Pressburg (ROAN) 10-K 27 Feb 14 2013 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
Document and Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Amendment Flag	'false	'	'
Entity Registrant Name	'Linn Energy, LLC	'	'
Entity Central Index Key	'0001326428	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Public Float	'	'	$6,583,133,742
Entity Common Stock, Shares Outstanding	'	331,287,217	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$52,171	$1,243
Accounts receivable - trade, net	488,202	371,333
Derivative instruments	176,130	350,695
Other current assets	99,437	88,157
Total current assets	815,940	811,428
Noncurrent assets	'	'
Oil and natural gas properties (successful efforts method)	17,888,559	11,611,330
Less accumulated depletion and amortization	-3,546,284	-2,025,656
Oil and natural gas properties, successful efforts method, net	14,342,275	9,585,674
Other property and equipment	647,882	469,188
Less accumulated depreciation	-110,939	-73,721
Other property and equipment, net	536,943	395,467
Derivative instruments	682,002	530,216
Other noncurrent assets	127,804	128,453
Noncurrent assets, excluding property, total	809,806	658,669
Total noncurrent assets	15,689,024	10,639,810
Total assets	16,504,964	11,451,238
Current liabilities	'	'
Accounts payable and accrued expenses	849,624	707,861
Derivative instruments	28,176	26
Other accrued liabilities	163,375	115,245
Current portion of long-term debt	211,558	0
Total current liabilities	1,252,733	823,132
Noncurrent liabilities	'	'
Credit facilities	2,733,175	1,180,000
Term loan	500,000	0
Senior notes, net	5,725,483	4,857,817
Derivative instruments	4,649	4,114
Other noncurrent liabilities	397,497	158,995
Total noncurrent liabilities	9,360,804	6,200,926
Commitments and contingencies (Note 11)	'	'
Unitholders' capital	'	'
329,661,161 units and 234,513,243 units issued and outstanding at December 31, 2013, and December 31, 2012, respectively	6,291,824	4,136,240
Accumulated income (deficit)	-400,397	290,940
Total unitholders' capital	5,891,427	4,427,180
Total liabilities and unitholders' capital	$16,504,964	$11,451,238

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]	'	'
Unitholder's capital: Units issued	329,661,161	234,513,243
Unitholders' capital: Units outstanding	329,661,161	234,513,243

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)

3 Months Ended

12 Months Ended

In Thousands, except Per Share data, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Revenues and other:

'

'

'

'

'

'

'

'

'

'

'

Oil, natural gas and natural gas liquids sales

$584,630

[1]

$537,671

$488,207

$462,732

$460,976

$444,082

$347,227

$348,895

$2,073,240

$1,601,180

$1,162,037

Gains on oil and natural gas derivatives

23,425

[1]

-63,931

326,733

-108,370

94,489

-411,405

439,647

2,031

177,857

124,762

449,940

Marketing revenues

'

'

'

'

'

'

'

'

54,171

37,393

5,868

Other revenues

'

'

'

'

'

'

'

'

26,387

10,905

4,609

Total revenues

629,208

[1]

494,562

838,825

369,060

571,225

48,328

800,597

354,090

2,331,655

1,774,240

1,622,454

Expenses:

'

'

'

'

'

'

'

'

'

'

'

Lease operating expenses

'

'

'

'

'

'

'

'

372,523

317,699

232,619

Transportation expenses

'

'

'

'

'

'

'

'

128,440

77,322

28,358

Marketing expenses

'

'

'

'

'

'

'

'

37,892

31,821

3,681

General and administrative expenses

'

'

'

'

'

'

'

'

236,271

173,206

133,272

Exploration costs

'

'

'

'

'

'

'

'

5,251

1,915

2,390

Depreciation, depletion and amortization

'

'

'

'

'

'

'

'

829,311

606,150

334,084

Impairment of long-lived assets

'

'

'

'

'

'

'

'

828,317

422,499

0

Taxes, other than income taxes

'

'

'

'

'

'

'

'

138,631

131,679

78,522

Losses on sale of assets and other, net

-10,597

[1]

-827

959

-3,172

-31

-16

2

-1,494

13,637

1,539

3,494

Total expenses

1,292,058

[1],[2]

420,803

[2]

385,540

[2]

478,235

[2]

656,221

[2]

376,323

[2]

460,655

[2]

269,092

[2]

2,590,273

1,763,830

816,420

Other income and (expenses):

'

'

'

'

'

'

'

'

'

'

'

Interest expense, net of amounts capitalized

'

'

'

'

'

'

'

'

-421,137

-379,937

-259,725

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

-5,304

0

-94,612

Other, net

'

'

'

'

'

'

'

'

-8,477

-14,299

-7,792

Total other income and (expenses)

'

'

'

'

'

'

'

'

-434,918

-394,236

-362,129

Income (loss) before income taxes

'

'

'

'

'

'

'

'

-693,536

-383,826

443,905

Income tax expense (benefit)

'

'

'

'

'

'

'

'

-2,199

2,790

5,466

Net income (loss)

($784,549)

[1]

($30,060)

$345,157

($221,885)

($187,495)

($430,005)

$237,086

($6,202)

($691,337)

($386,616)

$438,439

Net income (loss) per unit:

'

'

'

'

'

'

'

'

'

'

'

Basic (in usd per unit)

($3.15)

[1]

($0.13)

$1.47

($0.96)

($0.83)

($2.18)

$1.19

($0.04)

($2.94)

($1.92)

$2.52

Diluted (in usd per unit)

($3.15)

[1]

($0.13)

$1.46

($0.96)

($0.83)

($2.18)

$1.19

($0.04)

($2.94)

($1.92)

$2.51

Weighted average units outstanding:

'

'

'

'

'

'

'

'

'

'

'

Basic (in units)

'

'

'

'

'

'

'

'

237,544

203,775

172,004

Diluted (in units)

'

'

'

'

'

'

'

'

237,544

203,775

172,729

Distributions declared per unit (in usd per unit)

'

'

'

'

'

'

'

'

$2.90

$2.87

$2.70

[1]

Includes the results of operations of the Berry Acquisition since the acquisition date (see NoteB 2).

[2]

Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.

CONSOLIDATED_STATEMENT_OF_UNIT

CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (USD $)	3 Months Ended					12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Balance Beginning	'		$4,427,180	'	$3,428,910	$4,427,180	$3,428,910	$2,788,216
Sale of units, net of underwriting discounts and expenses	'		'	'	'	'	1,942,045	651,522
Issuance of units	'		'	'	'	2,783,907	7,061	7,446
Cancellation of units	'		'	'	'	'	'	0
Purchase of units	'		'	'	'	'	'	-17,352
Distributions to unitholders	'		'	'	'	-682,241	-596,935	-466,488
Unit-based compensation expenses	'		'	'	'	42,703	29,533	22,243
Reclassification of distributions paid on forfeited restricted units	'		'	'	'	176	92	79
Excess tax benefit from unit-based compensation	'		'	'	'	160	3,090	4,805
Deferred tax on capital contribution	'		'	'	'	10,879	'	'
Net income (loss)	-784,549	[1]	-221,885	-187,495	-6,202	-691,337	-386,616	438,439
Balance Ending	5,891,427		'	4,427,180	'	5,891,427	4,427,180	3,428,910
Units [Member]	'		'	'	'	'	'	'
Balance Beginning (in units)	'		234,513	'	177,365	234,513	177,365	159,010
Sale of units, net of underwriting discounts and expenses (in units)	'		'	'	'	'	55,877	17,514
Issuance of units (in units)	'		'	'	'	95,148	1,271	1,371
Cancellation of units (in units)	'		'	'	'	'	'	-530
Balance Ending (in units)	329,661		'	234,513	'	329,661	234,513	177,365
Unitholders' Capital [Member]	'		'	'	'	'	'	'
Balance Beginning	'		4,136,240	'	2,751,354	4,136,240	2,751,354	2,549,099
Sale of units, net of underwriting discounts and expenses	'		'	'	'	'	1,942,045	651,522
Issuance of units	'		'	'	'	2,783,907	7,061	7,446
Cancellation of units	'		'	'	'	'	'	-17,352
Distributions to unitholders	'		'	'	'	-682,241	-596,935	-466,488
Unit-based compensation expenses	'		'	'	'	42,703	29,533	22,243
Reclassification of distributions paid on forfeited restricted units	'		'	'	'	176	92	79
Excess tax benefit from unit-based compensation	'		'	'	'	160	3,090	4,805
Deferred tax on capital contribution	'		'	'	'	10,879	'	'
Balance Ending	6,291,824		'	4,136,240	'	6,291,824	4,136,240	2,751,354
Accumulated Income [Member]	'		'	'	'	'	'	'
Balance Beginning	'		290,940	'	677,556	290,940	677,556	239,117
Net income (loss)	'		'	'	'	-691,337	-386,616	438,439
Balance Ending	-400,397		'	290,940	'	-400,397	290,940	677,556
Treasury Units (at Cost) [Member]	'		'	'	'	'	'	'
Balance Beginning	'		'	'	'	'	'	0
Cancellation of units	'		'	'	'	'	'	17,352
Purchase of units	'		'	'	'	'	'	-17,352
Balance Ending	$0		'	$0	'	$0	$0	$0
[1]	Includes the results of operations of the Berry Acquisition since the acquisition date (see NoteB 2).

CONSOLIDATED_STATEMENT_OF_UNIT1

CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Statement of Stockholders' Equity [Abstract]	'	'
Underwriting discounts and expenses	$32,044	$27,427

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flow from operating activities:	'	'	'
Net income (loss)	($691,337)	($386,616)	$438,439
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:	'	'	'
Depreciation, depletion and amortization	829,311	606,150	334,084
Impairment of long-lived assets	828,317	422,499	0
Unit-based compensation expenses	42,703	29,533	22,243
Loss on extinguishment of debt	5,304	0	94,612
Amortization and write-off of deferred financing fees	21,507	25,598	21,526
Losses on sale of assets and other, net	37,232	92	2,021
Deferred income tax	-2,541	-360	310
Derivatives activities:	'	'	'
Total (gains) losses	-177,857	-124,762	-449,940
Cash settlements	248,862	390,765	237,134
Cash settlements on canceled derivatives	0	0	26,752
Premiums paid for derivatives	0	-583,434	-134,352
Changes in assets and liabilities:	'	'	'
(Increase) decrease in accounts receivable - trade, net	89,188	-77,573	-191,338
(Increase) decrease in other assets	16,179	-5,451	-2,951
Increase (decrease) in accounts payable and accrued expenses	-76,993	26,372	129,499
Increase (decrease) in other liabilities	-3,663	28,094	-9,333
Net cash provided by (used in) operating activities	1,166,212	350,907	518,706
Cash flow from investing activities:	'	'	'
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	-279,213	-2,640,475	-1,500,193
Development of oil and natural gas properties	-1,078,025	-984,530	-574,635
Purchases of other property and equipment	-92,352	-60,549	-55,229
Proceeds from sale of properties and equipment and other	196,273	725	-303
Net cash provided by (used in) investing activities	-1,253,317	-3,684,829	-2,130,360
Cash flow from financing activities:	'	'	'
Proceeds from sale of units	0	1,973,989	678,949
Proceeds from borrowings	2,230,000	5,439,802	2,534,240
Repayments of debt	-1,404,898	-3,400,000	-1,301,029
Distributions to unitholders	-682,241	-596,935	-466,488
Financing fees, offering expenses and other, net	-4,988	-85,895	-56,358
Excess tax benefit from unit-based compensation	160	3,090	4,805
Purchase of units	0	0	-17,352
Net cash provided by (used in) financing activities	138,033	3,334,051	1,376,767
Net increase (decrease) in cash and cash equivalents	50,928	129	-234,887
Cash and cash equivalents:	'	'	'
Beginning	1,243	1,114	236,001
Ending	$52,171	$1,243	$1,114

