minimum [Member] | Employee [Member]
Summary of Significant Accounting Policies Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Maximum [Member] | Employee [Member]
Summary of Significant Accounting Policies Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	4 years
Horizon Drilling Services [Member]
Summary of Significant Accounting Policies Line Items]
Goodwill	15
Bronco Drilling Company Incorporated [Member]
Summary of Significant Accounting Policies Line Items]
Goodwill		$28

Earnings_Per_Share_Antidilutiv

Earnings Per Share - Antidilutive Securities Excluded from Computation of EPS Table (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Earnings Per Share, Basic	$1.93	$0.73	($1.46)
Earnings Per Share, Diluted	$1.87	$0.73	($1.46)
Weighted Average Number of Shares Outstanding, Basic	659	653	643
Weighted Average Number of Shares Outstanding, Diluted	772	653	643
5.75% Cumulative Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments		$86	$86
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		56	56
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments		63	63
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		40	39
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments		10	10
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		5	5
4.50% Cumulative Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments		12	12
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		6	6
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$22	$10	$0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	3	5	5

Earnings_Per_Share_Earnings_Pe

Earnings Per Share Earnings Per Share - Reconciliation of Basic and Diluted EPS Table (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	$1,273	$474	($940)
Weighted Average Number of Shares Outstanding, Basic	659	653	643
Earnings Per Share, Basic	$1.93	$0.73	($1.46)
Net Income (Loss) Available to Common Stockholders, Diluted	1,444
Weighted Average Number of Shares Outstanding, Diluted	772	653	643
Earnings Per Share, Diluted	$1.87	$0.73	($1.46)
Convertible Debt Securities [Member] | 5.75% Cumulative Convertible Preferred Stock [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	86
Weighted Average Number Diluted Shares Outstanding Adjustment	59
Convertible Debt Securities [Member] | 5.75% Cumulative Convertible Preferred Stock Series A [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	63
Weighted Average Number Diluted Shares Outstanding Adjustment	42
Convertible Debt Securities [Member] | 5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	10
Weighted Average Number Diluted Shares Outstanding Adjustment	6
Convertible Debt Securities [Member] | 4.50% Cumulative Convertible Preferred Stock [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities	$12
Weighted Average Number Diluted Shares Outstanding Adjustment	6

Debt_LongTerm_Debt_Table_Detai

Debt - Long-Term Debt Table (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Apr. 24, 2014	Dec. 31, 2006
	Day
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$11,756
Debt Instrument, Unamortized Discount	-231	-357
Long-term Debt	11,535	12,886
Long-term Debt, Current Maturities	-381	0
Long-term debt, net	11,154	12,886
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	100.00%
Percentage Of Principal Amount Of Notes For Repurchase Requirement Of Contingent Convertible Senior Notes	100.00%
Debt Instrument, Convertible, Terms of Conversion Feature	5
Credit Facility Commitment Period	10 years
Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0
Interest Rate Contract [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	10	13
2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Common Stock Price Conversion Thresholds	$45.14
Debt Instrument, Date of First Required Payment	14-May-16
2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Common Stock Price Conversion Thresholds	$59.71
Debt Instrument, Date of First Required Payment	14-Nov-17
2.25% Contingent Convertible Senior Notes Due 2038 [Member]
Long-Term Debt Instrument [Line Items]
Common Stock Price Conversion Thresholds	$100.35
Debt Instrument, Date of First Required Payment	14-Jun-19
Unsecured Debt [Member] | Senior Unsecured Term Loan Due 2017 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	2,000
Debt Instrument, Unamortized Discount		-33
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	3,000		3,000
Debt Instrument, Unamortized Discount	-224	-303
Senior Notes [Member] | Debt Instrument, Redemption, Period One [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	5 years
Senior Notes [Member] | Debt Instrument, Redemption, Period Two [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	10 years
Senior Notes [Member] | Debt Instrument, Redemption, Period Three [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	15 years
Senior Notes [Member] | Debt Instrument, Redemption, Period Four [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	20 years
Senior Notes [Member] | 9.5% Senior Notes Due 2015 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	1,265
Debt Instrument, Interest Rate, Stated Percentage	9.50%
Senior Notes [Member] | 3.25% Senior Notes due 2016 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	500	500
Debt Instrument, Interest Rate, Stated Percentage	3.25%	3.25%
Senior Notes [Member] | 6.25% Euro-Denominated Senior Notes Due 2017 [ Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	416	473		344
Senior Notes [Member] | 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Cross Currency Interest Rate Contract [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	416
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Derivative, Forward Exchange Rate	1.2098	1.3743		1.3325
Senior Notes [Member] | 6.5% Senior Notes Due 2017 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	660	660
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Senior Notes [Member] | 6.875% Senior Notes Due 2018 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	97
Debt Instrument, Interest Rate, Stated Percentage	6.88%	6.88%
Senior Notes [Member] | 7.25% Senior Notes Due 2018 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	669	669
Debt Instrument, Interest Rate, Stated Percentage	7.25%
Senior Notes [Member] | Floating Rate Senior Notes due 2019 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,500	0
Senior Notes [Member] | 6.625% Senior Notes Due 2019 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	650
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Senior Notes [Member] | 6.625% Senior Notes Due 2020 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,300	1,300
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Senior Notes [Member] | 6.875% Senior Notes Due 2020 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	500	500
Debt Instrument, Interest Rate, Stated Percentage	6.88%
Senior Notes [Member] | 6.125% Senior Notes Due 2021 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,000	1,000
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	700	700
Debt Instrument, Interest Rate, Stated Percentage	5.38%	5.38%
Senior Notes [Member] | 4.875% Senior Notes due 2022 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,500	0
Debt Instrument, Interest Rate, Stated Percentage	4.88%
Senior Notes [Member] | 5.75% Senior Notes due 2023 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,100	1,100
Debt Instrument, Interest Rate, Stated Percentage	5.75%	5.75%
Senior Notes [Member] | 2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	396	396
Debt Instrument, Unamortized Discount	-15
Debt Instrument, Interest Rate, Stated Percentage	2.75%
Senior Notes [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,168	1,168
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Senior Notes [Member] | 2.25% Contingent Convertible Senior Notes Due 2038 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	347	347
Debt Instrument, Interest Rate, Stated Percentage	2.25%
Line of Credit [Member] | Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	0
Line of Credit [Member] | Oilfield Services Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$0	$405

Debt_Long_Term_Debt_Table_Phan

Debt - Long Term Debt Table (Phantom) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Senior Unsecured Term Loan Due 2017 [Member] | Unsecured Debt [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument Maturity Date	2-Dec-17
9.5% Senior Notes Due 2015 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	9.50%
Debt Instrument Maturity Date	15-Feb-15
3.25% Senior Notes due 2016 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%	3.25%
Debt Instrument Maturity Date	15-Mar-16
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member] | Cross Currency Interest Rate Contract [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Debt Instrument Maturity Date	15-Jan-17
6.5% Senior Notes Due 2017 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument Maturity Date	15-Aug-17
6.875% Senior Notes Due 2018 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.88%	6.88%
Debt Instrument Maturity Date	18-Aug-18
7.25% Senior Notes Due 2018 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.25%
Debt Instrument Maturity Date	15-Dec-18
Floating Rate Senior Notes due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument Maturity Date	15-Apr-19
6.625% Senior Notes Due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Debt Instrument Maturity Date	15-Nov-19
6.625% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Debt Instrument Maturity Date	15-Aug-20
6.875% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.88%
Debt Instrument Maturity Date	15-Nov-20
5.375% Senior Notes due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.38%	5.38%
Debt Instrument Maturity Date	15-Jun-21
6.125% Senior Notes Due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument Maturity Date	15-Feb-21
4.875% Senior Notes due 2022 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.88%
Debt Instrument Maturity Date	15-Apr-22
5.75% Senior Notes due 2023 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.75%	5.75%
Debt Instrument Maturity Date	15-Mar-23
2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instruments Convertible Optional Repurchase Dates	November 15, 2015, 2020, 2025, 2030
2.75% Contingent Convertible Senior Notes Due 2035 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.75%
Debt Instrument Maturity Date	15-Nov-35
2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instruments Convertible Optional Repurchase Dates	May 15, 2017, 2022, 2027, 2032
2.5% Contingent Convertible Senior Notes due 2037 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument Maturity Date	17-May-37
2.25% Contingent Convertible Senior Notes Due 2038 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instruments Convertible Optional Repurchase Dates	December 15, 2018, 2023, 2028, 2033
2.25% Contingent Convertible Senior Notes Due 2038 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.25%
Debt Instrument Maturity Date	15-Dec-38

Debt_Schedule_of_Debt_Maturiti

Debt - Schedule of Debt Maturities Table (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Debt Disclosure [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$396
Long-term Debt, Maturities, Repayments of Principal in Year Two	500
Long-term Debt, Maturities, Repayments of Principal in Year Three	2,244
Long-term Debt, Maturities, Repayments of Principal in Year Four	1,016
Long-term Debt, Maturities, Repayments of Principal in Year Five	1,500
Long-term Debt, Maturities, Repayments of Principal after Year Five	6,100
Long-term Debt, Gross	$11,756

Debt_Term_Loans_Narrative_Deta

Debt - Term Loans Narrative (Details) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Nov. 07, 2012	Apr. 24, 2014
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$11,756,000,000
Gains (Losses) on Extinguishment of Debt	-63,000,000	-40,000,000	-200,000,000
Unsecured Debt [Member]
Long-Term Debt Instrument [Line Items]
Commitment Period				5 years
Unsecured Debt					2,000,000,000
Proceeds from Issuance of Unsecured Debt				1,935,000,000
Gains (Losses) on Extinguishment of Debt	90,000,000
Unsecured Debt [Member] | Premium on Extinguishment of Term Loan Debt [Member]
Long-Term Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt	40,000,000
Unsecured Debt [Member] | Unamortized Discount on Extinguishment of Term Loan Debt [Member]
Long-Term Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt	30,000,000
Unsecured Debt [Member] | Unamortized Deferred Charges on Extinguishment of Term Loan Debt [Member]
Long-Term Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt	20,000,000
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$3,000,000,000					$3,000,000,000

Debt_Senior_Notes_and_Continge

Debt - Senior Notes and Contingent Convertible Senior Notes Purchased Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Apr. 24, 2014
Long-Term Debt Instrument [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	50.00%
Long-term Debt, Gross	$11,756,000,000
Proceeds from issuance of senior notes, net of discount and offering costs	3,460,000,000
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	100.00%
Long-term Debt, Gross	3,000,000,000		3,000,000,000
Debt Instrument, Face Amount		2,300,000,000
Proceeds from issuance of senior notes, net of discount and offering costs	2,966,000,000	2,274,000,000
Debt Instrument, Repurchase Amount		405,000,000
Gain (Loss) on Repurchase of Debt Instrument		37,000,000
Senior Notes [Member] | Premium on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		32,000,000
Senior Notes [Member] | Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		5,000,000
Minimum [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	50,000,000
Maximum [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	75,000,000
2.5% Contingent Convertible Senior Notes due 2037 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,168,000,000	1,168,000,000
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument, Interest Rate, Effective Percentage	8.00%
2.75% Contingent Convertible Senior Notes Due 2035 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	396,000,000	396,000,000
Debt Instrument, Interest Rate, Stated Percentage	2.75%
Debt Instrument, Interest Rate, Effective Percentage	6.86%
2.25% Contingent Convertible Senior Notes Due 2038 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	347,000,000	347,000,000
Debt Instrument, Interest Rate, Stated Percentage	2.25%
Debt Instrument, Interest Rate, Effective Percentage	8.00%
Floating Rate Senior Notes due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,500,000,000	0
4.875% Senior Notes due 2022 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,500,000,000	0
Debt Instrument, Interest Rate, Stated Percentage	4.88%
3.25% Senior Notes due 2016 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	500,000,000	500,000,000
Debt Instrument, Interest Rate, Stated Percentage	3.25%	3.25%
5.375% Senior Notes due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	700,000,000	700,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.38%	5.38%
5.75% Senior Notes due 2023 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	1,100,000,000	1,100,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.75%	5.75%
7.625% Senior Notes Due 2013 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		247,000,000
Debt Instrument, Interest Rate, Stated Percentage		7.63%
Debt Instrument, Repurchase Amount		221,000,000
Debt Instrument, Repurchased Face Amount		217,000,000
6.875% Senior Notes Due 2018 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	97,000,000
Debt Instrument, Interest Rate, Stated Percentage	6.88%	6.88%
Debt Instrument, Repurchased Face Amount	97,000,000	377,000,000
Gain (Loss) on Repurchase of Debt Instrument	6,000,000
6.875% Senior Notes Due 2018 [Member] | Senior Notes [Member] | Premium on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument	5,000,000
6.875% Senior Notes Due 2018 [Member] | Senior Notes [Member] | Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument	1,000,000
9.5% Senior Notes Due 2015 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0	1,265,000,000
Debt Instrument, Interest Rate, Stated Percentage	9.50%
Debt Instrument, Repurchased Face Amount	1,265,000,000	1,454,000,000
Gain (Loss) on Repurchase of Debt Instrument	99,000,000
9.5% Senior Notes Due 2015 [Member] | Senior Notes [Member] | Premium on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument	87,000,000
9.5% Senior Notes Due 2015 [Member] | Senior Notes [Member] | Unamortized Discount on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument	9,000,000
9.5% Senior Notes Due 2015 [Member] | Senior Notes [Member] | Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument	3,000,000
6.775% Senior Notes Due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.78%
Prejudgment Interest Statutory Rate	9.00%
Debt Instrument, Repurchased Face Amount		1,300,000,000
Gain (Loss) on Repurchase of Debt Instrument		33,000,000
6.775% Senior Notes Due 2019 [Member] | Senior Notes [Member] | Unamortized Discount on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		14,000,000
6.775% Senior Notes Due 2019 [Member] | Senior Notes [Member] | Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		$19,000,000