Basis_of_Presentation_and_Sign

Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Basis of Presentation	'
	Basis of Presentation and Significant Accounting Policies
	Nature of Business
	Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company that began operations in March 2003 and was formed as a Delaware limited liability company in April 2005. The Company completed its initial public offering (“IPO”) in January 2006 and its units representing limited liability company interests (“units”) are listed on the NASDAQ Global Select Market under the symbol “LINE.” LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets.
	The Company’s properties are located in the United States (“U.S.”). In connection with the Company’s acquisition of Berry Petroleum Company (“Berry”) in December 2013 (see Note 2), the Company combined the properties in its Green River Basin and Williston/Powder River Basin regions and added the Uinta Basin and Piceance Basin properties acquired in the Berry acquisition and included all of these properties in the new Rockies region. As a result, the Company currently has seven operating regions in the U.S.: Rockies, which includes properties located in Wyoming (Green River Basin and Powder River Basin), Utah (Uinta Basin), North Dakota (Williston Basin) and Colorado (Piceance Basin); Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays); Hugoton Basin, which includes properties located primarily in Kansas and the Shallow Texas Panhandle; California, which includes properties in the San Joaquin Valley Basin and the Los Angeles Basin; Permian Basin, which includes areas in west Texas and southeast New Mexico; Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois; and East Texas, which includes properties located in east Texas.
	The operations of the Company are governed by the provisions of a limited liability company agreement executed by and among its members. The agreement includes specific provisions with respect to the maintenance of the capital accounts of each of the Company’s unitholders. Pursuant to applicable provisions of the Delaware Limited Liability Company Act (the “Delaware Act”) and the Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC (the “LLC Agreement”), unitholders have no liability for the debts, obligations and liabilities of the Company, except as expressly required in the LLC Agreement or the Delaware Act. The Company will remain in existence unless and until dissolved in accordance with the terms of the LLC Agreement.
	Principles of Consolidation and Reporting
	The Company presents its financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. The Company’s other investment is carried at cost.
	The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss), unitholders’ capital or cash flows.
	Use of Estimates
	The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. Actual results could differ from these estimates. Any changes in estimates resulting from continuous changes in the economic environment will be reflected in the financial statements in future periods.
	Cash Equivalents
	For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows.
	Accounts Receivable – Trade, Net
	Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million at December 31, 2013, and approximately $450,000 at December 31, 2012.
	Inventories
	Materials, supplies and commodity inventories are valued at the lower of average cost or market.
	Oil and Natural Gas Properties
	Proved Properties
	The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.
	The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $2 million for each of the years ended December 31, 2013, December 31, 2012, and December 31, 2011.
	Impairment of Proved Properties
	Based on the analysis described above, for the year ended December 31, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $791 million associated with proved oil and natural gas properties in the Granite Wash formation related to asset performance resulting in reserve revisions and a decline in commodity prices. For the year ended December 31, 2012, the Company recorded a noncash impairment charge, before and after tax, of approximately $422 million associated with proved oil and natural gas properties in the Mississippi Shelf and Mayfield related to the SEC five-year development limitation on PUDs and a decline in commodity prices. The Company recorded no impairment charge for the year ended December 31, 2011. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
	Unproved Properties
	Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past.
	Exploration Costs
	Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $5 million for the year ended December 31, 2013, and approximately $2 million for the years ended December 31, 2012, and December 31, 2011, which are included in “exploration costs” on the consolidated statements of operations.
	Other Property and Equipment
	Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from three to 39 years for the individual asset or group of assets.
	Revenue Recognition
	Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.
	The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2013, and December 31, 2012, the Company had natural gas production imbalance receivables of approximately $27 million and $28 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $16 million and $18 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets.
	The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing sales and marketing expenses.
	The Company generates electricity with excess natural gas, which it uses to serve certain of its operating facilities in California. Any excess electricity is sold to the California wholesale power market. This revenue is included in “other revenues” on the consolidated statements of operations.
	Restricted Cash
	Restricted cash of approximately $6 million and $5 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2013, and December 31, 2012, respectively, and primarily represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements.
	Derivative Instruments
	The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. These transactions are primarily in the form of swap contracts and put options. In addition, the Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. At December 31, 2013, the Company had no outstanding interest rate swap agreements.
	As part of the Berry acquisition (see Note 2), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price.
	Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.
	Unit-Based Compensation
	The Company recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based awards granted to employees and nonemployee directors. The fair value of unit-based awards, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company currently does not have any awards accounted for as liability awards.
	The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. See Note 5 for additional details about the Company’s accounting for unit-based compensation.
	The benefit of tax deductions in excess of recognized compensation costs is required to be reported as financing cash flow rather than operating cash flow. This requirement reduces net operating cash flow and increases net financing cash flow in periods in which such tax benefit exists. The amount of the Company’s excess tax benefit is also reported in “excess tax benefit from unit-based compensation” on the consolidated statements of unitholders’ capital.
	Deferred Financing Fees
	The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2013, and December 31, 2012, net deferred financing fees of approximately $114 million are included in “other noncurrent assets” on the consolidated balance sheets. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense. For the years ended December 31, 2013, December 31, 2012, and December 31, 2011, amortization expense of approximately $18 million, $13 million and $16 million, respectively, is included in “interest expense, net of amounts capitalized.” For the years ended December 31, 2012, and December 31, 2011, approximately $8 million and $1 million, respectively, were written off to “other, net” on the consolidated statements of operations related to amendments of the LINN Credit Facility (as defined in Note 6). No fees related to amendments of the Credit Facilities (as defined in Note 6) were written off and charged to expense during the year ended December 31, 2013.
	Fair Value of Financial Instruments
	The carrying values of the Company’s receivables, payables and Credit Facilities are estimated to be substantially the same as their fair values at December 31, 2013, and December 31, 2012. See Note 6 for fair value disclosures related to the Company’s other outstanding debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments.
	Income Taxes
	The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for the operations of the Company except as described below.
	Limited liability companies are subject to Texas margin tax and were also subject to state income taxes in the state of Michigan during 2011. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes, which are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and tax carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 14 for detail of amounts recorded in the consolidated financial statements.

Acquisitions_JointVenture_Fund

Acquisitions, Joint-Venture Funding and Divestiture	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Acquisitions, Joint-Venture Funding and Divestitures	'
	Acquisitions, Joint-Venture Funding and Divestiture
	Berry Acquisition
	On December 16, 2013, the Company completed the previously-announced transactions contemplated by the merger agreement between the Company, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and the Company, under which LinnCo contributed Berry to the Company in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. The transaction has a preliminary value of approximately $4.6 billion, including the assumption of approximately $2.3 billion of Berry’s debt and net of cash acquired of approximately $451 million.
	Berry’s principal reserves and producing properties are located in California (San Joaquin Valley Basin and Los Angeles Basin), Texas (Permian Basin and east Texas), Utah (Uinta Basin) and Colorado (Piceance Basin). The acquisition included approximately 1,408 Bcfe of proved reserves as of the acquisition date and had average daily production of approximately 267 MMcfe/d since the acquisition date. At December 31, 2013, Berry had approximately 3,400 gross productive wells and more than 200,000 net acres.
	This acquisition was accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition date, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combination is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date. The results of operations of the acquisition have been included in the consolidated financial statements since the acquisition date.
	The purchase price is as follows (in thousands, except units and closing unit price):
	LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674
	Closing price of LINN Energy units on December 16, 2013	$	29.47
	LINN Energy unit consideration	$	2,763,009
	Employee unit-based awards	$	18,879
	Total purchase price	$	2,781,888
	The following presents the values assigned to the net assets acquired as of the acquisition date (in thousands):
	Assets:
	Cash	$	451,113
	Current	249,564
	Noncurrent	97,202
	Oil and natural gas properties	4,791,394
	Total assets acquired	5,589,273
	Liabilities:
	Current	310,105
	Noncurrent	100,809
	Asset retirement obligations, current and noncurrent	94,612
	Long-term debt, including current portion	2,301,859
	Total liabilities assumed	2,807,385
	Net assets acquired	$	2,781,888
	Current assets include receivables of approximately $194 million and derivative instruments of approximately $14 million. Noncurrent assets include derivative instruments of approximately $6 million and other property and equipment of approximately $83 million. Current liabilities include payables of approximately $272 million and out-of-market natural gas transportation contracts of approximately $19 million. Noncurrent liabilities include out-of-market natural gas transportation contracts of approximately $88 million.
	The fair value measurements of derivative instruments assumed were determined utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis, and represent Level 2 inputs. The fair value measurements of long-term debt were estimated based on prices quoted from third-party financial institutions and also represent Level 2 inputs.
	The fair value measurements of certain other assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value measurements of natural gas transportation contracts and operating leases assumed were determined utilizing a form of the income approach using Level 3 inputs which measures the contract relative to a replacement contract or the current market. Contracts with favorable fair values compared to the original contract terms were recorded in “other current assets” and “other noncurrent assets” and contracts with unfavorable fair values compared to the original contract terms were recorded in “accounts payable and accrued expenses” and “other noncurrent liabilities” on the consolidated balance sheet. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
	The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2013, and December 31, 2012, assuming the Berry acquisition and the 2012 acquisitions from BP America Production Company (“BP”) (see below) had been completed as of January 1, 2012, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information has been prepared for informational purposes only and does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The pro forma financial information does not give effect to the costs of any integration activities or benefits that may result from the realization of future cost savings from operating efficiencies, or any other synergies that may result from the transactions and changes in commodity and share prices.
			Year Ended
			December 31,
			2013			2012
			(in thousands, except
			per unit amounts)
	Total revenues and other		$	3,443,246		$	2,989,410
	Total operating expenses		$	3,366,987		$	2,572,921
	Net income (loss)		$	(445,965	)	$	(131,313	)
	Net income (loss) per unit:
	Basic		$	(1.36	)	$	(0.46	)
	Diluted		$	(1.36	)	$	(0.46	)
	The pro forma condensed combined statements of operations include adjustments to:
	•	Include the results of Berry and the 2012 acquisitions from BP for all periods presented.
	•	Reflect certain derivative transactions, consisting of WTI swaps and Brent-WTI basis swaps, Berry entered into at the Company’s request with respect to Berry’s production following the execution of the merger agreement.
	•	Reflect incremental depreciation, depletion and amortization expense, using the units-of-production method, related to oil and natural gas properties acquired and using an estimated useful life of 20 years for other property and equipment.
	•	Reflect accretion expense related to asset retirement obligations on oil and natural gas properties acquired.
	•	Reflect a reduction in interest expense related to the amortization of the adjustment to fair value of Berry’s debt using the effective interest method, and an increase in interest expense related to the incremental debt incurred to fund the purchase prices of the 2012 acquisitions from BP.
	•	Exclude transaction costs included in the historical statement of operations for the year ended December 31, 2013, as they reflect non-recurring charges not expected to have a continuing impact on the combined results.
	•	Reflect 93.8 million LINN Energy units assumed to be issued in conjunction with the transaction on January 1, 2012.
	For the year ended December 31, 2013, in connection with the Berry acquisition, the Company incurred acquisition-related transaction and integration costs of approximately $48 million, including approximately $18 million in employee severance and unit-based compensation.
	Joint-Venture Funding
	For the year ended December 31, 2013, the Company paid approximately $173 million, including interest, towards the future funding commitment related to the joint-venture agreement (“JV Agreement”) it entered into with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) in April 2012. From inception of the agreement through December 31, 2013, the Company has funded approximately $375 million towards the total commitment of $400 million.
	Other Acquisitions – 2013
	On October 31, 2013, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin. The Company paid approximately $528 million in total consideration for these properties. The transaction was financed with proceeds from a $500 million senior secured term loan with certain participants in its lender group and borrowings under the LINN Credit Facility. The term loan has a maturity date of April 2018, consistent with the maturity of the LINN Credit Facility.
	The following presents the values assigned to the net assets acquired in the Permian Basin acquisition as of the acquisition date (in thousands):
	Assets:
	Current	$	1,124
	Noncurrent	10
	Oil and natural gas properties	531,335
	Total assets acquired	532,469
	Liabilities:
	Current	1,808
	Asset retirement obligations, current and noncurrent	2,775
	Total liabilities assumed	4,583
Net assets acquired	$	527,886
Current assets include inventory and noncurrent assets include other property and equipment. Current liabilities include payables.
The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
During 2013, the Company also completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The Company, in the aggregate, paid approximately $40 million in total consideration for these properties.
All acquisitions were accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition date, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of all acquisitions have been included in the consolidated financial statements since the acquisition dates.
Divestiture
On May 31, 2013, the Company, through one of its wholly owned subsidiaries, together with the Company’s partners, Panther Energy, LLC and Red Willow Mid-Continent, LLC, completed the sale of its interests in certain oil and natural gas properties located in the Mid-Continent region (“Panther Operated Cleveland Properties”) to Midstates Petroleum Company, Inc. During the year ended December 31, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $37 million associated with the write-down of the carrying value of the Panther Operated Cleveland Properties. Proceeds received for the Company’s portion of its interests in the properties were approximately $218 million, net of costs to sell of approximately $2 million. The Company used the net proceeds from the sale to repay borrowings under the LINN Credit Facility.
Acquisitions - 2012 and 2011
The following is a summary of significant acquisitions completed by the Company during the years ended December 31, 2012, and December 31, 2011:
•	On July 31, 2012, the Company completed the acquisition of certain oil and natural gas properties in the Jonah Field located in the Green River Basin of southwest Wyoming from BP for approximately $988 million.
•	On May 1, 2012, the Company completed the acquisition of certain oil and natural gas properties located in east Texas for approximately $164 million.
•	On April 3, 2012, the Company entered into a JV Agreement with an affiliate of Anadarko whereby the Company participates as a partner in the CO2 enhanced oil recovery development of the Salt Creek Field, located in the Powder River Basin of Wyoming. Anadarko assigned the Company 23% of its interest in the field in exchange for future funding of $400 million of Anadarko’s development costs. The Company assigned approximately $392 million to the net assets acquired as of the JV Agreement date, which reflects an imputed discount of approximately $8 million on the future funding of this transaction.
•	On March 30, 2012, the Company completed the acquisition of certain oil and natural gas properties and the Jayhawk natural gas processing plant located in the Hugoton Basin in Kansas from BP for approximately $1.17 billion.
•	On December 15, 2011, the Company completed the acquisition of certain oil and natural gas properties located primarily in the Granite Wash of Texas and Oklahoma from Plains Exploration & Production Company for approximately $542 million.
•	On November 1, 2011, and November 18, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin for approximately $110 million.
•	On June 1, 2011, the Company completed the acquisition of certain oil and natural gas properties in the Cleveland play, located in the Texas Panhandle, from Panther Energy Company, LLC and Red Willow Mid-Continent, LLC for approximately $224 million.
•	On May 2, 2011, and May 11, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Williston Basin for approximately $153 million.
•	On April 1, 2011, and April 5, 2011, the Company completed two acquisitions of certain oil and natural gas properties located in the Permian Basin, including properties from SandRidge Exploration and Production, LLC for approximately $239 million.
•	On March 31, 2011, the Company completed the acquisition of certain oil and natural gas properties located in the Williston Basin from an affiliate of Concho Resources Inc. for approximately $192 million.