Debt_Revolving_Credit_Facility

Debt - Revolving Credit Facility Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015
	extension
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$11,756,000,000
Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Borrowing capacity	4,000,000,000
Line of Credit Facility, Increase (Decrease), Net	1,000,000,000
Line of Credit Facility, Number of Expiration Period Options	2
Line of Credit Facility, Expiration Period Option	1 year
Long-term Debt, Gross	0
Commitment Period	5 years
Letters of Credit Outstanding, Amount	$15,000,000
Interest Rate In Addition To Federal Funds Rate	0.50%
Loans Receivable, Basis Spread on Variable Rate	1.00%
Debt Instrument, Covenant Description	4.0 to 1.0
Line of Credit Facility, Guarantee Event One	cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $125 million or more
Line of Credit Facility, Guarantee Event Two	bankruptcy; judgments involving liability of $125 million or more that are not paid
Line of Credit Facility, Guarantee Event Three	ERISA events
Revolving Credit Facility [Member] | Alternatiove Base Rate (ABR) [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End	0.63%
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End	1.63%
Revolving Credit Facility [Member] | Maximum [Member]
Long-Term Debt Instrument [Line Items]
Ratio of Indebtedness to Net Capital	65
Revolving Credit Facility [Member] | Scenario, Forecast [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument Maturity Date		15-Dec-19
Revolving Credit Facility [Member] | Moody's, Ba3 Rating [Member] | Minimum [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Credit Rating	Ba3
Revolving Credit Facility [Member] | Standard & Poor's, BB- Rating [Member] | Minimum [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Credit Rating	BB-

Debt_SpinOff_Debt_Transactions

Debt - Spin-Off Debt Transactions (Details) (USD $)	12 Months Ended	6 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013	Apr. 24, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross	$11,756
Credit Facility Commitment Period	10 years
Proceeds from issuance of senior notes, net of discount and offering costs	3,460
Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Commitment Period		7 years
Seven Seven Energy Inc. Revolving Bank Credit Facility [Member] | Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Borrowing capacity		275
Payments of Financing Costs		3
Commitment Period		5 years
Secured Debt [Member] | Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross		400
Proceeds from Issuance of Secured Debt		394
Senior Notes [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross	3,000			3,000
Proceeds from issuance of senior notes, net of discount and offering costs	2,966		2,274
6.5% Senior Notes Due 2022 [Member] | Senior Notes [Member] | Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross		500
Debt Instrument, Interest Rate, Stated Percentage		6.50%
Proceeds from issuance of senior notes, net of discount and offering costs		494
General Partner Distributions		391

Debt_Fair_Value_of_Other_Finan

Debt - Fair Value of Other Financial Instruments (Table) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt, net	$11,535	$12,886
Reported Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt, net	11,525	10,501
Reported Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt, net	0	2,372
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt, net	12,052	11,557
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt, net	$0	$2,369

Contingencies_Narrative_Detail

Contingencies - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Loss Contingencies [Line Items]
Provision for legal contingencies	$234	$0	$0
Redemption of 2019 Notes [Member]
Loss Contingencies [Line Items]
Provision for legal contingencies	100
Redemption of 2019 Notes [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Provision for legal contingencies	100
Redemption of 2019 Notes [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Provision for legal contingencies	380
Settled Litigation [Member]
Loss Contingencies [Line Items]
Provision for legal contingencies	$119
Senior Notes [Member] | 6.775% Senior Notes Due 2019 [Member]
Loss Contingencies [Line Items]
Prejudgment Interest Statutory Rate	9.00%

Commitments_Undiscounted_Lease

Commitments - Undiscounted Lease Payments Table (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$5
Operating Leases, Future Minimum Payments, Due in Two Years	4
Operating Leases, Future Minimum Payments, Due in Three Years	1
Operating Leases, Future Minimum Payments, Due in Four Years	1
Future Minimum Payments Due	$11

Commitments_Undiscounted_Gathe

Commitments - Undiscounted Gathering Processing and Transportation Agreements Commitments Table (Details) (Gathering and Processing Equipment [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Gathering and Processing Equipment [Member]
Other Commitments [Line Items]
Gathering, Processing and Transportation Commitment, Due in Next Twelve Months	$1,855
Gathering, Processing and Transportation Commitment, Due in Second Year	1,987
Gathering, Processing and Transportation Commitment, Due in Third Year	2,003
Gathering, Processing and Transportation Commitment, Due in Fourth Year	1,802
Gathering, Processing and TransportationCommitment, Due in Fifth Year	1,516
Gathering, Processing and Transportation Commitment, Due after Fifth Year	6,880
Gathering, Processing and Transportation Commitment	$16,043

Commitments_Undiscounted_Drill

Commitments - Undiscounted Drilling Contracts Commitments Table (Details) (Drilling Rig Leases [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Drilling Rig Leases [Member]
Drilling Contracts [Line Items]
Drilling Contracts Obligation, Due in Next Twelve Months	$232
Drilling Contracts Obligation, Due in Second Year	179
Drilling Contracts Obligation, Due in Third Year	91
Drilling Contracts Obligation	$502

Commitments_Undiscounted_Press

Commitments - Undiscounted Pressure Pumping Contracts Commitments (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Other Commitments [Line Items]
Pressure Pumping Contracts, Future Minimum Payments Due, Next Twelve Months	$5
Pressure Pumping Contracts, Future Minimum Payments, Due in Two Years	4
Pressure Pumping Contracts, Future Minimum Payments, Due in Three Years	1
Future Minimum Payments Due	11
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member]
Other Commitments [Line Items]
Pressure Pumping Contracts, Future Minimum Payments Due, Next Twelve Months	245
Pressure Pumping Contracts, Future Minimum Payments, Due in Two Years	162
Pressure Pumping Contracts, Future Minimum Payments, Due in Three Years	59
Future Minimum Payments Due	$466

Commitments_Narrative_Details

Commitments - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 20, 2011
Long-term Purchase Commitment [Line Items]
Operating Leases, Rent Expense	$33	$158	$185
Gathering Fee Escalation Rate	15.00%
Investments	265	477
Sundrop Fuels Inc [Member]
Long-term Purchase Commitment [Line Items]
Marketable Securities, Equity Securities	25
Investments	155			155
Net Acreage Maintenance Commitment [Member]
Long-term Purchase Commitment [Line Items]
Cash Payment for Shortfall	$50
Net Acreage Shortfall [Member]
Long-term Purchase Commitment [Line Items]
Number Of Net Acres	20,800
Drilling Rig Leases [Member] | Minimum [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 months
Drilling Rig Leases [Member] | Maximum [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 years
Drilling Rig Leases [Member] | Seven Seven Energy Inc. [Member] | Minimum [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 months
Drilling Rig Leases [Member] | Seven Seven Energy Inc. [Member] | Maximum [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 years
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Percent of Total	50.00%
Pressure Pumping Leases [Member] | Pressure Pumping Crew Year One of Agreement [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews	7
Year of Service Agreement	1 year
Pressure Pumping Leases [Member] | Pressure Pumping Crew Year Two of Agreement [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews	5
Year of Service Agreement	2 years
Pressure Pumping Leases [Member] | Pressure Pumping Crew Year Three of Agreement [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews	3
Year of Service Agreement	3 years

Other_Liabilities_Current_Tabl

Other Liabilities - Current Table (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Other Liabilities Disclosure [Abstract]
Revenues and royalties due others	$1,176	$1,409
Accrued natural gas, oil and NGL drilling and production costs	385	457
Joint interest prepayments received	189	464
Accrued compensation and benefits	344	320
Other accrued taxes	55	161
Accrued dividends	101	101
Other	811	599
Total other current liabilities	$3,061	$3,511

Other_Liabilities_LongTerm_Tab

Other Liabilities - Long-Term Table (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Other Long-Term Liabilities [Line Items]
Financing obligations	$30	$31
Unrecognized Tax Benefits	303	644	599	369
Other	249	237
Other Liabilities, Current	3,061	3,511
Total other long-term liabilities	679	984
Other Noncurrent Liabilities [Member]
Other Long-Term Liabilities [Line Items]
Unrecognized Tax Benefits	45	317
Noncontrolling Interest, Chesapeake Utica L L C [Member]
Other Long-Term Liabilities [Line Items]
Conveyance Obligation Noncurrent	220	250
Other Liabilities, Current	14	13
Total other long-term liabilities	234	263
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]
Other Long-Term Liabilities [Line Items]
Conveyance Obligation Noncurrent	135	149
Other Liabilities, Current	23	12
Total other long-term liabilities	$158	$161

Income_Taxes_Income_Tax_Expens

Income Taxes - Income Tax Expense Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Current Federal Tax Expense (Benefit)	$0	$0	$0
Current State and Local Tax Expense (Benefit)	47	22	47
Current income taxes	47	22	47
Deferred Federal Income Tax Expense (Benefit)	1,115	502	-358
Deferred State and Local Income Tax Expense (Benefit)	-18	24	-69
Deferred income taxes	1,097	526	-427
INCOME TAX EXPENSE (BENEFIT)	$1,144	$548	($380)

Income_Taxes_Effective_Income_

Income Taxes - Effective Income Tax Rate Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	$1,120	$505	($341)
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	68	88	-38
Effective Income Tax Rate Reconciliation, Deferred Remeasurement	-114	-38	-19
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	74	-12	0
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	-4	5	18
INCOME TAX EXPENSE (BENEFIT)	$1,144	$548	($380)

Income_Taxes_Deferred_Tax_Asse

Income Taxes - Deferred Tax Assets and Liabilities Table (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Income Tax Disclosure [Abstract]
Deferred Tax Liabilities, Other Finite-Lived Assets	($3,950)	($2,631)
Deferred Tax Liabilities, Property, Plant and Equipment	-14	-371
Deferred Tax Liabilities, Deferred Expense, Other Capitalized Costs	-920	-1,216
Deferred Tax Liabilities, Deferred Expense, Deferred Financing Costs	-443	-439
Deferred Tax Liabilities, Tax Deferred Income	-102	0
Deferred Tax Liabilities, Derivatives	-428	0
Deferred Tax Liabilities, Gross	-5,857	-4,657
Deferred Tax Assets, Operating Loss Carryforwards	945	535
Deferred Tax Assets, Derivative Instruments	0	108
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Asset Retirement Obligations	165	153
Deferred Tax Assets, Investments	88	130
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	50	66
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	214	120
Deferred Tax Assets, Investment in Subsidiaries	135	152
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	34	317
Deferred Tax Assets, Other	56	40
Deferred Tax Assets, Gross	1,687	1,621
Deferred Tax Assets, Valuation Allowance	-222	-148
Deferred Tax Assets, Net of Valuation Allowance	1,465	1,473
Deferred income tax asset	0	223
Deferred Tax Liabilities, Net, Current	-207	0
Deferred Tax Liabilities, Net, Noncurrent	-4,185	-3,407
Deferred Tax Liabilities, Net	$4,392	$3,184

Income_Taxes_Unrecognized_Tax_

Income Taxes - Unrecognized Tax Benefits Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Period Start	$644	$599	$369
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	13	15	134
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	0	30	96
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	-354	0	0
Unrecognized Tax Benefits, Period End	$303	$644	$599

Income_Taxes_Narrative_Details

Income Taxes - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes Summary [Line Items]
Effective Income Tax Rate Reconciliation, Deferred Remeasurement	($114)	($38)	($19)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	74	-12	0
Deferred income tax asset	0	223
Deferred income tax liabilities	4,185	3,407
Deferred Tax Assets, Gross	1,687	1,621
Deferred Tax Assets, Valuation Allowance	222	148
Treasury Regulations Purchase of Stock	5.00%
Percentage Of Beneficial Interest Owned	50.00%
Unrecognized Tax Benefits	303	644	599	369
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	5	13
Federal Jurisdiction [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	1,600
State and Local Jurisdiction [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	8,300
Tax Credit Carryforward, Deferred Tax Asset	551	394
Unrecognized Tax Benefits	17	4
Alternative Minimum Tax [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	76
Unrecognized Tax Benefits	23
Windfall [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	$18

Related_Party_Transactions_Equ

Related Party Transactions - Equity Method Investees Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	$0	$47	$67
Related Party Transaction, Due from (to) Related Party	0	1	42
FTS International, Inc. [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	0	0	73
Payment For Transaction with Related Party	220	397	480
Twin Eagle Resource Management Llc [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	$0	$666	$392
Equity Method Investment, Ownership Percentage		30.00%

Equity_Common_Stock_Table_Deta

Equity - Common Stock Table (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Issued Beginning of Period	666,192,371	666,468,000	660,888,000
Stock Issued During Period, Shares, Restricted Stock Award, Net of Forfeitures	-2,529,000	-599,000	5,038,000
Stock option exercises	1,281,000	323,000	542,000
Common Stock, Shares, Issued End of Period	664,944,232	666,192,371	666,468,000

Equity_Preferred_Stock_Convers

Equity - Preferred Stock Conversion Terms Table (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
5.75% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Preferred Stock, Liquidation Preference Per Share	$1,000,000	$1,000,000
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Preferred Stock, Liquidation Preference Per Share	$1,000,000	$1,000,000
4.50% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Preferred Stock, Liquidation Preference Per Share	$100,000	$100,000
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Preferred Stock, Liquidation Preference Per Share	$100,000	$100,000
Preferred Stock [Member] | 5.75% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Stock Issue Date	May and June 2010
Preferred Stock, Liquidation Preference Per Share	$1,000
Conversion of Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	39.59%
Conversion of Stock, Conversion Price	$25.26
Conversion of Stock, Company Conversion Right, Date	17-May-15
Trigger Price For Time Period	$32.84
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Preferred Stock [Member] | 5.75% Cumulative Convertible Preferred Stock Series A [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Stock Issue Date	May-10
Preferred Stock, Liquidation Preference Per Share	$1,000
Conversion of Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	38.25%
Conversion of Stock, Conversion Price	$26.14
Conversion of Stock, Company Conversion Right, Date	17-May-15
Trigger Price For Time Period	33.9836
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Preferred Stock [Member] | 4.50% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Stock Issue Date	Sep-05
Preferred Stock, Liquidation Preference Per Share	$100
Conversion of Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	2.45%
Conversion of Stock, Conversion Price	$40.87
Conversion of Stock, Company Conversion Right, Date	15-Sep-10
Trigger Price For Time Period	53.1301
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Preferred Stock [Member] | 5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Stock Issue Date	Nov-05
Preferred Stock, Liquidation Preference Per Share	$100
Conversion of Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	2.77%
Conversion of Stock, Conversion Price	$36.14
Conversion of Stock, Company Conversion Right, Date	15-Nov-10
Trigger Price For Time Period	$46.98
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Minimum [Member] | Preferred Stock [Member] | 5.75% Cumulative Convertible Preferred Stock Series A [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Company Market Trigger	25,000
Minimum [Member] | Preferred Stock [Member] | 4.50% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Conversion of Stock, Company Market Trigger	250,000