Unitholders_Capital

Unitholders' Capital	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Unitholders' Capital	'
	Unitholders’ Capital
	Berry Acquisition
	On December 16, 2013, the Company completed the previously-announced transactions contemplated by the merger agreement under which LinnCo, an affiliate of LINN Energy, acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and the Company, under which LinnCo contributed Berry to the Company in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units with a value of approximately $2.8 billion.
	LinnCo Initial Public Offering
	In October 2012, LinnCo completed its initial public offering (the “LinnCo IPO”) of 34,787,500 common shares representing limited liability company interests to the public at a price of $36.50 per share ($34.858 per share, net of underwriting discount and structuring fee) for net proceeds of approximately $1.2 billion (after underwriting discount and structuring fee of approximately $57 million). The net proceeds LinnCo received from the offering were used to acquire 34,787,500 LINN Energy units which are equal to the number of LinnCo shares sold in the offering. The Company used the proceeds from the sale of the units to LinnCo to pay the expenses of the offering and repay a portion of the outstanding indebtedness under the LINN Credit Facility.
	Public Offering of Units
	In January 2012, the Company sold 19,550,000 units representing limited liability company interests at $35.95 per unit ($34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount and offering expenses of approximately $28 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under the LINN Credit Facility.
	In March 2011, the Company sold 16,726,067 units representing limited liability company interests at $38.80 per unit ($37.248 per unit, net of underwriting discount) for net proceeds of approximately $623 million (after underwriting discount and offering expenses of approximately $26 million). The Company used a portion of the net proceeds from the sale of these units to fund the March 2011 redemptions of a portion of the outstanding May 2017 Senior Notes and July 2018 Senior Notes and to fund the cash tender offers and related expenses for a portion of the remaining May 2017 Senior Notes and July 2018 Senior Notes (see Note 6). The Company used the remaining net proceeds from the sale of units to finance a portion of the acquisition in the Rockies region on March 31, 2011.
	Equity Distribution Agreement
	The Company has an equity distribution agreement pursuant to which it may from time to time issue and sell units representing limited liability company interests having an aggregate offering price of up to $500 million. Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.
	In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $1 million in commissions). In connection with the issue and sale of these units, the Company also incurred professional service expenses of approximately $700,000. The Company used the net proceeds for general corporate purposes, including the repayment of a portion of the indebtedness outstanding under the LINN Credit Facility. At December 31, 2013, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.
	In September 2011, the Company, under its equity distribution agreement, issued and sold 16,060 units representing limited liability company interests at an average unit price of $38.25 for proceeds of approximately $602,000 (net of approximately $12,000 in commissions). In December 2011, the Company issued and sold 772,104 units representing limited liability company interests at an average unit price of $38.03 for proceeds of approximately $29 million (net of approximately $587,000 in commissions). In connection with the issue and sale of these units, the Company also incurred professional service expenses of approximately $139,000. The Company used the net proceeds for general corporate purposes, including the repayment of a portion of the indebtedness outstanding under the LINN Credit Facility.
	Unit Repurchase Plan
	In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. During the year ended December 31, 2011, 529,734 units were repurchased at an average unit price of $32.76 for a total cost of approximately $17 million. All units were subsequently canceled.
	No units were repurchased by the Company during the years ended December 31, 2013, and December 31, 2012. At December 31, 2013, approximately $56 million was available for unit repurchase under the program. The timing and amounts of any such repurchases are at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. Units are repurchased at fair market value.
	Distributions
	Under the Company’s LLC Agreement, unitholders are entitled to receive a distribution of available cash, which includes cash on hand plus borrowings less any reserves established by the Company’s Board of Directors to provide for the proper conduct of the Company’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions over the next four quarters. Distributions paid by the Company are presented on the consolidated statements of unitholders’ capital and the consolidated statements of cash flows. In April 2013, the Company’s Board of Directors approved a change in its distribution policy that provides a distribution with respect to any quarter may be made, at the discretion of the Board of Directors, (i) within 45 days following the end of each quarter or (ii) in three equal installments within 15, 45 and 75 days following the end of each quarter. On January 2, 2014, the Company’s Board of Directors declared a cash distribution of $0.725 per unit with respect to the fourth quarter of 2013, to be paid in three equal monthly installments of $0.2416 per unit. The first monthly distribution, totaling approximately $80 million, was paid on January 16, 2014, to unitholders of record as of the close of business on January 13, 2014, and the second monthly distribution, totaling approximately $80 million, was paid on February 13, 2014, to unitholders of record as of the close of business on February 10, 2014.

Business_and_Credit_Concentrat

Business and Credit Concentrations	12 Months Ended
	Dec. 31, 2013
Risks and Uncertainties [Abstract]	'
Concentration Risk Disclosure	'
	Business and Credit Concentrations
	Cash
	The Company maintains its cash in bank deposit accounts which at times may exceed federally insured amounts. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on its cash.
	Revenue and Trade Receivables
	The Company has a concentration of customers who are engaged in oil and natural gas purchasing, transportation and/or refining within the U.S. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company’s customers consist primarily of major oil and natural gas purchasers and the Company generally does not require collateral since it has not experienced significant credit losses on such sales. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectibility (see Note 1).
	For the year ended December 31, 2013, the Company’s largest customer represented approximately 12% of the Company’s sales. For the year ended December 31, 2012, the Company’s two largest customers represented approximately 12% and 11%, respectively, of the Company’s sales. For the year ended December 31, 2011, the Company’s three largest customers represented approximately 13%, 10% and 10%, respectively, of the Company’s sales.
	At December 31, 2013, trade accounts receivable from two customers represented approximately 19% and 14%, respectively, of the Company’s receivables. At December 31, 2012, trade accounts receivable from two customers represented approximately 21% and 11%, respectively, of the Company’s receivables.