Equity_Convertible_Preferred_S

Equity - Convertible Preferred Stock Table (Details)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding, beginning of period	7,251,515	7,251,515
Shares outstanding, end of period	7,251,515	7,251,515
5.75% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding, beginning of period	1,497,000	1,497,000	1,497,000
Shares outstanding, end of period	1,497,000	1,497,000	1,497,000
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding, beginning of period	1,100,000	1,100,000	1,100,000
Shares outstanding, end of period	1,100,000	1,100,000	1,100,000
4.50% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding, beginning of period	2,559,000	2,559,000	2,559,000
Shares outstanding, end of period	2,559,000	2,559,000	2,559,000
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding, beginning of period	2,096,000	2,096,000	2,096,000
Shares outstanding, end of period	2,096,000	2,096,000	2,096,000

Equity_AOCI_Changes_Net_of_Tax

Equity - AOCI Changes Net of Tax Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	($162)
Net current period other comprehensive income	19	20	-16
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	-143	-162
Accumulated Other Comprehensive Income (Loss) [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	-162	-182
Other comprehensive income before reclassifications	1	-4
Amounts reclassified from accumulated other comprehensive income	18	24
Net current period other comprehensive income	19	20
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	-143	-162
Accumulated Other Comprehensive Income (Loss) [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	-167	-189
Other comprehensive income before reclassifications	1	2
Amounts reclassified from accumulated other comprehensive income	23	20
Net current period other comprehensive income	24	22
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	-143	-167
Accumulated Other Comprehensive Income (Loss) [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	5	7
Other comprehensive income before reclassifications	0	-6
Amounts reclassified from accumulated other comprehensive income	-5	4
Net current period other comprehensive income	-5	-2
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$0	$5

Equity_AOCI_Reclassifications_

Equity - AOCI Reclassifications Table (Details) (Accumulated Other Comprehensive Income (Loss) [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$18	$24
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	23	20
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	-5	4
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Impairment of Investment [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		6
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Sale of Investment [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	($5)	($2)

Equity_Narrative_Details

Equity - Narrative (Details)	12 Months Ended
	Dec. 31, 2014
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.00%
4.50% Cumulative Convertible Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	4.50%
5.75% Cumulative Convertible Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.75%

Equity_Noncontrolling_Interest

Equity - Noncontrolling Interests Narrative (Details) (USD $)	12 Months Ended			0 Months Ended	1 Months Ended	6 Months Ended	1 Months Ended	12 Months Ended	3 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 30, 2012	Mar. 30, 2012	Jun. 30, 2014	Oct. 31, 2011	Dec. 31, 2011	Dec. 31, 2011	Mar. 31, 2012	Nov. 30, 2011
				well	acre	well	acre	County
Noncontrolling Interest [Line Items]
Payments for (Proceeds from) Investments	$17	$44	$395
Restricted cash and cash equivalents, current	38	75
Stockholders' Equity Attributable to Noncontrolling Interest	1,302	2,145
Net income attributable to noncontrolling interests	139	170	175
Preferred Stock Redemption Premium	447	69	0
Common Stock, Shares, Issued	664,944,232	666,192,371	666,468,000					660,888,000	660,888,000
Common stock, par value (usd per share)	$0.01	$0.01
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres					245,000
Payments for (Proceeds from) Investments			1,250
Preferred Stock, Shares Issued			1,250,000
Number of Wells, Net				1,000
Overriding Royalty Interest Percentage	3.75%									3.75%
Restricted cash and cash equivalents, current	38	38
Preferred Stock, Dividend Rate, Percentage	6.00%
Preferred Stock, Dividends, Per Share, Cash Paid	$1,000
Distribution of Excess Cash	100.00%
Percentage of internal rate of return	9.00%
Internal return on investment, multiplier	1.35
Preferred Stock, Redemption Price Per Share	$1,185	$1,245
Acre Spacing	160
Stockholders' Equity Attributable to Noncontrolling Interest	1,015
Net income attributable to noncontrolling interests	75	75	57
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Days in Notice	45
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Maximum, March 31, 2019 [Member]
Noncontrolling Interest [Line Items]
Percentage of internal rate of return	15.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period Through 2013 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net Decimal	37.5
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period in 2014 Through 2016 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	25
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Cumulative Well Total [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	300
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period of April 1, 2014 - June 30,2014 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net Decimal						162.5
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period of June 30,2014 Through December 31, 2014 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net Decimal	175
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six Month Period, 1.1.15 - 6.30.15 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	225
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six Month Periods, 7.1.15 - 12.31.17 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	25
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Maximum, Two Consecutive Six-Month Periods [Member]
Noncontrolling Interest [Line Items]
Percentage of internal rate of return	3.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Maximum, Four Consecutive Six-Month Periods [Member]
Noncontrolling Interest [Line Items]
Percentage of internal rate of return	3.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Future Wells [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net				1,000
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Qualified Wells [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	17	77	84
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Percentage Increase in Future Net Wells [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Percentage of increase in leasehold in which commitment to drill is not met	5.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Drilled Wells [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	867
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Preferred Stock [Member]
Noncontrolling Interest [Line Items]
Preferred Stock, Dividend Rate, Percentage	6.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Cash Distribution [Member]
Noncontrolling Interest [Line Items]
Payments for (Proceeds from) Investments					225
Distribution of Excess Cash	75.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Share Distribution [Member]
Noncontrolling Interest [Line Items]
Payments for (Proceeds from) Investments					1,025
Distribution of Excess Cash	25.00%
Noncontrolling Interest, Chesapeake Utica L L C [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres							700,000
Payments for (Proceeds from) Investments								1,250
Preferred Stock, Shares Issued								1,250,000	1,250,000
Number of Wells, Net	1,500
Overriding Royalty Interest Percentage								3.00%	3.00%
Preferred Stock, Redemption Price Per Share	$1,189
Percentage of increase in leasehold in which commitment to drill is not met	4.00%
Stockholders' Equity Attributable to Noncontrolling Interest	0	807
Net income attributable to noncontrolling interests	43	79	88
Number of counties present in the leasehold land (Counties)								13
Payments for Repurchase of Preferred Stock and Preference Stock	1,254
Preferred Stock Redemption Premium	447
Spacing for Wells Drilled	150
Noncontrolling Interest, Chesapeake Utica L L C [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net	1,300
Noncontrolling Interest, Chesapeake Utica L L C [Member] | Wells, Percentage Increase in Future Net Wells [Member]
Noncontrolling Interest [Line Items]
Percentage of increase in leasehold in which commitment to drill is not met	4.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres	29,000
Stockholders' Equity Attributable to Noncontrolling Interest	287	314
Net income attributable to noncontrolling interests	24	20	35
Percentage Of Beneficial Interest Owned	51.00%
Common stock, par value (usd per share)											$19
Common shares, outstanding	46,750,000
Number of producing wells	69
Number of development wells drilled	102	82
Number Of Gross Acres	45,400
Maximum amount recoverable by trust under lien	$36	$79							$263
Percentage of incentive distributions received	50.00%
Percentage of remaining cash available for distribution in excess of the incentive threshold	50.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Percentage of proceeds from royalty interest conveyed to trust	50.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Maximum [Member]
Noncontrolling Interest [Line Items]
Percentage of proceeds from royalty interest conveyed to trust	90.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Wells, Initial Number of Wells [Member]
Noncontrolling Interest [Line Items]
Number of development wells drilled	118
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Common Unit [Member]
Noncontrolling Interest [Line Items]
Common Stock, Shares, Issued											23,000,000
Common shares, outstanding	12,062,500
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Subordinated Units [Member]
Noncontrolling Interest [Line Items]
Common shares, outstanding	11,687,500

Equity_Noncontrolling_Interest1

Equity - Noncontrolling Interests Distribution Table (Details) (Noncontrolling Interest, Chesapeake Granite Wash Trust [Member], USD $)	3 Months Ended
	Aug. 31, 2014	31-May-14	Feb. 28, 2014	Nov. 30, 2013	Aug. 31, 2013	31-May-13	Feb. 28, 2013	Nov. 30, 2012	Aug. 31, 2012	31-May-12	Feb. 29, 2012	Nov. 30, 2011
Noncontrolling Interest [Line Items]
Distribution Made to Limited Partner, Distribution Date	1-Dec-14	29-Aug-14	30-May-14	3-Mar-14	29-Nov-13	29-Aug-13	31-May-13	1-Mar-13	29-Nov-12	30-Aug-12	31-May-12	1-Mar-12
Common Unit [Member]
Noncontrolling Interest [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	0.5079	0.5796	0.6454	0.6624	0.6671	0.69	0.69	0.67	0.63	0.61	0.6588	0.7277
Subordinated Units [Member]
Noncontrolling Interest [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	0	0	0	0	0	0.1432	0.301	0.3772	0.2208	0.4819	0.6588	0.7277

ShareBased_Compensation_Restri

Share-Based Compensation - Restricted Stock Table (Details) (Restricted Stock [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period Start	13,400	18,899	19,544
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	5,049	9,189	9,480
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-4,803	-12,897	-8,620
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	-3,555	-1,791	-1,505
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period End	10,091	13,400	18,899
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period Start	$23.38	$23.72	$26.97
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$25.92	$19.68	$21.13
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$27.17	$21.32	$28.08
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$28.09	$22.86	$24.57
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End	$21.20	$23.38	$23.72

ShareBased_Compensation_Equity

Share-Based Compensation - Equity-Classified Valuation Table (Details) (Employee Stock Option [Member])	12 Months Ended
	Dec. 31, 2014
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	5 years 10 months 20 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	48.63%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.93%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	1.33%

ShareBased_Compensation_Stock_

Share-Based Compensation - Stock Option Activity Table (Details) (USD $)	0 Months Ended	12 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Dec. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period Start		5,268	481	1,051
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures		994	5,264
Share Based Compensation Arrangement By Share Based Payment Award Shares Underlying Options Exercised In Period		-1,322	-346	-570
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period		-28	-131
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested Options Forfeited, Number of Shares		-313
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period End		4,599	5,268	481	1,051
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number		1,304	1,552
Weighted Average Exercise Price [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period Start		$19.28	$12.69	$9.84
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value		$24.43	$19.32
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price		$18.71	$10.82	$7.45
Share-based Compensation Arrangements by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price		$18.97	$19.31
Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price		$21.05
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period End		$19.55	$19.28	$12.69	$9.84
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price		$18.71	$18.82
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period Start		$41	$2	$13
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value		11	3	7
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period End		5	41	2	13
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value		$1	$13
Weighted Average Contract Life (in years) [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	6 years 7 months 29 days	7 years 12 days		11 months 16 days	1 year 4 months 28 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term		5 years 8 months 13 days	1 year 11 months 19 days

ShareBased_Compensation_Equity1

Share-Based Compensation - Equity-Classified Compensation Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$104	$150	$191
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	46	60	71
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	29	52	71
Operating Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	18	21	24
Cost of Sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	6	7	15
Other Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$5	$10	$10

ShareBased_Compensation_Liabil

Share-Based Compensation - Liability Classified Valuation Table (Details) (Performance Shares [Member])	12 Months Ended
	Dec. 31, 2014
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	41.37%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	0.76%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	1.36%

ShareBased_Compensation_Perfor

Share-Based Compensation - Performance Share Unit Breakout (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$104	$150	$191
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	-1	48	14
Performance Shares [Member] | Year of 2012 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	11	2
Performance Shares [Member] | Payable 2015 [Member] | Year of 2012 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	884,507
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	12
Fair Value of Share Based Award	12		23
Performance Shares [Member] | Payable 2016 [Member] | Year of 2013 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	1,701,941
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	39
Fair Value of Share Based Award	42		35
Performance Shares [Member] | Payable 2017 [Member] | Year of 2014 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	609,637
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	7
Fair Value of Share Based Award	$10		$16

ShareBased_Compensation_Liabil1

Share-Based Compensation - Liability-Classified Compensation Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$104	$150	$191
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	46	60	71
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	29	52	71
Operating Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	18	21	24
Cost of Sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	6	7	15
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	-1	48	14
Performance Shares [Member] | General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	-4	34	8
Performance Shares [Member] | Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	3	9	4
Performance Shares [Member] | Operating Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	0	2	1
Performance Shares [Member] | Cost of Sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	0	2	1
Performance Shares [Member] | Oilfield Services [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$0	$1	$0

ShareBased_Compensation_Narrat

Share-Based Compensation - Narrative (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Authorized	1,000,000,000	1,000,000,000
Common Stock, Shares, Issued	664,944,232	666,192,371	666,468,000	660,888,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures	994,000	5,264,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	130
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	135
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	2 years 8 days
Restricted Stock [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	2 years 8 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used	Black-Scholes option pricing model
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options	11
TSR [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used	Monte Carlo simulation
Employee [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Employee [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	4 years
Management [Member] | Retention Based Stock Option Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	33.00%
Management [Member] | Incentive Based Stock Option Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Management [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years
Stock Option Award Three Year Anniversary [Member] | Management [Member] | Retention Based Stock Option Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Stock Optioin Award Four Year Anniversary [Member] | Management [Member] | Retention Based Stock Option Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	4 years
Stock option Award Five Year Anniversary [Member] | Management [Member] | Retention Based Stock Option Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	5 years
Paid-In Capital [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) in tax benefit from stock-based compensation	15	-13	-30
Paid-In Capital [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Adjustments to Additional Paid in Capital, Income Tax Deficiency from Share-based Compensation		14	32
Increase (decrease) in tax benefit from stock-based compensation	12
Paid-In Capital [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) in tax benefit from stock-based compensation	3	1	$2
Year of 2012 [Member] | Share-Based Comp Award One Year Anniversary [Member] | Management [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	1 year
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	first
Year of 2012 [Member] | Share-Based Comp Award Two Year Anniversary [Member] | Management [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	2 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	second
Year of 2012 [Member] | Share-Based Comp Award Three Year Anniversary [Member] | Management [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	third
Years of 2013 and 2014 [Member] | Share-Based Comp Award Three Year Anniversary [Member] | Management [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights		third
2014 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Reduction due to issuance of stock option or SAR	1
Reduction due to award other than stock option or SAR	2.12
Remaining Shares Available For Issuance	36,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	10 years
2014 Long Term Incentive Plan [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Authorized	36,600,000
2014 Long Term Incentive Plan [Member] | Employee [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation, Option to Purchase, Shares	272,289
2014 Long Term Incentive Plan [Member] | Non-Employee Director [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period		50,771
2005 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	10 years
2005 Long Term Incentive Plan [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Authorized	59,300,000
2005 Long Term Incentive Plan [Member] | Employee [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	1,300,000	2,500,000	5,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures	993,730	5,300,000	0
2005 Long Term Incentive Plan [Member] | Non-Employee Director [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	48,083	147,108	170,151
2003 Stock Award Plan for Non-Employee Directors [Member] | Non-Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining Shares Available For Issuance	120,000
2003 Stock Award Plan for Non-Employee Directors [Member] | Non-Employee Director [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Authorized	250,000
Common Stock, Shares, Issued	10,000
2003 Stock Award Plan for Non-Employee Directors [Member] | Common Stock [Member] | Non-Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	10,000	20,000	30,000
Long-Term Incentive Plan [Member] | Year of 2012 [Member] | Management [Member] | Performance Shares [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Long-Term Incentive Plan [Member] | Year of 2012 [Member] | Management [Member] | Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	125.00%
Long-Term Incentive Plan [Member] | Year of 2012 [Member] | Management [Member] | Performance Shares and Operational Components [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	250.00%
Long-Term Incentive Plan [Member] | Year of 2013 [Member] | Management [Member] | Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	200.00%
Long-Term Incentive Plan [Member] | Year of 2013 [Member] | Management [Member] | TSR [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Long-Term Incentive Plan [Member] | Year of 2013 [Member] | Management [Member] | TSR [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	125.00%
Long-Term Incentive Plan [Member] | Year of 2013 [Member] | Management [Member] | Operational Component [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Long-Term Incentive Plan [Member] | Year of 2013 [Member] | Management [Member] | Operational Component [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	62.50%
Long-Term Incentive Plan [Member] | Year of 2014 [Member] | Performance Shares [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		100.00%
Long-Term Incentive Plan [Member] | Year of 2014 [Member] | Management [Member] | TSR [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Long-Term Incentive Plan [Member] | Year of 2014 [Member] | Management [Member] | TSR [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	200.00%

Employee_Benefit_Plans_Narrati

Employee Benefit Plans Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	15.00%
Defined Benefit Plan, Contributions by Employer	$61,000,000	$81,000,000	$91,000,000
Defined Benefit Plans, General Information	55
Defined Benefit Pension Plan, Liabilities	3,000,000
Deferred Compensation, Excluding Share-based Payments and Retirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	75.00%
Deferred Bonus [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	100.00%
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum Annual Compensation Received	150,000
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plans, General Information	10%
DC Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	15.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	100.00%
Deferred Compensation Arrangement with Individual, Employer Contribution	$7,000,000	$14,000,000	$16,000,000
Director DC Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	100.00%

Derivative_and_Hedging_Activit2

Derivative and Hedging Activities - Derivative Instruments Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	MMBbls	MMBbls
Derivative [Line Items]
Fair Value	$721	($551)
Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	52,700,000	68,200,000
Fair Value	422	-314
Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	12,500,000	25,300,000
Fair Value	471	-50
Crude Oil [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	4,400,000	0
Fair Value	40	0
Crude Oil [Member] | Call Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	35,800,000	42,500,000
Fair Value	-89	-265
Crude Oil [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0	400,000
Fair Value	0	1
Natural Gas [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	735,000,000,000,000	1,009,000,000,000,000
Fair Value	299	-237
Natural Gas [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	275,000,000,000,000	448,000,000,000,000
Fair Value	281	-23
Natural Gas [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	207,000,000,000,000	288,000,000,000,000
Fair Value	165	-7
Natural Gas [Member] | Call Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	193,000,000,000,000	193,000,000,000,000
Fair Value	-170	-210
Natural Gas [Member] | Swaption [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	0	12,000,000,000,000
Fair Value	0	0
Natural Gas [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	60,000,000,000,000	68,000,000,000,000
Fair Value	$23	$3

Derivative_and_Hedging_Activit3

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$652
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value	-17
Derivative liability, gross liability		-649
Foreign Currency Fair Value Hedge Asset at Fair Value		2
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative, Fair Value, Net	652	-649
Interest Rate Derivative Instruments Not Designated as Hedging Instruments at Fair Value, Net	-17	-98
Foreign Currency Fair Value Hedge Derivative at Fair Value, Net	-53	2
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	722
Derivative liability, gross liability		-553
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative, Fair Value, Net	722	-553
Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value		-98
Derivative, Gain (Loss) on Derivative, Net	0	0
Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	974	29
Derivative, Gain (Loss) on Derivative, Net	-95	-29
Derivative, Fair Value, Net	879	0
Other Noncurrent Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	16	11
Derivative, Gain (Loss) on Derivative, Net	-10	-9
Derivative, Fair Value, Net	6	2
Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value	-5	-6
Interest Rate Derivative Instruments Not Designated as Hedging Instruments at Fair Value, Net	-5	-6
Other Current Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative liability, gross liability	-105	-231
Derivative, Gain (Loss) on Derivative, Net	95	29
Derivative, Fair Value, Net	-10	-202
Other Current Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Other Noncurrent Liabilities [Member]
Derivatives, Fair Value [Line Items]
Interest Rate Derivative Instruments Not Designated as Hedging Instruments, Liability at Fair Value	-12	-92
Foreign Currency Fair Value Hedge Asset at Fair Value		2
Foreign Currency Fair Value Hedge Liability at Fair Value	53
Interest Rate Derivative Instruments Not Designated as Hedging Instruments at Fair Value, Net	-12	-92
Foreign Currency Fair Value Hedge Derivative at Fair Value, Net	-53	2
Other Noncurrent Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative liability, gross liability	-163	-362
Derivative, Gain (Loss) on Derivative, Net	10	9
Derivative, Fair Value, Net	-153	-353
Other Noncurrent Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0
Other Noncurrent Liabilities [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$0	$0

Derivative_and_Hedging_Activit4

Derivative and Hedging Activities - Natural Gas and Oil Sales Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Gains on undesignated oil and natural gas derivatives	$81	($63)	($1)
Total Revenues	20,951	17,506	12,316
Oil And Gas Exploration And Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL sales	7,162	6,923	5,359
Gains on undesignated oil and natural gas derivatives	1,055	443	857
Gains (losses) on terminated cash flow hedges	-37	-314	62
Total Revenues	$8,180	$7,052	$6,278

Derivative_and_Hedging_Activit5

Derivative and Hedging Activities - Components of Interest Income and Interest Expense Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Interest expense on senior notes	$704	$740	$732
Interest expense on term loans	36	116	173
Amortization of loan discount, issuance costs and other	42	91	89
Interest expense on credit facilities	28	38	70
Gains on terminated fair value hedges	-3	-5	-8
(Gains) losses on undesignated interest rate derivatives	-81	63	1
Capitalized interest	-637	-816	-980
Total interest expense	$89	$227	$77

Derivative_and_Hedging_Activit6

Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Effect of Derivative Instruments AOCI Reconcile [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	($143)	($162)
Accumulated Other Comprehensive Income (Loss) [Member]
Effect of Derivative Instruments AOCI Reconcile [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	-143	-162	-182
Cash Flow Hedging [Member] | Accumulated Other Comprehensive Income (Loss) [Member]
Effect of Derivative Instruments AOCI Reconcile [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Before Tax, Period Start	-269	-304	-287
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	-167	-189	-178
Other Comprehensive Income (Loss), Before Reclassifications, Before Tax	1	3	10
Other Comprehensive Income (Loss), Before Reclassifications, Net of Tax	1	2	6
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	37	32
Derivative Instruments, Loss Reclassified from Accumulated OCI into Income, Effective Portion, Before Tax			27
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	23	20	-17
Accumulated Other Comprehensive Income (Loss), Before Tax, Period End	-231	-269	-304
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	($143)	($167)	($189)

Derivative_and_Hedging_Activit7

Derivative and Hedging Activities - Fair Value of Recurring Assets and Liabilities Table (Details) (Fair Value, Measurements, Recurring [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	($17)	($98)
Foreign Currency Contracts, Liability, Fair Value Disclosure	-53
Foreign Currency Contracts, Asset, Fair Value Disclosure		2
Derivative Assets (Liabilities), at Fair Value, Net	652	-649
Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	990	40
Derivative Liability	-268	-593
Fair Value, Inputs, Level 1 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	0	0
Foreign Currency Contracts, Liability, Fair Value Disclosure	0
Foreign Currency Contracts, Asset, Fair Value Disclosure		0
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Fair Value, Inputs, Level 1 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	-17	-98
Foreign Currency Contracts, Liability, Fair Value Disclosure	-53
Foreign Currency Contracts, Asset, Fair Value Disclosure		2
Derivative Assets (Liabilities), at Fair Value, Net	706	-171
Fair Value, Inputs, Level 2 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	785	25
Derivative Liability	-9	-100
Fair Value, Inputs, Level 3 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Interest Rate Derivative Liabilities, at Fair Value	0	0
Foreign Currency Contracts, Liability, Fair Value Disclosure	0
Foreign Currency Contracts, Asset, Fair Value Disclosure		0
Derivative Assets (Liabilities), at Fair Value, Net	-54	-478
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	205	15
Derivative Liability	($259)	($493)

Derivative_and_Hedging_Activit8

Derivative and Hedging Activities - Fair Value Level 3 Measurements Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Interest Rate Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, End of Period		$0
Fair Value, Inputs, Level 3 [Member] | Natural Gas And Oil Sales [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	262	382
Fair Value, Inputs, Level 3 [Member] | Interest Expense [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	0	0
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Beginning of Period	-478	-1,016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	292	410
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	136	128
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	-4
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, End of Period	-54	-478
Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Beginning of Period	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	0	-1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales		1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, End of Period	$0	$0

Derivative_and_Hedging_Activit9

Derivative and Hedging Activities - Quantitative Disclosures Level 3 Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Natural Gas [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	-5
Natural Gas [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	18.71%
Natural Gas [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	63.70%
Natural Gas [Member] | Weighted Average [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	34.38%
Crude Oil [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	-49
Crude Oil [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	27.33%
Crude Oil [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	43.56%
Crude Oil [Member] | Weighted Average [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	34.09%

Recovered_Sheet2

Derivative and Hedging Activities - Narrative (Details)

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Apr. 24, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2006

Dec. 31, 2006

Dec. 31, 2006

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

In Millions, unless otherwise specified

USD ($)

USD ($)

Interest Rate Contract [Member]

Interest Rate Contract [Member]

Senior Notes [Member]

Senior Notes [Member]

Multi-Counterparty Hedging Facility [Member]

Multi-Counterparty Hedging Facility [Member]

Multi-Counterparty Hedging Facility [Member]

Multi-Counterparty Hedging Facility [Member]

Multi-Counterparty Hedging Facility [Member]

6.25% Euro-Denominated Senior Notes Due 2017 [ Member]

6.25% Euro-Denominated Senior Notes Due 2017 [ Member]

6.25% Euro-Denominated Senior Notes Due 2017 [ Member]

6.25% Euro-Denominated Senior Notes Due 2017 [ Member]

6.25% Euro-Denominated Senior Notes Due 2017 [ Member]

6.25% Euro-Denominated Senior Notes Due 2017 [ Member]

6.25% Euro-Denominated Senior Notes Due 2017 [ Member]

6.25% Euro-Denominated Senior Notes Due 2017 [ Member]

Minimum [Member]

Minimum [Member]

Accumulated Other Comprehensive Deferred Loss [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

Credit Risk [Member]

Energy Related Derivative [Member]

Price Risk Derivative [Member]

Basis Derivative [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Multi-Counterparty Hedging Facility [Member]

Cash Flow Hedging [Member]

USD ($)

USD ($)

USD ($)

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

counterparty

counterparty

MMBoe

MMBoe

MMBoe

USD ($)

USD ($)

USD ($)

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

EUR (€)

USD ($)

EUR (€)

USD ($)

Derivative [Line Items]

Derivative, Amount of Hedged Item

$850

$2,250

Interest Rate Derivatives, at Fair Value, Net

17

98

Amortization Period of Deferred Gain (Loss) on Discontinuation of Fair Value Hedge

6 years

Deferred (Gain) Loss on Discontinuation of Fair Value Hedge

10

Euro-denominated debt in notes payable, adjusted value

11,756

10

13

3,000

3,000

416

473

344

416

50

Derivative, Forward Exchange Rate

1.3325

1.2098

1.3743

Semi Annual Interest Rate Swap Payments By Counterparty

11

344

Dollar Equivalent Interest Rate

7.49%

7.49%

Short-term Debt, Refinanced, Description

17

459

Derivative liability, gross liability

649

53

Derivative Asset, Fair Value, Gross Asset

652

2

Accumulated other comprehensive loss

-143

-162

-136

-143

-162

-182

-143

-167

-189

-178

Expected amount to be transferred of during the next 12 months

23

Number of counterparties in hedge facility

17

18

Multi-counterparty hedging facility, committed to provide a trading capacity (in tcfe)