UnitBased_Compensation_and_Oth

Unit-Based Compensation and Other Benefit Plans	12 Months Ended
	Dec. 31, 2013
Unit Based Compensation and Other Benefit Plans [Abstract]	'
Compensation and Employee Benefit Plans [Text Block]	'
	Unit-Based Compensation and Other Benefit Plans
	Incentive Plan Summary
	The Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (the “Plan”), originally became effective in December 2005. The Plan, which is administered by the Compensation Committee of the Board of Directors (“Compensation Committee”), permits granting unrestricted units, restricted units, phantom units, unit options, performance units and unit appreciation rights to employees, consultants and nonemployee directors under the terms of the Plan. The restricted units, phantom units and unit options generally vest ratably over three years. The contractual life of unit options is 10 years. Performance units were granted for the first time in January 2014 to certain executive officers. The initial 2014 awards vest 50% in two years and 50% in three years from the award date.
	The Plan limits the number of units that may be delivered pursuant to awards to 21 million units. The Board of Directors and the Compensation Committee have the right to alter or amend the Plan or any part of the Plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits to the participant without the consent of the participant.
	Units to be delivered as restricted units, upon the vesting of phantom units or performance units, or upon exercise of a unit option or unit appreciation right may be new units issued by the Company, units acquired by the Company in the open market, units acquired by the Company from any other person, units already owned by the Company, or any combination of the foregoing. If the Company issues new units upon the grant of restricted units, vesting of phantom units or performance units, or exercise of a unit option or unit appreciation right, the total number of units outstanding will increase. To date, the Company has issued awards of unrestricted units, restricted units, phantom units, performance units and unit options. The Plan provides for all of the following types of awards:
	Unit Grants – A unit grant is the grant of an unrestricted unit, meaning a unit that vests immediately upon issuance.
	Restricted Units – A restricted unit is a unit that vests over a period of time and that during such time is subject to forfeiture. The Company intends the restricted units under the Plan to serve as a means of incentive compensation for performance. Therefore, Plan participants will not pay any consideration for the units they receive. If a grantee’s employment, consulting relationship or membership on the Company’s Board of Directors terminates for any reason, other than death, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. The restricted units will vest upon a change of control, unless provided otherwise by the Compensation Committee.
	Phantom Units – A phantom unit entitles the grantee to receive a unit upon the vesting of the phantom unit or, in the discretion of the Compensation Committee, cash equivalent to the value of a unit. The Compensation Committee may grant tandem distribution equivalent rights with respect to phantom units that entitle the holder to receive cash equal to any cash distributions made on units while the phantom units are outstanding. The Compensation Committee will determine the period over which phantom units will vest, subject to applicable minimum vesting periods except with respect to phantom unit grants to nonemployee directors. The Company intends the phantom units under the Plan to serve as a means of incentive compensation for performance. Therefore, Plan participants will not pay any consideration for the units they receive. If a grantee’s employment, consulting relationship or membership on the Company’s Board of Directors terminates for any reason, other than death or retirement, the grantee’s phantom units will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. The phantom units will vest upon a change of control, unless provided otherwise by the Compensation Committee.
	Unit Options – A unit option is a right to purchase a unit at a specified price. Unit options will have an exercise price that will not be less than the fair market value of the units on the date of grant. If a grantee’s employment, consulting relationship or membership on the Company’s Board of Directors terminates for any reason, the grantee’s unvested unit options will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. The unit options will become exercisable upon a change of control, unless provided otherwise by the Compensation Committee.
	Performance Units – A performance unit is a unit that vests over a period of time in an amount based on certain comparative performance criteria. The Company intends the performance units under the Plan to serve as a means of incentive compensation for performance. Therefore, Plan participants will not pay any consideration for the units they receive. Upon termination of employment with the Company other than for “Cause” or with “Good Reason” (as those terms are defined in the employment agreement), the performance units vest on the originally scheduled vesting date at the performance level multiplier applicable on that date.  If employment terminates by reason of death or “Disability” (as defined in the employment agreement), the performance units immediately vest at the target level. Additionally, the performance units vest upon a change of control and the number of units awarded is determined as if the vesting period ended on the change of control date instead of the originally scheduled date.
	Unit Appreciation Rights – A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. The excess may be paid in the Company’s units, cash or a combination thereof, as determined by the Compensation Committee in its discretion. To date, the Company has not granted any unit appreciation rights.
	Securities Authorized for Issuance Under the Plan
	As of December 31, 2013, approximately 9 million units were issuable under the Plan pursuant to outstanding award or other agreements, including unvested restricted units, phantom units and outstanding unit options, and 6.2 million additional units were reserved for future issuance under the Plan.
	Berry Acquisition
	On December 16, 2013, in connection with the Berry acquisition (see Note 2), certain Berry awards were exchanged for awards issued by the Company. Each unvested Berry restricted stock unit (“RSU”) (excluding any Berry RSU held by a former nonemployee director of Berry or by an employee of Berry whose employment was terminated in connection with the acquisition as agreed by the parties and any performance-based Berry RSU) was converted into a restricted unit award in respect of the number of LINN Energy units. Each option to purchase shares of Berry common stock was converted into an option to purchase a number of LINN Energy units.
	Under the acquisition method of accounting, Berry employee RSUs and options were measured and recorded at their fair values on the acquisition date, resulting in additional purchase price consideration of approximately $19 million. The portion of the replacement awards attributable to post-combination service was calculated as the difference between the fair value of the replacement awards and the amount attributed to pre-combination service, and will be recognized as compensation expense over the vesting period.
	Accounting for Unit-Based Compensation
	The Company recognizes as expense, beginning at the grant date, the fair value of equity-based compensation issued to employees and nonemployee directors. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period using the straight-line method in the Company’s consolidated statements of operations. A summary of unit-based compensation expenses included in the consolidated statements of operations is presented below:
			Year Ended December 31,
			2013			2012			2011
			(in thousands)
	General and administrative expenses		$	37,375		$	27,641		$	21,131
	Lease operating expenses		5,328			1,892			1,112
	Total unit-based compensation expenses		$	42,703		$	29,533		$	22,243
	Income tax benefit		$	15,779		$	10,912		$	8,219
	Restricted Units/Phantom Units/Unrestricted Units
	The fair value of restricted units, phantom units and unrestricted unit grants issued is determined based on the fair market value of the Company units on the date of grant. A summary of the status of the nonvested units as of December 31, 2013, is presented below:
			Number of		Weighted Average
			Nonvested		Grant-Date
			Units		Fair Value
	Nonvested units at December 31, 2012		1,953,131		$	36.16
	Granted		1,652,711		$	30.71
	Vested		(889,767	)	$	34.63
	Forfeited		(144,665	)	$	37.09
	Nonvested units at December 31, 2013		2,571,410		$	33.14
	The weighted average grant-date fair value of restricted units, phantom units and unrestricted units granted was $37.42 and $38.54 during the years ended December 31, 2012, and December 31, 2011, respectively. The total fair value of units that vested was approximately $31 million, $24 million and $13 million for the years ended December 31, 2013, December 31, 2012, and December 31, 2011, respectively. As of December 31, 2013, there was approximately $40 million of unrecognized compensation cost related to nonvested restricted units and phantom units. The cost is expected to be recognized over a weighted average period of approximately 1.6 years.
	In January 2014, the Company granted 1,435,192 restricted units and 213,710 phantom units as part of its annual review of its employees’, including executives, compensation. The Company also granted 212,524 performance units (the maximum number of units available to be earned) to certain executive officers.
	Unit Options
	The following provides information related to unit option activity for the year ended December 31, 2013:
			Number of		Weighted Average			Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value in Millions
			Units Underlying Options		Exercise Price Per Unit
	Outstanding at December 31, 2012		4,642,805		$	35.25		6.28		$	16
	Berry assumed		2,237,593		$	20.58
	Exercised		(117,175	)	$	18.79
	Forfeited or expired		(330,000	)	$	39.55
	Outstanding at December 31, 2013		6,433,223		$	30.22		6.66		$	33
	Exercisable at December 31, 2013		3,318,226		$	21.08		7.48		$	33
	During the years ended December 31, 2013, and December 31, 2012, the weighted average grant-date fair value of unit options granted was $7.52 and $5.31, respectively. All unit options granted in 2013 were replacement awards issued in exchange for options assumed in the Berry acquisition. No unit options were granted during the year ended December 31, 2011. The total intrinsic value of unit options exercised was approximately $2 million, $3 million and $5 million, during the years ended December 31, 2013, December 31, 2012, and December 31, 2011, respectively. The Company received approximately $2 million from the exercise of unit options during the year ended December 31, 2013. As of December 31, 2013, total unrecognized compensation cost related to nonvested unit options was approximately $9 million. The cost is expected to be recognized over a weighted average period of approximately 2.6 years.
	The fair value of unit-based compensation for unit options was estimated on the date of grant using a Black-Scholes pricing model based on certain assumptions. That value may not be indicative of the fair value observed in a willing buyer/willing seller market transaction. The Company’s determination of the fair value of unit-based awards is affected by the Company’s unit price as well as assumptions consisting of a number of complex and subjective variables. The Company’s employee unit options have various restrictions including vesting provisions and restrictions on transfers and hedging, among others, and often are expected to be exercised prior to their contractual maturity.
	Expected volatilities used in the estimation of fair value of the unit option grants have been determined using available volatility data for the Company. Expected distributions are estimated based on the Company’s distribution rate at the date of grant. Forfeitures are estimated using historical Company data and are revised, if necessary, in subsequent periods if actual forfeitures differ from estimates. The risk-free rate for periods within the expected term of the unit option is based on the U.S. Treasury yield curve in effect at the time of grant. Historical data of the Company is used to estimate expected term. All employees granted awards have been determined to have similar behaviors for purposes of determining the expected term used to estimate fair value. The fair values of the Company’s unit option grants were based upon the following assumptions:
		2013 (1)		2012
	Expected volatility	29.65% – 50.88%		34.10%
	Expected distributions	9.84%		7.25%
	Risk-free rate	0.13% – 1.55%		0.67%
	Expected term	0.68 years – 5 years		5 years
	(1)	All unit options granted in 2013 were replacement awards issued in exchange for options assumed in the Berry acquisition.
	Nonemployee Grants
	At December 31, 2013, the Company had 15,000 outstanding unit warrants with an exercise price of $25.50 per unit warrant, which are fully exercisable and expire in 2017.
	Defined Contribution Plan
	The Company sponsors a 401(k) defined contribution plan for eligible employees. Company contributions to the 401(k) plan consist of a discretionary matching contribution equal to 100% of the first 6% of eligible compensation contributed by the employee on a before-tax basis. The Company contributed approximately $7 million, $5 million and $4 million during the years ended December 31, 2013, December 31, 2012, and December 31, 2011, respectively, to the 401(k) plan’s trustee account. The 401(k) plan funds are held in a trustee account on behalf of the plan participants.