1,031,000,000

Borrowing capacity

$16,500

Natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility, multiplier

1.3

1.65

Multi-counterparty hedge facility, hedged total (in tcfe)

164,000,000

10,000,000

Natural_Gas_and_Oil_Property_T2

Natural Gas and Oil Property Transactions - VPP Transactions Table (Details) (USD $)	12 Months Ended	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Mar. 31, 2012	Jun. 30, 2011	Sep. 30, 2010	Dec. 31, 2008	Sep. 30, 2008	Jun. 30, 2008	Dec. 31, 2007	31-May-11	Aug. 31, 2008	31-May-08
	Mcfe	Mcfe		Mcfe	Mcfe			Mcfe	Mcfe	Mcfe	Mcfe
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)	$5,481
Proved Developed Reserves (Energy)	1,220,000,000,000
Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)	5,200,000
Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)	1,105,000,000,000
NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)	14,000,000
VPP 10 Aradarko Basin Granite Wash [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)		744
Proved Developed Reserves (Energy)		160,000,000,000
VPP 10 Aradarko Basin Granite Wash [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)		3,000,000
VPP 10 Aradarko Basin Granite Wash [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)		87,000,000,000
VPP 10 Aradarko Basin Granite Wash [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)		9,200,000
VPP 9 Mid-Continent [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)			853
Proved Developed Reserves (Energy)									177,000,000,000
VPP 9 Mid-Continent [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)									1,700,000
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)									138,000,000,000
VPP 9 Mid-Continent [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)									4,800,000
VPP 8 Barnett Shale [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)				1,150
Proved Developed Reserves (Energy)				390,000,000,000
VPP 8 Barnett Shale [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)				0
VPP 8 Barnett Shale [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)				390,000,000,000
VPP 8 Barnett Shale [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)				0
VPP 4 Anadarko and Arkoma Basins [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)					412
Proved Developed Reserves (Energy)					98,000,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)					500,000
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)					95,000,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)					0
VPP 3 Anadarko Basin [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)						600
Proved Developed Reserves (Energy)										93,000,000,000
VPP 3 Anadarko Basin [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)										0
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)										93,000,000,000
VPP 3 Anadarko Basin [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)										0
VPP 2 Texas, Oklahoma and Kansas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)							622
Proved Developed Reserves (Energy)											94,000,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)											0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)											94,000,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)											0
VPP 1 Kentucky and West Virginia [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP)								$1,100
Proved Developed Reserves (Energy)								208,000,000,000
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)								0
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)								208,000,000,000
VPP 1 Kentucky and West Virginia [Member] | NGL [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proved Developed Reserves (Volume)								0

Natural_Gas_and_Oil_Property_T3

Natural Gas and Oil Property Transactions - VPP Volumes Produced During Period Table (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Mcfe	Mcfe	Mcfe
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	145,200,000,000	170,900,000,000	202,200,000,000
Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	678,200	864,300	1,580,800
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	131,100,000,000	154,000,000,000	178,400,000,000
NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	1,707,500	1,964,700	2,372,700
VPP 10 Anadarko Basin Granite Wash [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	20,700,000,000	25,800,000,000	32,800,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	403,000	547,000	727,000
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	10,600,000,000	13,500,000,000	18,100,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	1,296,500	1,509,000	1,729,100
VPP 9 Mid-Continent [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	19,000,000,000	21,000,000,000	23,700,000,000
VPP 9 Mid-Continent [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	187,500	213,200	249,300
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	15,400,000,000	17,000,000,000	18,400,000,000
VPP 9 Mid-Continent [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	411,000	455,700	643,600
VPP 8 Barnett Shale [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	60,100,000,000	68,100,000,000	79,700,000,000
VPP 8 Barnett Shale [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 8 Barnett Shale [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	60,100,000,000	68,100,000,000	79,700,000,000
VPP 8 Barnett Shale [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 7 Permian Basin [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)			3,400,000,000
VPP 7 Permian Basin [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production			490,300
VPP 7 Permian Basin [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production			400,000,000
VPP 7 Permian Basin [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production			0
VPP 6 East Texas and Texas Gulf Coast [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	4,300,000,000	4,900,000,000	5,500,000,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	23,100	24,000	24,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	4,200,000,000	4,800,000,000	5,300,000,000
VPP 6 East Texas and Texas Gulf Coast [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 5 South Texas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	4,700,000,000	7,700,000,000	9,000,000,000
VPP 5 South Texas [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	16,500	25,400	27,400
VPP 5 South Texas [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	4,600,000,000	7,500,000,000	8,800,000,000
VPP 5 South Texas [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 4 Anadarko and Arkoma Basins [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	9,200,000,000	10,500,000,000	12,200,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	48,100	54,700	62,800
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	9,000,000,000	10,200,000,000	11,700,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 3 Anadarko Basin [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	7,200,000,000	8,100,000,000	9,300,000,000
VPP 3 Anadarko Basin [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	7,200,000,000	8,100,000,000	9,300,000,000
VPP 3 Anadarko Basin [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 2 Texas, Oklahoma and Kansas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	6,200,000,000	10,300,000,000	11,300,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	6,200,000,000	10,300,000,000	11,400,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 1 Kentucky and West Virginia [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	13,800,000,000	14,500,000,000	15,300,000,000
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	13,800,000,000	14,500,000,000	15,300,000,000
VPP 1 Kentucky and West Virginia [Member] | NGL [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0

Natural_Gas_and_Oil_Property_T4

Natural Gas and Oil Property Transactions - VPP Volume Remaining to Be Delivered Table (Details)	12 Months Ended
	Dec. 31, 2014	31-May-11	Sep. 30, 2010	Dec. 31, 2008	Aug. 31, 2008	31-May-08	Dec. 31, 2007
	Mcfe	Mcfe	Mcfe	Mcfe	Mcfe	Mcfe	Mcfe
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)	1,220,000,000,000
Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)	345,500,000,000
Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	5,200,000
Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	2,200,000
Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	1,105,000,000,000
Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	292,300,000,000
NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	14,000,000
NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	6,600,000
VPP 10 Anadarko Basin Granite Wash [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	86 months
Proved Developed Reserves (Energy)	74,000,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	1,300,000
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	38,000,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	4,700,000
VPP 9 Mid-Continent [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)		177,000,000,000
VPP 9 Mid-Continent [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	74 months
Proved Developed Reserves (Energy)	89,900,000,000
VPP 9 Mid-Continent [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)		1,700,000
VPP 9 Mid-Continent [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	800,000
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)		138,000,000,000
VPP 9 Mid-Continent [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	73,200,000,000
VPP 9 Mid-Continent [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)		4,800,000
VPP 9 Mid-Continent [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	1,900,000
VPP 8 Barnett Shale [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)			390,000,000,000
VPP 8 Barnett Shale [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	8 months
Proved Developed Reserves (Energy)	36,600,000,000
VPP 8 Barnett Shale [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)			0
VPP 8 Barnett Shale [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 8 Barnett Shale [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)			390,000,000,000
VPP 8 Barnett Shale [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	36,600,000,000
VPP 8 Barnett Shale [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)			0
VPP 8 Barnett Shale [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 4 Anadarko and Arkoma Basins [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)				98,000,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	24 months
Proved Developed Reserves (Energy)	15,800,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)				500,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	100,000
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)				95,000,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	15,300,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)				0
VPP 4 Anadarko and Arkoma Basins [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 3 Anadarko Basin [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)					93,000,000,000
VPP 3 Anadarko Basin [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	55 months
Proved Developed Reserves (Energy)	23,900,000,000
VPP 3 Anadarko Basin [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)					0
VPP 3 Anadarko Basin [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)					93,000,000,000
VPP 3 Anadarko Basin [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	23,900,000,000
VPP 3 Anadarko Basin [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)					0
VPP 3 Anadarko Basin [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 2 Texas, Oklahoma and Kansas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)						94,000,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	52 months
Proved Developed Reserves (Energy)	13,800,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)						0
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)						94,000,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	13,800,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)						0
VPP 2 Texas, Oklahoma and Kansas [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 1 Kentucky and West Virginia [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Energy)							208,000,000,000
VPP 1 Kentucky and West Virginia [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Term remaining (in months)	96 months
Proved Developed Reserves (Energy)	91,500,000,000
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)							0
VPP 1 Kentucky and West Virginia [Member] | Oil [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)							208,000,000,000
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	91,500,000,000
VPP 1 Kentucky and West Virginia [Member] | NGL [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)							0
VPP 1 Kentucky and West Virginia [Member] | NGL [Member] | Reserve Volume Remaining [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Proved Developed Reserves (Volume)	0

Natural_Gas_and_Oil_Property_T5

Natural Gas and Oil Property Transactions - Narrative (Details) (USD $)	12 Months Ended			1 Months Ended	0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 31, 2008	Oct. 15, 2014	Oct. 14, 2014
	Mcfe	Mcfe	Mcfe		acre
Business Acquisition [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)	145,200,000,000	170,900,000,000	202,200,000,000
Proceeds from divestitures of proved and unproved properties	$5,813,000,000	$3,467,000,000	$5,884,000,000
Total Drilling Carries	9,000,000,000
Minimum [Member]
Business Acquisition [Line Items]
Interest Sold				20.00%
Maximum [Member]
Business Acquisition [Line Items]
Interest Sold				50.00%
VPP 6 East Texas and Texas Gulf Coast [Member]
Business Acquisition [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds						63,000,000
Proved Developed and Undeveloped Reserve, Production (Energy)	4,300,000,000	4,900,000,000	5,500,000,000
Corporate Joint Venture [Member]
Business Acquisition [Line Items]
Number Of Net Acres		850,000
Proceeds from divestitures of proved and unproved properties	379,000,000
Number of Joint Ventures	8
Number of Resource Plays	8
Proceeds from Divestiture of Interest in Joint Venture	8,000,000,000
Oil And Gas Benefit From Drilling Carries	679,000,000	884,000,000	784,000,000
JV Mississippian Lime [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture		1,110,000,000
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners		50.00%
JV Utica [Member]
Business Acquisition [Line Items]
Drilling Carries Remaining	51,000,000
Percentage of Total Payment by Joint Venture Partner	60.00%
JV Marcellus, Barnett, Utica, Eagle Ford, Mid-Continent [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture	33,000,000	58,000,000	272,000,000
Corporate VPP [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Other Assets	0
Payment Remaining [Member] | JV Mississippian Lime [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture		71,000,000
Closing adjustments between the effective date and the closing date transaction [Member] | JV Mississippian Lime [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture		90,000,000
Payment Received [Member] | JV Mississippian Lime [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture		64,000,000
Southwestern [Member]
Business Acquisition [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds						4,975,000,000
Number Of Net Acres					413,000
Southwestern [Member] | North Western Virginia and Southern Pennsylvania [Member]
Business Acquisition [Line Items]
Number of Wells, Gross					1,500
Southwestern [Member] | Marcellus and Utica Formations [Member]
Business Acquisition [Line Items]
Number of Wells, Gross					435
RKI Exploration & Production, LLC [Member]
Business Acquisition [Line Items]
Number Of Gross Acres	440,000
RKI Exploration & Production, LLC [Member] | RKI Obligation [Member]
Business Acquisition [Line Items]
Number Of Net Acres	203,000
Number of Wells, Gross	186
Interest Sold	48.00%
RKI Exploration & Production, LLC [Member] | Chesapeake Obligation [Member]
Business Acquisition [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	450,000,000
Number Of Net Acres	137,000
Number of Wells, Gross	67
Interest Sold	22.00%
Rice Drilling [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties	233,000,000
Hilcorp Energy [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties	133,000,000
Haynesville Shale [Member]
Business Acquisition [Line Items]
Number Of Net Acres		9,600
Haynesville Shale [Member] | Payment at Closing [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		257,000,000
Haynesville Shale [Member] | Subsequent Payment [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		47,000,000
Northern Eagle Ford Shale [Member]
Business Acquisition [Line Items]
Number Of Net Acres		55,000
Northern Eagle Ford Shale [Member] | Payment at Closing [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		617,000,000
Northern Eagle Ford Shale [Member] | Subsequent Payment [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties	57,000,000	32,000,000
MKR Holdings LLC [Member] | Payment at Closing [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		490,000,000
Permian Basin [Member]
Business Acquisition [Line Items]
Percentage Of Estimated Proved Reserves			6.00%
Permian Basin [Member] | Cash Payment [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties			3,091,000,000
Permian Basin [Member] | Amount allocated to midstream and other fixed assets [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		42,000,000
Permian Basin [Member] | Subsequent Payment [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties			466,000,000
Chitwood Knox [Member]
Business Acquisition [Line Items]
Number Of Net Acres			40,000
Proceeds from divestitures of proved and unproved properties			540,000,000
Utica [Member]
Business Acquisition [Line Items]
Number Of Net Acres			72,000
Proceeds from divestitures of proved and unproved properties			358,000,000
XTO Energy Inc. [Member]
Business Acquisition [Line Items]
Number Of Net Acres			60,000
Proceeds from divestitures of proved and unproved properties			$572,000,000
Compressor [Member] | Hilcorp Energy [Member]
Business Acquisition [Line Items]
Equipment, Number of Units	61

SpinOff_of_Oilfield_Services_B1

Spin-Off of Oilfield Services Business Narrative (Details) (USD $)	12 Months Ended			6 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2014	Apr. 24, 2014
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Long-term Debt, Gross	$11,756
Operating Leases, Future Minimum Payments Due	11
Spin-off of oilfield services business (Note 13)	-270	0	0
Restructuring and other termination costs	7	248	7
Minimum [Member] | Drilling Rig Leases [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Lease Term	3 months
Maximum [Member] | Drilling Rig Leases [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Lease Term	3 years
Senior Notes [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Long-term Debt, Gross	3,000				3,000
Senior Notes [Member] | Minimum [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Long-term Debt, Gross	50
Senior Notes [Member] | Maximum [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Long-term Debt, Gross	75
Seven Seven Energy Inc. [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Stockholders' Equity Note, Stock Split				one share of SSE common stock and cash in lieu of fractional shares for every 14 shares of Chesapeake common stock
Seven Seven Energy Inc. [Member] | Drilling Rig Leases [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Operating Leases, Future Minimum Payments Due	410
Seven Seven Energy Inc. [Member] | Minimum [Member] | Drilling Rig Leases [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Lease Term	3 months
Seven Seven Energy Inc. [Member] | Maximum [Member] | Drilling Rig Leases [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Lease Term	3 years
Seven Seven Energy Inc. [Member] | Secured Debt [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Long-term Debt, Gross				400
Seven Seven Energy Inc. [Member] | Senior Notes [Member] | 6.5% Senior Notes Due 2022 [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Long-term Debt, Gross				500
Debt Instrument, Interest Rate, Stated Percentage				6.50%
General Partner Distributions				391
Seven Seven Energy Inc. [Member] | Spinoff [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Deferred Tax Liabilities, Deferred Expense	151
Restructuring and other termination costs	15	0	0
Seven Seven Energy Inc. [Member] | Seven Seven Energy Inc. Revolving Bank Credit Facility [Member]
Assets Disposed of by Method Other than Sale, in Period of Disposition [Line Items]
Borrowing capacity				275

Investments_Schedule_of_Invest

Investments - Schedule of Investments Table (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Schedule of Equity Method Investments [Line Items]
Investments	$265	$477
FTS International, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	30.00%	30.00%
Investments	116	138
Sundrop Fuels Inc [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	56.00%	56.00%
Investments	130	135
Chaparral Energy, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	0.00%	20.00%
Investments	0	143
Other Investment Companies [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	0.00%	0.00%
Investments	$19	$61

Investments_Narrative_Details

Investments - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments	$239	$115	$2,000
Investments	265	477
FTS International, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Investment Adjustments	32
Equity method accretion adjustments	10
Excess carrying value of investment over underlying equity in net assets	44
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity Attributable to Goodwill	14
Investments	116	138
Equity Method Investment, Ownership Percentage	30.00%	30.00%
Sundrop Fuels Inc [Member]
Schedule of Equity Method Investments [Line Items]
Equity Investment Adjustments	21
Excess carrying value of investment over underlying equity in net assets	78
Interest Costs Capitalized	16
Investments	130	135
Equity Method Investment, Ownership Percentage	56.00%	56.00%
Chaparral Energy, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Net Sales Proceeds	209
Equity Method Investment, Realized Gain (Loss) on Disposal	73
Investments	0	143
Equity Method Investment, Ownership Percentage	0.00%	20.00%
Clean Energy Fuels Corp [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Realized Gain (Loss) on Disposal		3
Cost Method Investments		100
Proceeds from Cost Method Investment		85
Other than Temporary Impairment Losses, Investments		15
Proceeds from sales of investments		13
Other Commitment		50
Gastar Exploration Ltd [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Net Sales Proceeds		10
Chesapeake Midstream Partners Lp [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Realized Gain (Loss) on Disposal			1,032
Proceeds from sales of investments			2,000
Glass Mountain Pipeline Limited Liability Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Realized Gain (Loss) on Disposal			62
Proceeds from sales of investments			99
Additional Assets Pipeline Length			210
Equity Method Investment, Ownership Percentage			50.00%
Other Investments [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Realized Gain (Loss) on Disposal	-6	5
Proceeds from sales of investments	$30	$6

Variable_Interest_Entities_Nar

Variable Interest Entities - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Variable Interest Entity [Line Items]
Cash and cash equivalents	$4,108	$837	$287	$351
Short-term derivative assets	879	0
Proved natural gas and oil properties	58,594	56,157
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	39,043	37,161
Other Liabilities, Current	3,061	3,511
Variable Interest Entities, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	1	1
Short-term derivative assets	16	0
Proved natural gas and oil properties	488	488
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	251	168
Other Liabilities, Current	15	22
Corporate Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Percentage of acquisition	10.00%
Carrying value of investment	9
Corporate Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. [Member] | Minimum [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Royalty percentage minimum	7.00%
Royalty percentage maximum	7.00%
Corporate Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. [Member] | Maximum [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Other Commitment	25
Royalty percentage minimum	22.50%
Royalty percentage maximum	22.50%
Partner Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Percentage of acquisition	90.00%
Partner Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. [Member] | Maximum [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Other Commitment	$225

Other_Property_and_Equipment_H

Other Property and Equipment - Held for Use and Useful Lives Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Other property and equipment	$3,083	$3,203
Oilfield services equipment	0	2,192
Property and equipment, other	3,083	5,395
Accumulated Depreciation And Amortization Of Other Property And Equipment	-804	-1,584
Other property and equipment, net	2,279	3,811
Building and Building Improvements [Member]
Property, Plant and Equipment [Line Items]
Buildings and Improvements, Gross	1,242	1,433
Property, Plant and Equipment, Estimated Useful Lives	Oct-39
Natural Gas Compressors [Member]
Property, Plant and Equipment [Line Items]
Machinery and Equipment, Gross	551	368
Property, Plant and Equipment, Estimated Useful Lives	20-Mar
Land [Member]
Property, Plant and Equipment [Line Items]
Land	296	212
Property, Plant and Equipment, Estimated Useful Lives	0
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	218	292
Property, Plant and Equipment, Estimated Useful Lives	20
Exploration and Production Equipment [Member]
Property, Plant and Equipment [Line Items]
Oilfield services equipment	0	2,192
Property, Plant and Equipment, Estimated Useful Lives	15-Mar
Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Property and Equipment Other Miscellaneous	$776	$898
Property, Plant and Equipment, Estimated Useful Lives	20-Feb

Other_Property_and_Equipment_N1

Other Property and Equipment Net Gains (Losses) on Sales of Fixed Assets Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	$199	$302	$267
Natural Gas Compressors [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	195	0	0
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	-8	326	286
Exploration and Production Equipment [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	7	-2	-10
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	2	-27	-7
Other Assets [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	$3	$5	($2)

Other_Property_and_Equipment_A

Other Property and Equipment - Assets Held For Sale Table (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Long Lived Assets Held-for-sale [Line Items]
Assets Held for Sale	$93	$730
Land and Building [Member]
Long Lived Assets Held-for-sale [Line Items]
Assets Held for Sale	93	405
Compressor [Member]
Long Lived Assets Held-for-sale [Line Items]
Assets Held for Sale	0	285
Exploration and Production Equipment [Member]
Long Lived Assets Held-for-sale [Line Items]
Assets Held for Sale	0	29
Gathering and Processing Equipment [Member]
Long Lived Assets Held-for-sale [Line Items]
Assets Held for Sale	$0	$11

Other_Property_and_Equipment_N2

Other Property and Equipment - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	$199,000,000	$302,000,000	$267,000,000
Gathering Fee Escalation Rate	15.00%
Reclassification from held for sale to held for use	120,000,000
Chesapeake Midstream Operating [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment			289,000,000
Proceeds from Divestiture of Businesses and Interests in Affiliates			2,160,000,000
Gathering Fee Escalation Rate			2.50%
Midstream Eagle Ford Oil Gathering Assets [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment			115,000,000
Gain (Loss) on Disposition of Property Plant Equipment			3,000,000
Midstream Eagle Ford Oil Gathering Assets [Member] | Scenario, Adjustment [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment			10,000,000
Compressor [Member] | Hilcorp Energy [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units	61
Proceeds from Sale of Property, Plant, and Equipment	19,000,000
Gain (Loss) on Disposition of Property Plant Equipment	6,000,000
Compressor [Member] | Exterran Partners L.P. [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units	499
Proceeds from Sale of Property, Plant, and Equipment	495,000,000
Gain (Loss) on Disposition of Property Plant Equipment	161,000,000
Compressor [Member] | Access Midstream Partners, L.P. [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units	102
Proceeds from Sale of Property, Plant, and Equipment	159,000,000
Gain (Loss) on Disposition of Property Plant Equipment	24,000,000
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	-8,000,000	326,000,000	286,000,000
Gathering and Processing Equipment [Member] | SemGroup Corporation [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment		306,000,000
Gain (Loss) on Disposition of Property Plant Equipment	141,000,000
Gathering and Processing Equipment [Member] | Granite Wash Midstream Gas Services, L.L.C. [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment		252,000,000
Gain (Loss) on Disposition of Property Plant Equipment		105,000,000
Gathering and Processing Equipment [Member] | Sale to Western Gas Partners, LP [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment		134,000,000
Gain (Loss) on Disposition of Property Plant Equipment		55,000,000
Exploration and Production Equipment [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	44,000,000
Gain (Loss) on Disposition of Property Plant Equipment	7,000,000	-2,000,000	-10,000,000
Crude Oil Hauling Equipment [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	23,000,000
Drilling Rigs [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units	14	23
Proceeds from Sale of Property, Plant, and Equipment	14,000,000
Gain (Loss) on Disposition of Property Plant Equipment	($14,000,000)

Impairments_Table_Details

Impairments Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	$88	$546	$340
Natural Gas Compressors [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	11	0	0
Gathering and Processing Equipment [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	13	22	6
Exploration and Production Equipment [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	23	71	60
Land and Building [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	18	366	248
Other Assets [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	$23	$87	$26

Impairments_Narrative_Details

Impairments - Narrative (Details) (USD $)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of oil and natural gas properties	$3,315	$0	$0	$3,315
Effects of Cash Flow Hedges Considered in Calculation Ceiling Limitation, Amount	279
Impairments of fixed assets and other		88	546	340
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down			69
Other Asset Impairment Charges			87
Net Acreage Shortfall [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Other Cost and Expense, Operating		22
Net Acreage Maintenance Commitment [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Other Asset Impairment Charges			2	26
Natural Gas Compressors [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other		11	0	0
Gathering and Processing Equipment [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other		13	22	6
Other Asset Impairment Charges			26
Drilling Rigs [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other		15
Leased Equipment Purchased		31
Payments to Acquire Property, Plant, and Equipment		140	141
Gain (Loss) on Contract Termination		8	22
Equipment, Number of Units		14	23
Impairment of Long-Lived Assets to be Disposed of			27	26
Drilling Rigs [Member] | Assets Held-for-sale [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Equipment, Number of Units			2
Leasehold Improvements [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Long-Lived Assets to be Disposed of			22
Tubular Goods [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Long-Lived Assets to be Disposed of				9
Land and Building [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other		18	366	248
Land and Building [Member] | In the Oklahoma City Area [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other			186
Land and Building [Member] | In the Fort Worth Area [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other			10
Land and Building [Member] | Outside the Oklahoma City Area [Member] [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other			15
Land and Building [Member] | Assets Held-for-sale [Member] | In the Fort Worth Area [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other			86
Property, Plant and Equipment, Other Types [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Other Asset Impairment Charges			16
Repurchase of Rigs [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Equipment, Number of Units				25
Repurchase of Rigs [Member] | Drilling Rigs [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Payments to Acquire Property, Plant, and Equipment				36
Gain (Loss) on Contract Termination				25
Selling and Marketing Expense [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Other Asset Impairment Charges			28
Third Party [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Gain (Loss) on Contract Termination			$15

Restructuring_and_Other_Termin1

Restructuring and Other Termination Benefits - Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Cash paid to purchase debt	$3,362	$2,141	$4,000
Severance Costs		50
Restructuring and other termination costs	7	248	7
Other, Including PSU's [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Restructuring and other termination costs	0	50	5
Seven Seven Energy Inc. [Member] | Spinoff [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Business Exit Costs	17	0	0
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options	5	0	0
Stock Granted, Value, Share-Based Compensation, Forfeited	-10	0	0
Cash paid to purchase debt	3	0	0
Restructuring and other termination costs	15	0	0
Workforce Reduction Plan [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Restructuring and Related Cost, Incurred Cost		66
Restructuring and other termination costs	0	66	0
Workforce Reduction Plan [Member] | Other Costs Associated with Retirement [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Restructuring and Related Cost, Incurred Cost	0	1	0
Workforce Reduction Plan [Member] | Salary Expense [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Restructuring and Related Cost, Incurred Cost	0	20	0
Workforce Reduction Plan [Member] | Acceleration of Stock-Based Compensation Awards [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Restructuring and Related Cost, Incurred Cost	0	45	0
VSP Program [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs		63
Restructuring and other termination costs	0	63	2
VSP Program [Member] | Cash Salary and Bonus Costs [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	33	1
VSP Program [Member] | Acceleration of Restricted Stock Awards [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	29	1
VSP Program [Member] | Other Costs Associated with Retirement [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	1	0
Former CEO [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs		69
Restructuring and other termination costs	-8	69	0
Former CEO [Member] | Cash Salary and Bonus Costs [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	11	0
Former CEO [Member] | Claw-Back Bonus [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	11	0
Former CEO [Member] | Acceleration of Restricted Stock Awards [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	0	22	0
Former CEO [Member] | Acceleration of Performance Shares [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	-8	18	0
Former CEO [Member] | Other Costs Associated with Retirement [Member]
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]
Severance Costs	$0	$7	$0

Restructuring_and_Other_Termin2

Restructuring and Other Termination Benefits - Narrative (Details) (USD $)	1 Months Ended	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 30, 2012	Feb. 28, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Employee	Employee
Defined Benefit Plan Disclosure [Line Items]
Restructuring and other termination costs			$7	$248	$7
Restructuring and Related Cost, Number of Positions Eliminated				900
Severance Costs				50
Former CEO [Member]
Defined Benefit Plan Disclosure [Line Items]
Restructuring and other termination costs			-8	69	0
Severance Costs				69
Workforce Reduction Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Restructuring and other termination costs			0	66	0
Restructuring and Related Cost, Incurred Cost				66
VSP Program [Member]
Defined Benefit Plan Disclosure [Line Items]
Restructuring and other termination costs			0	63	2
Restructuring and Related Cost, Number of Positions Eliminated	275	211
Severance Costs				63
Seven Seven Energy Inc. [Member] | Spinoff [Member]
Defined Benefit Plan Disclosure [Line Items]
Restructuring and other termination costs			$15	$0	$0