Debt

Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Debt	'
	Debt
	The following summarizes the Company’s outstanding debt:
			December 31,
			2013			2012
			(in millions, except percentages)
	Berry credit facility (1) (2)		$	1,173		$	—
	LINN credit facility (3)		1,560			1,180
	Term loan (4)		500			—
	10.25% Berry senior notes due June 2014 (2)		205			—
	11.75% senior notes due May 2017		—			41
	9.875% senior notes due July 2018		—			14
	6.50% senior notes due May 2019		750			750
	6.25% senior notes due November 2019		1,800			1,800
	8.625% senior notes due April 2020		1,300			1,300
	6.75% Berry senior notes due November 2020 (2)		300			—
	7.75% senior notes due February 2021		1,000			1,000
	6.375% Berry senior notes due September 2022 (2)		600			—
	Net unamortized discounts and premiums		(18		)	(47		)
	Total debt, net		9,170			6,038
	Less current maturities		(211		)	—
	Total long-term debt, net		$	8,959		$	6,038
	(1)	Variable interest rate of 2.67% at December 31, 2013.
	(2)	Assumed on December 16, 2013.
	(3)	Variable interest rates of 1.92% and 1.97% at December 31, 2013, and December 31, 2012, respectively.
	(4)	Variable interest rate of 2.67% at December 31, 2013.
	Fair Value
	The Company’s debt is recorded at the carrying amount in the consolidated balance sheets. The carrying amounts of the Company’s Credit Facilities and term loan approximate fair value because the interest rates are variable and reflective of market rates. The Company uses a market approach to determine the fair value of its senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.
			December 31, 2013						December 31, 2012
			Carrying			Fair Value			Carrying		Fair Value
			Value						Value
			(in millions)
	Credit Facilities		$	2,733		$	2,733		$	1,180	$	1,180
	Term loan		500			500			—		—
	Senior notes, net		5,937			6,162			4,858		5,091
	Total debt, net		$	9,170		$	9,395		$	6,038	$	6,271
	Credit Facilities
	LINN Credit Facility
	In April 2013, the Company entered into a Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”), which provides for a revolving credit facility up to the lesser of: (i)  the then-effective borrowing base and (ii)  the maximum commitment amount of $4.0 billion. The borrowing base remained unchanged at $4.5 billion and does not include any assets acquired in the Berry acquisition (see Note 2). The maturity date is April 2018. The amended and restated agreement is substantially similar to the previous LINN Credit Facility with revisions to permit the transactions related to the Berry acquisition and to designate Berry as an unrestricted subsidiary under the agreement. At December 31, 2013, the borrowing capacity under the LINN Credit Facility was approximately $2.4 billion, which includes a $5 million reduction in availability for outstanding letters of credit.
	Redetermination of the borrowing base under the LINN Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October. The administrative agent, at the direction of certain of the lenders, has the right to request one interim borrowing base redetermination per year. The Company also has the right to request one interim borrowing base redetermination per year, as well as the right to an additional interim redetermination each year in connection with certain acquisitions. Significant declines in commodity prices may result in a decrease in the borrowing base. The Company’s obligations under the LINN Credit Facility are secured by mortgages on certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in the Company’s direct and indirect material subsidiaries. The Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on the most recent reserve report, or 2) a Collateral Coverage Ratio of at least 2.5 to 1. Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. Additionally, the obligations under the LINN Credit Facility are guaranteed by all of the Company’s material subsidiaries, other than Berry, and are required to be guaranteed by any future material subsidiaries. The Company is in compliance with all financial and other covenants of the LINN Credit Facility.
	At the Company’s election, interest on borrowings under the LINN Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.5% and 2.5% per annum (depending on the then-current level of borrowings under the LINN Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the LINN Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at LIBOR. The Company is required to pay a commitment fee to the lenders under the LINN Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% (depending on the then-current level of borrowings under the LINN Credit Facility) on the average daily unused amount of the maximum commitment amount of the lenders.
	On October 30, 2013, the Company entered into an amendment to the LINN Credit Facility, under which the Company entered into a $500 million senior secured term loan with certain participants in its lender group under the LINN Credit Facility. The term loan has a maturity date of April 2018, consistent with the maturity of the LINN Credit Facility, and incurs interest based on either the LIBOR plus a margin of 2.5% per annum or the ABR plus a margin of 1.5% per annum, at the Company’s election. Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at LIBOR. The term loan may be repaid at the option of the Company without premium or penalty, subject to breakage costs. While the term loan is outstanding, the Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on the most recent reserve report, or 2) a Term Loan Collateral Coverage Ratio of at least 2.5 to 1. The Term Loan Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount and the aggregate amount of the term loan outstanding. The other terms and conditions of the LINN Credit Facility, including the financial and other restrictive covenants set forth therein, are applicable to the term loan. The proceeds of the term loan were used to partially fund the acquisition of certain oil and natural gas properties located in the Permian Basin.
	Berry Credit Facility
	In December 2013, Berry entered into an amendment to its Second Amended and Restated Credit Agreement (“Berry Credit Facility”) primarily to conform certain terms in the Berry Credit Facility to like terms in the LINN Credit Facility. The maturity date is May 2016. The Berry Credit Facility has a borrowing base of $1.4 billion, subject to lender commitments. At December 31, 2013, lender commitments under the facility were $1.2 billion and there was no remaining borrowing capacity available. Any borrowings under the Berry Credit Facility must be repaid upon the refinancing of all of Berry’s outstanding senior notes. In February 2014, Berry entered into an amendment to the Berry Credit Facility to amend the terms of certain financial covenants and reporting covenants.
	Redetermination of the borrowing base under the Berry Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in March and September. The lenders under the Berry Credit Facility also have the right to request interim borrowing base redeterminations once between scheduled redeterminations, contemporaneously with issuances of permitted unsecured debt, in conjunction with unwinding certain derivatives and in conjunction with certain permitted sales of property. Berry also has the right to request interim borrowing base redeterminations once between scheduled redeterminations and in conjunction with certain issuances of permitted unsecured debt. Significant declines in commodity prices may result in a decrease in the borrowing base. Berry’s obligations under the Berry Credit Facility are secured by mortgages on its oil and natural gas properties and other personal property. Berry is required to maintain mortgages on properties representing at least 80% of the present value of its oil and natural gas proved reserves.
	Berry is currently in compliance with all financial and other covenants of the Berry Credit Facility. At December 31, 2013, Berry’s Current Ratio (as defined in the Berry Credit Facility), fell short of the requirement under its covenant primarily due to factors related to the transactions between the Company, LinnCo and Berry, including a reassessment of the carrying value of items on Berry’s balance sheet as of the acquisition date and updated accruals as of December 31, 2013. In February 2014, Berry received a waiver of the applicability of that covenant and any noncompliance which may have resulted as of December 31, 2013, and entered into an amendment to its credit facility to address this covenant for future periods. The shortfall and related waiver and amendment had no effect on Berry’s compliance with the indentures governing its outstanding senior notes for the quarter ended December 31, 2013, and Berry was in compliance with all of the covenants under its senior notes at December 31, 2013.
	At Berry’s election, interest on borrowings under the Berry Credit Facility is determined by reference to either the LIBOR plus an applicable margin between 1.5% and 2.5% per annum (depending on the then-current level of borrowings under the Berry Credit Facility) or a Base Rate (as defined in the Berry Credit Facility) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the Berry Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the Base Rate and at the end of the applicable interest period for loans bearing interest at LIBOR. Berry is required to pay a commitment fee to the lenders under the Berry Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% (depending on the then-current level of utilization under the Berry Credit Facility) on the average daily unused amount of the maximum commitment amount of the lenders.
	The Company refers to the LINN Credit Facility and the Berry Credit Facility, collectively, as the “Credit Facilities.”
	Berry Senior Notes Due June 2014
	Berry’s $205 million in aggregate principal amount of 10.25% senior notes due June 2014 (the “Berry June 2014 Senior Notes”) matures on June 1, 2014. Therefore, the $205 million is classified as a current obligation on the Company’s consolidated balance sheet at December 31, 2013. While the Company has not yet determined how it will repay or refinance the Berry June 2014 Senior Notes, the Company may do so through various alternatives which it may pursue separately or in combination, including (i) issuing new debt or equity securities and (ii) borrowing under the LINN Credit Facility.
	The Berry June 2014 Senior Notes were recorded at their fair value of $212 million on the Berry acquisition date. The $7 million premium is being amortized to interest expense over the life of the related notes.
	Senior Notes Due May 2019
	The Company has $750 million in aggregate principal amount of 6.50% senior notes due May 2019 (the “May 2019 Senior Notes”). In an exchange offer that expired in October 2012, the Company exchanged all of its $750 million outstanding principal amount of May 2019 Senior Notes for an equal amount of new May 2019 Senior Notes. The terms of the new May 2019 Senior Notes are identical in all material respects to those of the outstanding May 2019 Senior Notes, except that the transfer restrictions, registration rights and additional interest provisions relating to the outstanding May 2019 Senior Notes do not apply to the new May 2019 Senior Notes.
	Senior Notes Due November 2019
	The Company has $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (the “November 2019 Senior Notes”). In connection with the issuance and sale of the November 2019 Senior Notes, the Company entered into a Registration Rights Agreement (“November 2019 Registration Rights Agreement”) with the initial purchasers. Under the November 2019 Registration Rights Agreement, the Company agreed to use its reasonable efforts to file with the Securities and Exchange Commission (“SEC”) and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the November 2019 Senior Notes in exchange for outstanding November 2019 Senior Notes within 400 days after the notes were issued. On March 22, 2013, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the November 2019 Senior Notes. As of February 27, 2014, that registration statement has not been declared effective. Accordingly, beginning on April 8, 2013, interest accruing on the November 2019 Senior Notes increased by 0.25%, and increased by an additional 0.25% on the 90th, 180th and 270th day after such date. The increase in interest is payable until the registration statement is declared effective and the Company completes an offer to exchange the November 2019 Senior Notes for registered notes. The additional interest was approximately $7 million through December 2013.
	Senior Notes Due April 2020 and Senior Notes Due February 2021
	The Company has $1.3 billion in aggregate principal amount of 8.625% senior notes due April 2020 (the “April 2020 Senior Notes”) and $1.0 billion in aggregate principal amount of 7.75% senior notes due February 2021 (the “February 2021 Senior Notes,” and together with the April 2020 Senior Notes, the “2010 Issued Senior Notes”). The restrictive legends from each of the 2010 Issued Senior Notes have been removed making them freely tradable (other than with respect to persons that are affiliates of the Company), thereby terminating the Company’s obligations under each of the registration rights agreements entered into in connection with the issuance of the 2010 Issued Senior Notes.
	Berry Senior Notes Due November 2020
	Berry has $300 million in aggregate principal amount of 6.75% senior notes due November 2020 (the “Berry November 2020 Senior Notes”). The Berry November 2020 Senior Notes were recorded at their fair value of $310 million on the Berry acquisition date. The $10 million premium is being amortized to interest expense over the life of the related notes.
	Berry Senior Notes Due September 2022
	Berry has $600 million in aggregate principal amount of 6.375% senior notes due September 2022 (the “Berry September 2022 Senior Notes”). The Berry September 2022 Senior Notes were recorded at their fair value of $607 million on the Berry acquisition date. The $7 million premium is being amortized to interest expense over the life of the related notes.
	Redemptions of Senior Notes Due May 2017 and Senior Notes Due July 2018
	In accordance with the provisions of the indentures related to the Company’s 11.75% senior notes due May 2017 (the “May 2017 Senior Notes”) and 9.875% senior notes due July 2018 (the “July 2018 Senior Notes” and together with the May 2017 Senior Notes, the “Original Senior Notes”), in June 2013 and July 2013, the Company redeemed the remaining outstanding principal amounts of approximately $41 million and $14 million, respectively. In connection with the redemptions of the Original Senior Notes, the Company recorded a loss on extinguishment of debt of approximately $5 million for the year ended December 31, 2013.
	The Company’s senior notes contain covenants that, among other things, may limit their ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. The Company is in compliance with all financial and other covenants of its senior notes.
Berry’s senior notes contain covenants that, among other things, may limit its ability to: (i) incur or guarantee additional indebtedness; (ii) pay distributions on Berry’s equity or redeem its subordinated debt; (iii) create certain liens; (iv) enter into agreements that restrict distributions or other payments from Berry’s restricted subsidiaries to Berry; (v) sell assets; (vi) engage in transactions with affiliates; and (vii) consolidate, merge or transfer all or substantially all of Berry’s assets. Berry is in compliance with all financial and other covenants of its senior notes.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivatives	'
	Derivatives
	Commodity Derivatives
	The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company directly hedges only its oil and natural gas production.
	The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production to provide an economic hedge of the risk related to the future commodity prices received. The Company does not enter into derivative contracts for trading purposes. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.
	The following table summarizes derivative positions for the periods indicated as of December 31, 2013:
		2014			2015			2016			2017			2018
	Natural gas positions:
	Fixed price swaps (NYMEX Henry Hub):
	Hedged volume (MMMBtu)	97,400			118,041			121,841			120,122			36,500
	Average price ($/MMBtu)	$	5.25		$	5.19		$	4.2		$	4.26		$	5
	Put options (NYMEX Henry Hub): (1)
	Hedged volume (MMMBtu)	79,628			71,854			76,269			66,886			—
	Average price ($/MMBtu)	$	5		$	5		$	5		$	4.88		$	—
	Oil positions:
	Fixed price swaps (NYMEX WTI): (2)
	Hedged volume (MBbls)	16,831			11,599			11,465			4,755			—
	Average price ($/Bbl)	$	92.44		$	96.23		$	90.56		$	89.02		$	—
		2014			2015			2016			2017			2018
	Collars (NYMEX WTI):
	Hedged volume (MBbls)	730			—			—			—			—
	Average floor price ($/Bbl)	$	90		$	—		$	—		$	—		$	—
	Average ceiling price ($/Bbl)	$	102.87		$	—		$	—		$	—		$	—
	Three-way collars (NYMEX WTI):
	Hedged volume (MBbls)	3,103			1,095			—			—			—
	Short put ($/Bbl)	$	72.11		$	70		$	—		$	—		$	—
	Long put ($/Bbl)	$	93.76		$	90		$	—		$	—		$	—
	Short call ($/Bbl)	$	109.79		$	101.62		$	—		$	—		$	—
	Put options (NYMEX WTI):
	Hedged volume (MBbls)	3,960			3,426			3,271			384			—
	Average price ($/Bbl)	$	91.3		$	90		$	90		$	90		$	—
	Three-way collars (ICE Brent):
	Hedged volume (MBbls)	365			—			—			—			—
	Short put ($/Bbl)	$	80		$	—		$	—		$	—		$	—
	Long put ($/Bbl)	$	100		$	—		$	—		$	—		$	—
	Short call ($/Bbl)	$	114.05		$	—		$	—		$	—		$	—
	Natural gas basis differential positions: (3)
	Panhandle basis swaps:
	Hedged volume (MMMBtu)	79,388			87,162			59,954			59,138			16,425
	Hedged differential ($/MMBtu)	$	(0.33	)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)
	NWPL Rockies basis swaps:
	Hedged volume (MMMBtu)	39,718			43,292			46,294			38,880			10,804
	Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	(0.19	)	$	(0.19	)
	MichCon basis swaps:
	Hedged volume (MMMBtu)	9,490			9,344			7,768			7,437			2,044
	Hedged differential ($/MMBtu)	$	0.08		$	0.06		$	0.05		$	0.05		$	0.05
	Houston Ship Channel basis swaps:
	Hedged volume (MMMBtu)	5,256			4,891			4,575			3,604			986
	Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.08	)	$	(0.08	)
	Permian basis swaps:
	Hedged volume (MMMBtu)	4,891			5,074			4,219			4,819			1,314
	Hedged differential ($/MMBtu)	$	(0.21	)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)
	Oil basis differential positions:
	ICE Brent - NYMEX WTI basis swaps:
	Hedged volume (MBbls)	3,650			2,920			—			—			—
	Hedged differential ($/Bbl)	$	11.6		$	11.6		$	—		$	—		$	—
	Oil timing differential positions:
	Trade month roll swaps (NYMEX WTI): (4)
	Hedged volume (MBbls)	9,079			7,251			7,446			6,486			—
	Hedged differential ($/Bbl)	$	0.24		$	0.24		$	0.25		$	0.25		$	—
	(1)	Includes certain outstanding natural gas put options of approximately 10,570 MMMBtu for each of the years ending December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to indirectly hedge revenues associated with NGL production.
	(2)	Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.
	(3)	Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.
	(4)	The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).
During the year ended December 31, 2013, the Company entered into commodity derivative contracts consisting of oil basis swaps for 2013 and natural gas basis swaps for 2013 through 2018. In connection with the Berry acquisition (see Note 2), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including oil swaps, oil trade month roll swaps and oil collars through 2014, and oil basis swaps and oil three-way collars through 2015. These derivative positions are included in the summary table above.
Settled derivatives on natural gas production for the year ended December 31, 2013, included volumes of 173,488 MMMBtu at an average contract price of $5.29 per MMBtu. Settled derivatives on oil production for the year ended December 31, 2013, included volumes of 15,590 MBbls at an average contract price of $95.35 per Bbl. Settled derivatives on natural gas production for the year ended December 31, 2012, included volumes of 140,884 MMMBtu at an average contract price of $5.41 per MMBtu. Settled derivatives on oil production for the year ended December 31, 2012, included volumes of 11,289 MBbls at an average contract price of $97.61 per Bbl. The natural gas derivatives are settled based on the closing price of NYMEX natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX light crude oil for each day of the delivery month.
Balance Sheet Presentation
The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:
		December 31,
		2013			2012
		(in thousands)
Assets:
Commodity derivatives		$	1,048,212		$	1,282,390
Liabilities:
Commodity derivatives		$	222,905		$	405,619
By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facilities or were participants or affiliates of participants in its Credit Facilities at the time it originally entered into the derivatives. The Credit Facilities are secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $1 billion at December 31, 2013. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.
Gains (Losses) on Derivatives
Gains and losses on derivatives were net gains of approximately $178 million, $125 million and $450 million for the years ended December 31, 2013, December 31, 2012, and December 31, 2011, respectively, and are reported on the consolidated statements of operations in “gains on oil and natural gas derivatives.”

Fair_Value_Measurements_on_a_R

Fair Value Measurements on a Recurring Basis	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements on a Recurring Basis	'
	Fair Value Measurements on a Recurring Basis
	The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives.
	Fair Value Hierarchy
	In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
	Financial assets and liabilities recorded in the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:
	Level 1	Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.
	Level 2	Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives and interest rate swaps).
	Level 3	Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.
	When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.
	The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
			December 31, 2013
			Level 2		Netting (1)			Total
			(in thousands)
	Assets:
	Commodity derivatives		$	1,048,212	$	(190,080	)	$	858,132
	Liabilities:
	Commodity derivatives		$	222,905	$	(190,080	)	$	32,825
			December 31, 2012
			Level 2		Netting (1)			Total
			(in thousands)
	Assets:
	Commodity derivatives		$	1,282,390	$	(401,479	)	$	880,911
	Liabilities:
	Commodity derivatives		$	405,619	$	(401,479	)	$	4,140
	(1)	Represents counterparty netting under agreements governing such derivatives.

Other_Property_and_Equipment

Other Property and Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment Disclosure	'
	Other Property and Equipment
	Other property and equipment consists of the following:
		December 31,
		2013			2012
		(in thousands)
	Natural gas plant and pipeline	$	507,342		$	371,292
	Buildings and leasehold improvements	32,658			19,999
	Vehicles	27,964			19,731
	Drilling and other equipment	8,618			6,265
	Furniture and office equipment	65,909			47,623
	Land	5,391			4,278
		647,882			469,188
	Less accumulated depreciation	(110,939		)	(73,721		)
		$	536,943		$	395,467

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	Asset Retirement Obligations
	Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other accrued liabilities” and “other noncurrent liabilities” on the consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for each of the years in the three-year period ended December 31, 2013); and (iv) a credit-adjusted risk-free interest rate (average of 6.2%, 6.8% and 7.5% for the years ended December 31, 2013, December 31, 2012, and December 31, 2011, respectively). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
	The following presents a reconciliation of the Company’s asset retirement obligations:
		December 31,
		2013			2012
		(in thousands)
	Asset retirement obligations at beginning of year	$	151,974		$	71,142
	Liabilities added from acquisitions	98,343			63,663
	Liabilities added from drilling	4,048			1,799
	Liabilities associated with assets sold	(1,092		)	—
	Current year accretion expense	11,938			8,550
	Settlements	(5,136		)	(3,640		)
	Revision of estimates	29,246			10,460
	Asset retirement obligations at end of year	$	289,321		$	151,974