Fair_Value_Measurements_Assets

Fair Value Measurements - Assets and Liabilities Table (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	($1)	($2)
Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	57	80
Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	-58	-82
Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	-1	-2
Fair Value, Inputs, Level 1 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	57	80
Fair Value, Inputs, Level 1 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	-58	-82
Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	0	0
Fair Value, Inputs, Level 2 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 2 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	0	0
Fair Value, Inputs, Level 3 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	$0	$0

Asset_Retirement_Obligation_Ta1

Asset Retirement Obligation Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation Beginning of Period	$465	$405	$375
Asset Retirement Obligation, Liabilities Incurred	29	20
Asset Retirement Obligation, Revision of Estimate	101	8
Asset Retirement Obligation, Liabilities Settled	-92	-20
Asset Retirement Obligation, Accretion Expense	22	22
Asset Retirement Obligation End of Period	465	405	375
Asset Retirement Obligation, Current	18	0
Asset retirement obligations, net of current portion	$447	$405

Major_Customers_and_Segment_In2

Major Customers and Segment Information - Table (Details) (USD $)	1 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Total Revenues		$20,951,000,000	$17,506,000,000	$12,316,000,000
Unrealized Gain (Loss) on Derivatives		-1,394,000,000	-228,000,000	-561,000,000
Depreciation, depletion and amortization		2,915,000,000	2,903,000,000	2,811,000,000
Impairment of oil and natural gas properties	3,315,000,000	0	0	3,315,000,000
Impairments of fixed assets and other		88,000,000	546,000,000	340,000,000
Gain (Loss) on Disposition of Property Plant Equipment		-199,000,000	-302,000,000	-267,000,000
Interest expense		-89,000,000	-227,000,000	-77,000,000
Losses on investments		-80,000,000	-226,000,000	-103,000,000
Net gain (loss) on sales of investments		67,000,000	-7,000,000	1,092,000,000
Losses on purchases of debt		-197,000,000	-193,000,000	-200,000,000
Income (Loss) Before Income Taxes		3,200,000,000	1,442,000,000	-974,000,000
Total Assets		40,751,000,000	41,782,000,000	41,611,000,000
Payments to Acquire Productive Assets		6,667,000,000	7,190,000,000	14,108,000,000
Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues		8,180,000,000	7,052,000,000	6,278,000,000
Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues		12,225,000,000	9,559,000,000	5,431,000,000
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues		516,000,000	879,000,000	602,000,000
Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues		30,000,000	16,000,000	5,000,000
Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Total Revenues		20,951,000,000	17,506,000,000	12,316,000,000
Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues		0	0	0
Operating Segments [Member] | Reportable Subsegments [Member] | Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues		8,180,000,000	7,052,000,000	6,278,000,000
Unrealized Gain (Loss) on Derivatives		-1,394,000,000	-228,000,000	-561,000,000
Depreciation, depletion and amortization		2,756,000,000	2,674,000,000	2,624,000,000
Impairment of oil and natural gas properties				3,315,000,000
Impairments of fixed assets and other		22,000,000	27,000,000	28,000,000
Gain (Loss) on Disposition of Property Plant Equipment		-2,000,000	2,000,000	14,000,000
Interest expense		-709,000,000	-918,000,000	-47,000,000
Losses on investments		2,000,000	3,000,000	0
Net gain (loss) on sales of investments		-6,000,000	0	-2,000,000
Losses on purchases of debt		197,000,000	-193,000,000	-200,000,000
Income (Loss) Before Income Taxes		2,874,000,000	2,997,000,000	-1,798,000,000
Total Assets		35,381,000,000	35,341,000,000	37,004,000,000
Payments to Acquire Productive Assets		6,173,000,000	6,198,000,000	12,044,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues		20,790,000,000	17,129,000,000	10,895,000,000
Unrealized Gain (Loss) on Derivatives		0	0	0
Depreciation, depletion and amortization		38,000,000	46,000,000	54,000,000
Impairment of oil and natural gas properties				0
Impairments of fixed assets and other		24,000,000	50,000,000	6,000,000
Gain (Loss) on Disposition of Property Plant Equipment		-187,000,000	-329,000,000	-298,000,000
Interest expense		-21,000,000	-24,000,000	-20,000,000
Losses on investments		0	0	49,000,000
Net gain (loss) on sales of investments		0	0	1,094,000,000
Losses on purchases of debt		0	0	0
Income (Loss) Before Income Taxes		326,000,000	511,000,000	1,665,000,000
Total Assets		1,978,000,000	2,430,000,000	2,291,000,000
Payments to Acquire Productive Assets		298,000,000	299,000,000	852,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues		1,060,000,000	2,188,000,000	1,917,000,000
Unrealized Gain (Loss) on Derivatives		0	0	0
Depreciation, depletion and amortization		145,000,000	289,000,000	232,000,000
Impairment of oil and natural gas properties				0
Impairments of fixed assets and other		23,000,000	75,000,000	60,000,000
Gain (Loss) on Disposition of Property Plant Equipment		-8,000,000	-1,000,000	10,000,000
Interest expense		-42,000,000	-82,000,000	-76,000,000
Losses on investments		-6,000,000	-1,000,000	0
Net gain (loss) on sales of investments		0	0	0
Losses on purchases of debt		0	0	0
Income (Loss) Before Income Taxes		-16,000,000	-51,000,000	112,000,000
Total Assets		0	2,018,000,000	2,115,000,000
Payments to Acquire Productive Assets		158,000,000	272,000,000	658,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues		30,000,000	29,000,000	21,000,000
Unrealized Gain (Loss) on Derivatives		0	0	0
Depreciation, depletion and amortization		42,000,000	49,000,000	46,000,000
Impairment of oil and natural gas properties				0
Impairments of fixed assets and other		19,000,000	394,000,000	246,000,000
Gain (Loss) on Disposition of Property Plant Equipment		-2,000,000	26,000,000	7,000,000
Interest expense		3,000,000	-74,000,000	-364,000,000
Losses on investments		-76,000,000	-229,000,000	-152,000,000
Net gain (loss) on sales of investments		73,000,000	-7,000,000	0
Losses on purchases of debt		0	0	0
Income (Loss) Before Income Taxes		-30,000,000	-727,000,000	-478,000,000
Total Assets		4,283,000,000	5,750,000,000	2,529,000,000
Payments to Acquire Productive Assets		38,000,000	421,000,000	554,000,000
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues		0	0	0
Intersegment Eliminations [Member] | Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues		0	0	0
Intersegment Eliminations [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues		8,565,000,000	7,570,000,000	5,464,000,000
Intersegment Eliminations [Member] | Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues		544,000,000	1,309,000,000	1,315,000,000
Intersegment Eliminations [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues		0	13,000,000	16,000,000
Intersegment Eliminations [Member] | Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Total Revenues		9,109,000,000	8,892,000,000	6,795,000,000
Unrealized Gain (Loss) on Derivatives		0	0	0
Depreciation, depletion and amortization		-66,000,000	-155,000,000	-145,000,000
Impairment of oil and natural gas properties				0
Impairments of fixed assets and other		0	0	0
Gain (Loss) on Disposition of Property Plant Equipment		0	0	0
Interest expense		680,000,000	871,000,000	430,000,000
Losses on investments		0	1,000,000	0
Net gain (loss) on sales of investments		0	0	0
Losses on purchases of debt		0	0	0
Income (Loss) Before Income Taxes		46,000,000	-1,288,000,000	-475,000,000
Total Assets		-891,000,000	-3,757,000,000	-2,328,000,000
Payments to Acquire Productive Assets		0	0	0
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues		$9,109,000,000	$8,892,000,000	$6,795,000,000

Major_Customers_and_Segment_In3

Major Customers and Segment Information - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Segment
Segment Reporting Information [Line Items]
Segment Reporting, Disclosure of Major Customers		no
Concentration Risk, Percentage		10.00%
Number of reportable segments	2
Total Revenues	$20,951	$17,506	$12,316
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0
Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	12,225	9,559	5,431
Marketing, Gathering And Compression [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	8,565	7,570	5,464
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	516	879	602
Oilfield Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	$544	$1,309	$1,315
ExxonMobil [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	12.00%		11.00%

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information - Balance Sheet Table (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
CURRENT ASSETS:
Cash and cash equivalents	$4,108	$837	$287	$351
Restricted cash	38	75
Other current assets	207	299
Intercompany receivable, net	0	0
Total Current Assets	7,468	3,656
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	30,143	32,593
Other property and equipment, net	2,279	3,811
Property and equipment held for sale, net	93	730
Total Property and Equipment, Net	32,515	37,134
LONG-TERM ASSETS:
Other long-term assets	497	511
Investments in subsidiaries and intercompany advances	0	0
Total Assets	40,751	41,782	41,611
CURRENT LIABILITIES:
Other Liabilities, Current	3,061	3,511
Intercompany payable, net	0	0
Current Liabilities	5,863	5,515
LONG-TERM LIABILITIES:
Long-term debt, net	11,154	12,886
Deferred income tax liabilities	4,185	3,407
Other long-term liabilities	679	984
Total Long-Term Liabilities	16,683	18,127
EQUITY:
Chesapeake stockholders’ equity	16,903	15,995
Noncontrolling interests	1,302	2,145
Total Equity	18,205	18,140	17,896
TOTAL LIABILITIES AND EQUITY	40,751	41,782
Parent Company Member]
CURRENT ASSETS:
Cash and cash equivalents	4,100	799	228	2
Restricted cash	0	0
Other current assets	55	103
Intercompany receivable, net	24,527	25,549
Total Current Assets	28,682	26,451
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	0	0
Other property and equipment, net	0	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	0	0
LONG-TERM ASSETS:
Other long-term assets	153	111
Investments in subsidiaries and intercompany advances	126	2,169
Total Assets	28,961	28,731
CURRENT LIABILITIES:
Other Liabilities, Current	792	300
Intercompany payable, net	0	0
Current Liabilities	792	300
LONG-TERM LIABILITIES:
Long-term debt, net	11,154	11,831
Deferred income tax liabilities	0	209
Other long-term liabilities	112	396
Total Long-Term Liabilities	11,266	12,436
EQUITY:
Chesapeake stockholders’ equity	16,903	15,995
Noncontrolling interests	0	0
Total Equity	16,903	15,995
TOTAL LIABILITIES AND EQUITY	28,961	28,731
Guarantor Subsidiaries [Member]
CURRENT ASSETS:
Cash and cash equivalents	2	8	0	0
Restricted cash	0	37
Other current assets	3,174	2,465
Intercompany receivable, net	0	0
Total Current Assets	3,176	2,510
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	28,358	30,933
Other property and equipment, net	2,276	2,360
Property and equipment held for sale, net	93	701
Total Property and Equipment, Net	30,727	33,994
LONG-TERM ASSETS:
Other long-term assets	618	1,161
Investments in subsidiaries and intercompany advances	467	-209
Total Assets	34,988	37,456
CURRENT LIABILITIES:
Other Liabilities, Current	5,084	5,262
Intercompany payable, net	24,937	26,409
Current Liabilities	30,021	31,671
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	3,751	2,338
Other long-term liabilities	1,090	1,278
Total Long-Term Liabilities	4,841	3,616
EQUITY:
Chesapeake stockholders’ equity	126	2,169
Noncontrolling interests	0	0
Total Equity	126	2,169
TOTAL LIABILITIES AND EQUITY	34,988	37,456
Non-Guarantor Subsidiaries [Member]
CURRENT ASSETS:
Cash and cash equivalents	84	38	59	349
Restricted cash	38	38
Other current assets	93	524
Intercompany receivable, net	341	860
Total Current Assets	556	1,460
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	1,112	1,471
Other property and equipment, net	3	1,452
Property and equipment held for sale, net	0	29
Total Property and Equipment, Net	1,115	2,952
LONG-TERM ASSETS:
Other long-term assets	26	96
Investments in subsidiaries and intercompany advances	0	0
Total Assets	1,697	4,508
CURRENT LIABILITIES:
Other Liabilities, Current	68	309
Intercompany payable, net	0	0
Current Liabilities	68	309
LONG-TERM LIABILITIES:
Long-term debt, net	0	1,055
Deferred income tax liabilities	234	773
Other long-term liabilities	142	504
Total Long-Term Liabilities	376	2,332
EQUITY:
Chesapeake stockholders’ equity	1,253	1,867
Noncontrolling interests	0	0
Total Equity	1,253	1,867
TOTAL LIABILITIES AND EQUITY	1,697	4,508
Eliminations [Member]
CURRENT ASSETS:
Cash and cash equivalents	-78	-8	0	0
Restricted cash	0	0
Other current assets	0	-348
Intercompany receivable, net	-24,868	-26,409
Total Current Assets	-24,946	-26,765
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	673	189
Other property and equipment, net	0	-1
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	673	188
LONG-TERM ASSETS:
Other long-term assets	-29	-376
Investments in subsidiaries and intercompany advances	-593	-1,960
Total Assets	-24,895	-28,913
CURRENT LIABILITIES:
Other Liabilities, Current	-81	-356
Intercompany payable, net	-24,937	-26,409
Current Liabilities	-25,018	-26,765
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	200	87
Other long-term liabilities	0	-344
Total Long-Term Liabilities	200	-257
EQUITY:
Chesapeake stockholders’ equity	-1,379	-4,036
Noncontrolling interests	1,302	2,145
Total Equity	-77	-1,891
TOTAL LIABILITIES AND EQUITY	-24,895	-28,913
Consolidated Entities [Member]
CURRENT ASSETS:
Other current assets	3,322	2,744
LONG-TERM ASSETS:
Other long-term assets	768	992
CURRENT LIABILITIES:
Other Liabilities, Current	5,863	5,515
LONG-TERM LIABILITIES:
Other long-term liabilities	$1,344	$1,834

Condensed_Consolidating_Financ3

Condensed Consolidating Financial Information -Statement Of Operations Table (Details) (USD $)	1 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES
Oil, natural gas and NGL		$8,180	$7,052	$6,278
Marketing, gathering and compression		12,225	9,559	5,431
Oilfield services		546	895	607
Total Revenues		20,951	17,506	12,316
OPERATING EXPENSES
Oil, natural gas and NGL production		1,208	1,159	1,304
Production taxes		232	229	188
Marketing, gathering and compression		12,236	9,461	5,312
Oilfield services		431	736	465
General and administrative		322	457	535
Restructuring and other termination costs		7	248	7
Provision for legal contingencies		234	0	0
Oil, natural gas and NGL depreciation, depletion and amortization		2,683	2,589	2,507
Depreciation and amortization of other assets		232	314	304
Impairment of oil and natural gas properties	3,315	0	0	3,315
Impairments of fixed assets and other		88	546	340
Net gains on sales of fixed assets		-199	-302	-267
Total Operating Expenses		17,474	15,437	14,010
INCOME FROM OPERATIONS		3,477	2,069	-1,694
OTHER INCOME (EXPENSE):
Interest expense		-89	-227	-77
Losses on investments		-80	-226	-103
Net gain (loss) on sales of investments		67	-7	1,092
Losses on purchases of debt		-197	-193	-200
Other income		22	26	8
Equity in net earnings (losses) of subsidiary		0	0
Total Other Expense		-277	-627	720
Income (Loss) Before Income Taxes		3,200	1,442	-974
INCOME TAX EXPENSE (BENEFIT)		1,144	548	-380
NET INCOME		2,056	894	-594
Net income attributable to noncontrolling interests		-139	-170	-175
Net income (loss) attributable to Chesapeake		1,917	724	-769
Other Comprehensive Income (Loss), Net of Tax		19	20	-16
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE		1,936	744	-785
Parent Company Member]
REVENUES
Oil, natural gas and NGL		0	0	0
Marketing, gathering and compression		0	0	0
Oilfield services		0	0	0
Total Revenues		0	0	0
OPERATING EXPENSES
Oil, natural gas and NGL production		0	0	0
Production taxes		0	0	0
Marketing, gathering and compression		0	0	0
Oilfield services		0	0	0
General and administrative		0	0	0
Restructuring and other termination costs		0	0	0
Provision for legal contingencies		100
Oil, natural gas and NGL depreciation, depletion and amortization		0	0	0
Depreciation and amortization of other assets		0	0	0
Impairment of oil and natural gas properties		0	0	0
Impairments of fixed assets and other		0	0	0
Net gains on sales of fixed assets		0	0	0
Total Operating Expenses		100	0	0
INCOME FROM OPERATIONS		-100	0	0
OTHER INCOME (EXPENSE):
Interest expense		-657	-921	-879
Losses on investments		0	0	0
Net gain (loss) on sales of investments		0	0	0
Losses on purchases of debt		-195	-70	-200
Other income		502	3,979	819
Equity in net earnings (losses) of subsidiary		2,206	-1,129	-610
Total Other Expense		1,856	1,859	-870
Income (Loss) Before Income Taxes		1,756	1,859	-870
INCOME TAX EXPENSE (BENEFIT)		-161	1,135	-101
NET INCOME		1,917	724	-769
Net income attributable to noncontrolling interests		0	0	0
Net income (loss) attributable to Chesapeake		1,917	724	-769
Other Comprehensive Income (Loss), Net of Tax		1	3	6
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE		1,918	727	-763
Guarantor Subsidiaries [Member]
REVENUES
Oil, natural gas and NGL		7,765	6,439	5,920
Marketing, gathering and compression		12,220	9,547	5,218
Oilfield services		41	221	154
Total Revenues		20,026	16,207	11,292
OPERATING EXPENSES
Oil, natural gas and NGL production		1,166	1,112	1,278
Production taxes		227	222	182
Marketing, gathering and compression		12,232	9,455	5,197
Oilfield services		53	239	301
General and administrative		273	375	431
Restructuring and other termination costs		4	244	5
Provision for legal contingencies		134
Oil, natural gas and NGL depreciation, depletion and amortization		2,523	2,336	2,353
Depreciation and amortization of other assets		153	180	187
Impairment of oil and natural gas properties		0	-2	3,192
Impairments of fixed assets and other		65	417	275
Net gains on sales of fixed assets		-192	-301	-269
Total Operating Expenses		16,638	14,277	13,132
INCOME FROM OPERATIONS		3,388	1,930	-1,840
OTHER INCOME (EXPENSE):
Interest expense		-37	-4	45
Losses on investments		-77	-225	-167
Net gain (loss) on sales of investments		67	-7	29
Losses on purchases of debt		-2	-123	0
Other income		198	-603	203
Equity in net earnings (losses) of subsidiary		-258	-383	436
Total Other Expense		-109	-1,345	546
Income (Loss) Before Income Taxes		3,279	585	-1,294
INCOME TAX EXPENSE (BENEFIT)		1,264	370	-675
NET INCOME		2,015	215	-619
Net income attributable to noncontrolling interests		0	0	0
Net income (loss) attributable to Chesapeake		2,015	215	-619
Other Comprehensive Income (Loss), Net of Tax		18	19	-22
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE		2,033	234	-641
Non-Guarantor Subsidiaries [Member]
REVENUES
Oil, natural gas and NGL		418	553	351
Marketing, gathering and compression		5	12	212
Oilfield services		983	1,836	1,553
Total Revenues		1,406	2,401	2,116
OPERATING EXPENSES
Oil, natural gas and NGL production		42	47	26
Production taxes		5	7	6
Marketing, gathering and compression		4	6	115
Oilfield services		769	1,434	1,096
General and administrative		49	83	105
Restructuring and other termination costs		3	4	2
Provision for legal contingencies		0
Oil, natural gas and NGL depreciation, depletion and amortization		162	253	154
Depreciation and amortization of other assets		143	281	266
Impairment of oil and natural gas properties		349	313	123
Impairments of fixed assets and other		23	129	65
Net gains on sales of fixed assets		-7	-1	2
Total Operating Expenses		1,542	2,556	1,960
INCOME FROM OPERATIONS		-136	-155	156
OTHER INCOME (EXPENSE):
Interest expense		-42	-85	-84
Losses on investments		-5	-1	55
Net gain (loss) on sales of investments		0	0	1,063
Losses on purchases of debt		0	0	0
Other income		-2	13	14
Equity in net earnings (losses) of subsidiary		0	0	0
Total Other Expense		-49	-73	1,048
Income (Loss) Before Income Taxes		-185	-228	1,204
INCOME TAX EXPENSE (BENEFIT)		-66	-87	470
NET INCOME		-119	-141	734
Net income attributable to noncontrolling interests		0	0	0
Net income (loss) attributable to Chesapeake		-119	-141	734
Other Comprehensive Income (Loss), Net of Tax		0	-2	0
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE		-119	-143	734
Eliminations [Member]
REVENUES
Oil, natural gas and NGL		-3	60	7
Marketing, gathering and compression		0	0	1
Oilfield services		-478	-1,162	-1,100
Total Revenues		-481	-1,102	-1,092
OPERATING EXPENSES
Oil, natural gas and NGL production		0	0	0
Production taxes		0	0	0
Marketing, gathering and compression		0	0	0
Oilfield services		-391	-937	-932
General and administrative		0	-1	-1
Restructuring and other termination costs		0	0	0
Provision for legal contingencies		0
Oil, natural gas and NGL depreciation, depletion and amortization		-2	0	0
Depreciation and amortization of other assets		-64	-147	-149
Impairment of oil and natural gas properties		-349	-311	0
Impairments of fixed assets and other		0	0	0
Net gains on sales of fixed assets		0	0	0
Total Operating Expenses		-806	-1,396	-1,082
INCOME FROM OPERATIONS		325	294	-10
OTHER INCOME (EXPENSE):
Interest expense		647	783	841
Losses on investments		2	0	9
Net gain (loss) on sales of investments		0	0	0
Losses on purchases of debt		0	0	0
Other income		-676	-3,363	-1,028
Equity in net earnings (losses) of subsidiary		-1,948	1,512	174
Total Other Expense		-1,975	-1,068	-4
Income (Loss) Before Income Taxes		-1,650	-774	-14
INCOME TAX EXPENSE (BENEFIT)		107	-870	-74
NET INCOME		-1,757	96	60
Net income attributable to noncontrolling interests		-139	-170	-175
Net income (loss) attributable to Chesapeake		-1,896	-74	-115
Other Comprehensive Income (Loss), Net of Tax		0	0	0
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE		($1,896)	($74)	($115)

Condensed_Consolidating_Financ4

Condensed Consolidating Financial Information - Statements Of Cash Flows Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	$4,634	$4,614	$2,837
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	-4,581	-5,604	-8,930
Acquisitions of proved and unproved properties	-1,311	-1,032	-3,161
Proceeds from divestitures of proved and unproved properties	5,813	3,467	5,884
Additions to other property and equipment	-726	-972	-2,651
Other	-3	4	-1
Net Cash Used In Investing Activities	454	-2,967	-4,984
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	7,406	7,669	20,318
Payments on credit facilities borrowings	-7,788	-7,682	-21,650
Proceeds from issuance of senior notes, net of discount and offering costs	3,460
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	394
Cash paid to purchase debt	-3,362	-2,141	-4,000
Proceeds from sales of noncontrolling interests	0	6	1,077
Other	-34	-105	-251
Intercompany advances, net	0	0	0
Net Cash Provided By (Used In) Financing Activities	-1,817	-1,097	2,083
Net increase (decrease) in cash and cash equivalents	3,271	550	-64
Cash and cash equivalents, beginning of period	837	287	351
Cash and cash equivalents, end of period	4,108	837	287
Parent Company Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	0	0	0
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0	0
Acquisitions of proved and unproved properties	0	0	0
Proceeds from divestitures of proved and unproved properties	0	0	0
Additions to other property and equipment	0	0	0
Other	0	0	0
Net Cash Used In Investing Activities	0	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	0	0	0
Payments on credit facilities borrowings	0	0	0
Proceeds from issuance of senior notes, net of discount and offering costs	2,966	2,274	1,263
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	0		5,722
Cash paid to purchase debt	-3,362	-2,141	-4,000
Proceeds from sales of noncontrolling interests		0	0
Other	-439	1,819	-477
Intercompany advances, net	4,136	-1,381	-2,282
Net Cash Provided By (Used In) Financing Activities	3,301	571	226
Net increase (decrease) in cash and cash equivalents	3,301	571	226
Cash and cash equivalents, beginning of period	799	228	2
Cash and cash equivalents, end of period	4,100	799	228
Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	4,201	4,218	1,711
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	-4,445	-4,838	-8,605
Acquisitions of proved and unproved properties	-1,306	-1,378	-3,622
Proceeds from divestitures of proved and unproved properties	5,812	3,466	5,884
Additions to other property and equipment	-480	-271	-1,736
Other	1,199	246	5,083
Net Cash Used In Investing Activities	780	-2,775	-2,996
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	6,689	6,452	18,930
Payments on credit facilities borrowings	-6,689	-6,452	-20,651
Proceeds from issuance of senior notes, net of discount and offering costs	0	0	0
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	0		0
Cash paid to purchase debt	0	0	0
Proceeds from sales of noncontrolling interests		0	63
Other	-1,278	-2,897	-299
Intercompany advances, net	-3,709	1,462	3,242
Net Cash Provided By (Used In) Financing Activities	-4,987	-1,435	1,285
Net increase (decrease) in cash and cash equivalents	-6	8	0
Cash and cash equivalents, beginning of period	8	0	0
Cash and cash equivalents, end of period	2	8	0
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	462	439	1,182
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	-136	-766	-325
Acquisitions of proved and unproved properties	-5	346	461
Proceeds from divestitures of proved and unproved properties	1	1	0
Additions to other property and equipment	-246	-701	-915
Other	60	765	-316
Net Cash Used In Investing Activities	-326	-355	-1,095
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	717	1,217	1,388
Payments on credit facilities borrowings	-1,099	-1,230	-999
Proceeds from issuance of senior notes, net of discount and offering costs	494	0	0
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	394		0
Cash paid to purchase debt	0	0	0
Proceeds from sales of noncontrolling interests		6	1,014
Other	-169	-17	-820
Intercompany advances, net	-427	-81	-960
Net Cash Provided By (Used In) Financing Activities	-90	-105	-377
Net increase (decrease) in cash and cash equivalents	46	-21	-290
Cash and cash equivalents, beginning of period	38	59	349
Cash and cash equivalents, end of period	84	38	59
Eliminations [Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	-29	-43	-56
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0	0
Acquisitions of proved and unproved properties	0	0	0
Proceeds from divestitures of proved and unproved properties	0	0	0
Additions to other property and equipment	0	0	0
Other	0	163	-893
Net Cash Used In Investing Activities	0	163	-893
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	0	0	0
Payments on credit facilities borrowings	0	0	0
Proceeds from issuance of senior notes, net of discount and offering costs	0	0	0
Proceeds from issuance of oilfield services term loan, net of discount and offering costs	0		0
Cash paid to purchase debt	0	0	0
Proceeds from sales of noncontrolling interests		0	0
Other	-41	-128	949
Intercompany advances, net	0	0	0
Net Cash Provided By (Used In) Financing Activities	-41	-128	949
Net increase (decrease) in cash and cash equivalents	-70	-8	0
Cash and cash equivalents, beginning of period	-8	0	0
Cash and cash equivalents, end of period	-78	-8	0
Chesapeake Energy [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior notes, net of discount and offering costs	2,966	2,274	1,263
Proceeds from issuance of oilfield services term loan, net of discount and offering costs			5,722
Consolidated Entities [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Other	1,259	1,174	3,874
CASH FLOWS FROM FINANCING ACTIVITIES:
Other	($1,927)	($1,223)	($647)

Condensed_Consolidating_Financ5

Condensed Consolidating Financial Information Condensed Consolidating Financial Information Narrative (Details)	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	50.00%
Senior Notes [Member]
Condensed Financial Statements, Captions [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	100.00%