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. With respect to a certain statewide class action case, the parties in this case are currently engaged in settlement negotiations and based on the current status of those negotiations, the Company estimates a range of possible loss of $1 million to $4.5 million, for which an appropriate reserve has been established. For a certain statewide class action royalty payment dispute where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to the Company. Based on the 10th Circuit Court of Appeals’ decision to reverse class certification orders in two unrelated certification cases, the court has permitted additional limited discovery prior to the briefing and hearing on class certification. Briefing and the hearing on class certification have not yet been set by the court. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any. In addition, the Company is involved in various other disputes arising in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
	On March 21, 2013, a purported stockholder class action captioned Nancy P. Assad Trust v. Berry Petroleum Co., et al. was filed in the District Court for the City and County of Denver, Colorado, No. 13-CV-31365. The action names as defendants Berry, the members of its board of directors, Bacchus HoldCo, Inc., a direct wholly owned subsidiary of Berry (“HoldCo”), Bacchus Merger Sub, Inc., a direct wholly owned subsidiary of HoldCo (“Bacchus Merger Sub”), LinnCo, LINN Energy and Linn Acquisition Company, LLC, a direct wholly owned subsidiary of LinnCo (“LinnCo Merger Sub”). On April 5, 2013, an amended complaint was filed, which alleges that the individual defendants breached their fiduciary duties in connection with the transactions by engaging in an unfair sales process that resulted in an unfair price for Berry, by failing to disclose all material information regarding the transactions, and that the entity defendants aided and abetted those breaches of fiduciary duty. The amended complaint seeks a declaration that the transactions are unlawful and unenforceable, an order directing the individual defendants to comply with their fiduciary duties, an injunction against consummation of the transactions, or, in the event they are completed, rescission of the transactions, an award of fees and costs, including attorneys’ and experts’ fees and expenses, and other relief. On May 21, 2013, the Colorado District Court stayed and administratively closed the Nancy P. Assad Trust action in favor of the Hall action described below that is pending in the Delaware Court of Chancery.
	On April  2, 2013, a purported stockholder class action captioned David Hall v. Berry Petroleum Co., et al. was filed in the Delaware Court of Chancery, C.A. No. 8476-VCG. The complaint names as defendants Berry, the members of its board of directors, HoldCo, Bacchus Merger Sub, LinnCo, LINN Energy and LinnCo Merger Sub. The complaint alleges that the individual defendants breached their fiduciary duties in connection with the transactions by engaging in an unfair sales process that resulted in an unfair price for Berry, by failing to disclose all material information regarding the transactions, and that the entity defendants aided and abetted those breaches of fiduciary duty. In December 2013, the parties signed a Memorandum of Understanding to settle the case, and is in the process of seeking court approval of the settlement. The Company is unable to estimate a possible loss, or range of possible loss, if any, at this time.
	On July 9, 2013, Anthony Booth, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of Texas, against LINN Energy, Mark E. Ellis, Kolja Rockov, and David B. Rottino (the “Booth Action”). On July 18, 2013, the Catherine A. Fisher Trust, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of Texas, against the same defendants (the “Fisher Action”). On July 17, 2013, Don Gentry, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of Texas, against LINN Energy, LinnCo, Mark E. Ellis, Kolja Rockov, David B. Rottino, George A. Alcorn, David D. Dunlap, Terrence S. Jacobs, Michael C. Linn, Joseph P. McCoy, Jeffrey C. Swoveland, and the various underwriters for LinnCo’s initial public offering (the “Gentry Action”) (the Booth Action, Fisher Action, and Gentry Action together, the “Texas Federal Actions”). The Texas Federal Actions each assert claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the “Exchange Act”) based on allegations that LINN Energy made false or misleading statements relating to its hedging strategy, the cash flow available for distribution to unitholders, and LINN Energy’s energy production. The Gentry Action asserts additional claims under Sections 11 and 15 of the Securities Act of 1933 based on alleged misstatements relating to these issues in the prospectus and registration statement for LinnCo’s initial public offering. On September 23, 2013, the Southern District of Texas entered an order transferring the Texas Federal Actions to the Southern District of New York so that they could be consolidated with the New York Federal Actions, which are described below.
	On July 10, 2013, David Adrian Luciano, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of New York, against LINN Energy, LinnCo, Mark E. Ellis, Kolja Rockov, David B. Rottino, George A. Alcorn, David D. Dunlap, Terrence S. Jacobs, Michael C. Linn, Joseph P. McCoy, Jeffrey C. Swoveland, and the various underwriters for LinnCo’s initial public offering (the “Luciano Action”). The Luciano Action asserts claims under Sections 11 and 15 of the Securities Act of 1933 based on alleged misstatements relating to LINN Energy’s hedging strategy, the cash flow available for distribution to unitholders, and LINN Energy’s energy production in the prospectus and registration statement for LinnCo’s initial public offering. On July 12, 2013, Frank Donio, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of New York, against LINN Energy, Mark E. Ellis, Kolja Rockov, and David B. Rottino (the “Donio Action”). The Donio Action asserts claims under Sections 10(b) and 20(a) of the Exchange Act based on allegations that LINN Energy made false or misleading statements relating to its hedging strategy, the cash flow available for distribution to unitholders, and LINN Energy’s energy production. Several additional class action cases substantially similar to the Luciano Action and the Donio Action were subsequently filed in the Southern District of New York and assigned to the same judge (the Luciano Action, Donio Action, and all similar subsequently filed New York federal class actions together, the “New York Federal Actions”). The Texas Federal Actions and the New York Federal Actions have now been consolidated in the United States District Court for the Southern District of New York (the “Combined Actions”). In November 2013, LINN Energy filed a motion to dismiss the Combined Actions. The motion is currently pending before the Southern District of New York. There has not been any discovery conducted in the Combined Actions. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any.
	On July 10, 2013, Judy Mesirov, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against Mark E. Ellis, Kolja Rockov, David B. Rottino, Arden L. Walker, Jr., Charlene A. Ripley, Michael C. Linn, Joseph P. McCoy, George A. Alcorn, Terrence S. Jacobs, David D. Dunlap, Jeffrey C. Swoveland, and Linda M. Stephens in the District Court of Harris County, Texas (the “Mesirov Action”). On July 12, 2013, John Peters, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants in the District Court of Harris County, Texas (the “Peters Action”). On August 26, 2013, Joseph Abdalla, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants in the District Court of Harris County, Texas (the “Abdalla Action”) (the Mesirov Action, Peters Action, and Abdalla Actions together, the “Texas State Court Derivative Actions”). On August 19, 2013, the Charlote J. Lombardo Trust of 2004, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants in the United States District Court for the Southern District of Texas (the “Lombardo Action”). On September 30, 2013, the Thelma Feldman Rev. Trust, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants (the “Feldman Rev. Trust Action”). On October 21, 2013, the Parker Family Trust of 2012, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants (the “Parker Family Trust Action”) (the Lombardo Action, Feldman Rev. Trust Action, and Parker Family Trust Action together, the “Texas Federal Court Derivative Actions”) (the Texas State Court Derivative Action and Texas Federal Court Derivative Actions together, the “Texas Derivative Actions”). The Texas Derivative Actions assert derivative claims on behalf of LINN Energy against the individual defendants for alleged breaches of fiduciary duty, waste of corporate assets, mismanagement, abuse of control, and unjust enrichment based on factual allegations similar to those in the Texas Federal Actions and the New York Federal Actions. The cases are in their preliminary stages and it is possible that additional similar actions could be filed in the District Court of Harris County, Texas, or in other jurisdictions. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any.
	In 2008, Lehman Brothers Holdings Inc. and Lehman Brothers Commodity Services Inc. (together “Lehman”), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. In March 2011, the Company and Lehman entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman in the amount of $51 million (the “Company Claim”). In December 2011, a Chapter 11 Plan (“Lehman Plan”) was approved by the Bankruptcy Court. Based on the recovery estimates described in the approved disclosure statement relating to the Lehman Plan, the Company expects to ultimately receive a substantial portion of the Company Claim. During 2012, the Company received approximately $28 million of the Company Claim under the Lehman Plan resulting in a gain of approximately $22 million for the year ended December 31, 2012, and during 2013, the Company received approximately $11 million of the Company Claim, both of which are included in “gains on oil and natural gas derivatives” on the consolidated statements of operations. In the aggregate, the Company has received approximately $39 million of the Company Claim and additional distributions are expected to occur in the future.

Earnings_Per_Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings Per Unit	'
	Earnings Per Unit
	Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect.
	The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net income (loss):
		Year Ended December 31,
		2013			2012			2011
		(in thousands, except per unit data)
	Net income (loss)	$	(691,337	)	$	(386,616	)	$	438,439
	Allocated to participating securities	(5,935		)	(4,575		)	(4,739		)
		$	(697,272	)	$	(391,191	)	$	433,700
	Basic net income (loss) per unit	$	(2.94	)	$	(1.92	)	$	2.52
	Diluted net income (loss) per unit	$	(2.94	)	$	(1.92	)	$	2.51
	Basic weighted average units outstanding	237,544			203,775			172,004
	Dilutive effect of unit equivalents	—			—			725
	Diluted weighted average units outstanding	237,544			203,775			172,729
	Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 4 million and 2 million unit options and warrants for each of the years ended December 31, 2013, and December 31, 2012, respectively. All equivalent units were anti-dilutive for the years ended December 31, 2013, and December 31, 2012. There were no anti-dilutive unit equivalents for the year ended December 31, 2011.

Operating_Leases

Operating Leases	12 Months Ended
	Dec. 31, 2013
Leases, Operating [Abstract]	'
Operating Leases	'
	Operating Leases
	The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2020. The Company recognized expense under operating leases of approximately $7 million, $7 million and $5 million, for the years ended December 31, 2013, December 31, 2012, and December 31, 2011, respectively.
	As of December 31, 2013, future minimum lease payments were as follows (in thousands):
	2014	$	14,222
	2015	11,146
	2016	7,869
	2017	5,958
	2018	5,055
	Thereafter	5,786
		$	50,036

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax and were also subject to state income taxes in the state of Michigan during 2011. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company, except as set forth in the tables below. Amounts recognized for income taxes are reported in “income tax expense (benefit)” on the consolidated statements of operations.
	The Company’s taxable income or loss, which may vary substantially from the net income or net loss reported on the consolidated statements of operations, is includable in the federal and state income tax returns of each unitholder. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholder’s tax attributes.
	Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Income tax expense (benefit) consisted of the following:
		Year Ended December 31,
		2013				2012				2011
		(in thousands)
	Current taxes:
	Federal	$	144			$	2,711			$	4,551
	State	198				439				605
	Deferred taxes:
	Federal	(2,805		)		323				(1,148		)
	State	264				(683		)		1,458
		$	(2,199	)		$	2,790			$	5,466
	As of December 31, 2013, the Company’s taxable entities had approximately $10 million of net operating loss carryforwards for federal income tax purposes which will begin expiring in 2032.
	A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
		Year Ended December 31,
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State, net of federal tax benefit	(0.1	)		0.1			0.5
	Loss excluded from nontaxable entities	(34.6	)		(35.6	)		(34.4	)
	Other items	—			(0.2	)		0.1
	Effective rate	0.3	%		(0.7	)%		1.2	%
	Significant components of the deferred tax assets and liabilities were as follows:
		December 31,
		2013				2012
		(in thousands)
	Deferred tax assets:
	Net operating loss carryforwards	$	1,129			$	—
	Unit-based compensation	21,965				10,579
	Other	7,759				4,924
	Total deferred tax assets	30,853				15,503
	Deferred tax liabilities:
	Property and equipment principally due to differences in depreciation	(12,525		)		(11,049		)
	Other	(1,509		)		(1,055		)
	Total deferred tax liabilities	(14,034		)		(12,104		)
	Net deferred tax assets	$	16,819			$	3,399
	Net deferred tax assets and liabilities were classified on the consolidated balance sheets as follows:
		December 31,
		2013				2012
		(in thousands)
	Deferred tax assets	$	29,204			$	10,318
	Deferred tax liabilities	(10		)		(612		)
	Other current assets	$	29,194			$	9,706
	Deferred tax assets	$	1,649			$	5,186
	Deferred tax liabilities	(14,024		)		(11,493		)
	Other noncurrent liabilities	$	(12,375	)		$	(6,307	)
	In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2013, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.
	In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2013, and December 31, 2012. The tax years 2010 – 2012 remain open to examination for federal income tax purposes.

Supplemental_Disclosures_to_th

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows	12 Months Ended
	Dec. 31, 2013
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]	'
Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows	'
	Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows
	“Other accrued liabilities” reported on the consolidated balance sheets include the following:
		December 31,
		2013			2012
		(in thousands)
	Accrued compensation	$	55,257		$	35,431
	Accrued interest	93,998			72,668
	Other	14,120			7,146
		$	163,375		$	115,245
	Supplemental disclosures to the consolidated statements of cash flows are presented below:
		Year Ended December 31,
		2013			2012			2011
		(in thousands)
	Cash payments for interest, net of amounts capitalized	$	392,607		$	343,331		$	247,217
	Cash payments for income taxes	$	14		$	366		$	487
	Noncash investing and financing activities:
	In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follow:
	Fair value of assets acquired	$	5,726,681		$	2,923,990		$	1,523,466
	Cash paid, net of cash acquired	(109,350		)	(2,640,475		)	(1,500,193		)
	Units issued in connection with the Berry acquisition	(2,781,888		)	—			—
	Receivables from sellers	(93		)	2,132			3,557
	Payables to sellers	(6,854		)	443			(4,847		)
	Liabilities assumed	$	2,828,496		$	286,090		$	21,983
	Included in “acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired” on the consolidated statements of cash flows for the year ended December 31, 2013, is approximately $170 million paid by the Company towards the future funding commitment related to the joint-venture agreement entered into with Anadarko (see Note 2).
	For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $6 million and $5 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2013, and December 31, 2012, respectively, and primarily represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.
	The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facilities. At December 31, 2013, and December 31, 2012, net outstanding checks of approximately $48 million and $35 million, respectively, were reclassified and included in “accounts payable and accrued expenses” on the consolidated balance sheets. The Company presents net outstanding checks as cash flows from financing activities on the consolidated statements of cash flows.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Related Party Transactions
	LinnCo
	LinnCo, an affiliate of LINN Energy, was formed on April 30, 2012. LinnCo’s initial sole purpose was to own units in LINN Energy. In connection with the acquisition of Berry, LinnCo amended its limited liability company agreement to permit, among other things, the acquisition and subsequent contribution of assets to LINN Energy. All of LinnCo’s common shares are held by the public. In October 2012, LinnCo completed its IPO and used the net proceeds of approximately $1.2 billion from the offering to acquire 34,787,500 of LINN Energy’s units.
	On December 16, 2013, LinnCo and LINN Energy completed the previously-announced transactions contemplated by the merger agreement, as amended, under which Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement between LinnCo and LINN Energy, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units valued at approximately $2.8 billion.
	As of December 31, 2013, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy. At December 31, 2013, LinnCo owned approximately 39% of LINN Energy’s outstanding units.
	LINN Energy has agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any legal, accounting, tax advisory, financial advisory and engineering fees, printing costs or other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity. These expenses include costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees. In addition, the Company has agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities.
	For the year ended December 31, 2013, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $42 million, of which approximately $22 million had been paid by LINN Energy on LinnCo’s behalf. The expenses for the year ended December 31, 2013, include approximately $40 million of transaction costs related to the Berry acquisition (see Note 2), including approximately $9 million of noncash share-based compensation expense. The expenses for the year ended December 31, 2013, also include approximately $2 million related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses. The offering costs of approximately $388,000 were incurred in connection with LinnCo’s registration statement on Form S-4 also related to the Berry acquisition. All expenses and costs paid by LINN Energy on LinnCo’s behalf are accounted for as investment at cost.
	During the year ended December 31, 2013, the Company paid approximately $101 million in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy.
	Other
	One of the Company’s directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the years ended December 31, 2013, and December 31, 2012, the Company paid approximately $26 million and $21 million, respectively, to Superior and its subsidiaries for services rendered to the Company. The transactions associated with these payments were consummated on terms equivalent to those that prevail in arm’s-length transactions.

Subsidiary_Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2013
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Subsidiary Guarantors	'
	Subsidiary Guarantors
	LINN Energy, LLC’s November 2019 Senior Notes, May 2019 Senior Notes and 2010 Issued Notes are guaranteed by all of the Company’s material subsidiaries, other than Berry Petroleum Company, LLC, which is an indirect wholly owned, unrestricted subsidiary of the Company. The following condensed consolidating financial information presents the financial information of LINN Energy, LLC, the guarantor subsidiaries and the non-guarantor subsidiary at December 31, 2013, and for the year ended December 31, 2013, in accordance with SEC Regulation S-X Rule 3-10. The condensed consolidating financial information for the co-issuer, Linn Energy Finance Corp., is not presented as it has no assets, operations or cash flows. Balances are as of December 31, 2013, and results of operations and cash flows of Berry Petroleum Company, LLC are reflected since December 16, 2013, the date of acquisition (see Note 2). The financial information may not necessarily be indicative of the financial position or results of operations had the guarantor subsidiaries or non-guarantor subsidiary operated as independent entities. Condensed consolidating financial information is not provided for 2012 or 2011 since during those periods, the Company was a holding company that had no independent assets or operations of its own, the guarantees under each series of notes were full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors were minor. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.
	CONDENSED CONSOLIDATING BALANCE SHEETS
	31-Dec-13
		LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
								Guarantor Subsidiary
		(in thousands)
	ASSETS
	Current assets:
	Cash and cash equivalents	$	52		$	1,078		$	51,041		$	—		$	52,171
	Accounts receivable – trade, net	—			365,347			122,855			—			488,202
	Accounts receivable – affiliates	4,212,348			16,950			—			(4,229,298		)	—
	Derivative instruments	—			170,534			5,596			—			176,130
	Other current assets	330			68,274			30,833			—			99,437
	Total current assets	4,212,730			622,183			210,325			(4,229,298		)	815,940
	Noncurrent assets:
	Oil and natural gas properties (successful efforts method)	—			13,074,900			4,813,659			—			17,888,559
	Less accumulated depletion and amortization	—			(3,535,890		)	(10,394		)	—			(3,546,284		)
		—			9,539,010			4,803,265			—			14,342,275
	Other property and equipment	—			564,756			83,126			—			647,882
	Less accumulated depreciation	—			(110,706		)	(233		)	—			(110,939		)
		—			454,050			82,893			—			536,943
	Derivative instruments	—			679,491			2,511			—			682,002
	Notes receivable – affiliates	86,200			—			—			(86,200		)	—
	Investments in consolidated subsidiaries	7,139,737			—			—			(7,139,737		)	—
	Other noncurrent assets, net	108,785			10,968			8,051			—			127,804
		7,334,722			690,459			10,562			(7,225,937		)	809,806
	Total noncurrent assets	7,334,722			10,683,519			4,896,720			(7,225,937		)	15,689,024
	Total assets	$	11,547,452		$	11,305,702		$	5,107,045		$	(11,455,235	)	$	16,504,964
	LIABILITIES AND UNITHOLDERS’ CAPITAL
	Current liabilities:
	Accounts payable and accrued expenses	$	14,529		$	587,774		$	247,321		$	—		$	849,624
	Accounts payable – affiliates	—			4,212,348			16,950			(4,229,298		)	—
	Derivative instruments	—			7,783			20,393			—			28,176
	Other accrued liabilities	75,071			59,311			28,993			—			163,375
	Current portion of long-term debt	—			—			211,558			—			211,558
	Total current liabilities	89,600			4,867,216			525,215			(4,229,298		)	1,252,733
	Noncurrent liabilities:
	Credit facilities	1,560,000			—			1,173,175			—			2,733,175
	Term loan	500,000			—			—			—			500,000
	Senior notes, net	4,809,055			—			916,428			—			5,725,483
	Notes payable – affiliates	—			86,200			—			(86,200		)	—
	Derivative instruments	—			—			4,649			—			4,649
	Other noncurrent liabilities	—			205,406			192,091			—			397,497
	Total noncurrent liabilities	6,869,055			291,606			2,286,343			(86,200		)	9,360,804
	Unitholders’ capital:
	Units issued and outstanding	6,282,747			4,833,354			2,315,460			(7,139,737		)	6,291,824
	Accumulated income (deficit)	(1,693,950		)	1,313,526			(19,973		)	—			(400,397		)
		4,588,797			6,146,880			2,295,487			(7,139,737		)	5,891,427
	Total liabilities and unitholders’ capital	$	11,547,452		$	11,305,702		$	5,107,045		$	(11,455,235	)	$	16,504,964
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	For the Year Ended December 31, 2013
		LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
								Guarantor Subsidiary
		(in thousands)
	Revenues and other:
	Oil, natural gas and natural gas liquids sales	$	—		$	2,022,916		$	50,324		$	—		$	2,073,240
	Gains (losses) on oil and natural gas derivatives	—			182,906			(5,049		)	—			177,857
	Marketing revenues	—			53,772			399			—			54,171
	Other revenues	—			24,943			1,444			—			26,387
		—			2,284,537			47,118			—			2,331,655
	Expenses:
	Lease operating expenses	—			357,113			15,410			—			372,523
Transportation expenses	—			125,864			2,576			—			128,440
Marketing expenses	—			36,259			1,633			—			37,892
General and administrative expenses	—			215,973			20,298			—			236,271
Exploration costs	—			5,251			—			—			5,251
Depreciation, depletion and amortization	—			818,466			10,845			—			829,311
Impairment of long-lived assets	—			828,317			—			—			828,317
Taxes, other than income taxes	—			136,501			2,130			—			138,631
Losses on sale of assets and other, net	724			2,705			10,208			—			13,637
	724			2,526,449			63,100			—			2,590,273
Other income and (expenses):
Interest expense, net of amounts capitalized	(415,670		)	(1,504		)	(3,963		)	—			(421,137		)
Interest expense – affiliates	—			(5,543		)	—			5,543			—
Loss on extinguishment of debt	(5,304		)	—			—			—			(5,304		)
Interest income – affiliates	5,543			—			—			(5,543		)	—
Other, net	(8,283		)	(166		)	(28		)	—			(8,477		)
	(423,714		)	(7,213		)	(3,991		)	—			(434,918		)
Loss before income taxes	(424,438		)	(249,125		)	(19,973		)	—			(693,536		)
Income tax benefit	—			2,199			—			—			2,199
Net loss	$	(424,438	)	$	(246,926	)	$	(19,973	)	$	—		$	(691,337	)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2013
	LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
							Guarantor Subsidiary
	(in thousands)
Cash flow from operating activities:
Net loss	$	(424,438	)	$	(246,926	)	$	(19,973	)	$	—		$	(691,337	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			818,466			10,845			—			829,311
Impairment of long-lived assets	—			828,317			—			—			828,317
Unit-based compensation expenses	—			42,703			—			—			42,703
Loss on extinguishment of debt	5,304			—			—			—			5,304
Amortization and write-off of deferred financing fees	22,122			—			(615		)	—			21,507
Losses on sale of assets and other, net	—			37,232			—			—			37,232
Deferred income tax	—			(2,541		)	—			—			(2,541		)
Derivatives activities:
Total (gains) losses	—			(182,906		)	5,049			—			(177,857		)
Cash settlements	—			248,862			—			—			248,862
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net	—			17,754			71,434			—			89,188
(Increase) decrease in accounts receivable – affiliates	(120,967		)	(16,950		)	—			137,917			—
(Increase) decrease in other assets	(330		)	5,896			10,613			—			16,179
Increase (decrease) in accounts payable and accrued expenses	178			(52,143		)	(25,028		)	—			(76,993		)
Increase (decrease) in accounts payable and accrued expenses – affiliates	—			120,967			16,950			(137,917		)	—
Increase (decrease) in other liabilities	2,092			6,842			(12,597		)	—			(3,663		)
Net cash provided by (used in) operating activities	(516,039		)	1,625,573			56,678			—			1,166,212
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	—			(730,326		)	451,113			—			(279,213		)
Development of oil and natural gas properties	—			(1,060,547		)	(17,478		)	—			(1,078,025		)
Purchases of other property and equipment	—			(92,352		)	—			—			(92,352		)
Investment in affiliates	435,000			—			—			(435,000		)	—
Change in notes receivable with affiliate	(26,700		)	—			—			26,700			—
Proceeds from sale of properties and equipment and other	(22,039		)	218,312			—			—			196,273
Net cash provided by (used in) investing activities	386,261			(1,664,913		)	433,635			(408,300		)	(1,253,317		)
	LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
							Guarantor Subsidiary
	(in thousands)
Cash flow from financing activities:
Proceeds from borrowings	2,230,000			—			—			—			2,230,000
Repayments of debt	(1,404,898		)	—			—			—			(1,404,898		)
Distributions to unitholders	(682,241		)	—			—			—			(682,241		)
Financing fees, offering expenses and other, net	(13,138		)	12,422			(4,272		)	—			(4,988		)
Change in note payable with affiliate	—			26,700			—			(26,700		)	—
Capital contribution – affiliates	—			—			(435,000		)	435,000			—
Excess tax benefit from unit-based compensation	—			160			—			—			160
Net cash provided by (used in) financing activities	129,723			39,282			(439,272		)	408,300			138,033
Net increase (decrease) in cash and cash equivalents	(55		)	(58		)	51,041			—			50,928
Cash and cash equivalents:
Beginning	107			1,136			—			—			1,243
Ending	$	52		$	1,078		$	51,041		$	—		$	52,171

SEC_Inquiry

SEC Inquiry	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
SEC Inquiry	'
	SEC Inquiry
	As disclosed on July 1, 2013, the Company and its affiliate, LinnCo, have been notified by the staff of the SEC that its Fort Worth Regional Office has commenced an inquiry regarding LINN Energy and LinnCo (the “SEC inquiry”). The SEC staff is investigating whether any violations of federal securities laws have occurred. The SEC staff has requested the production of documents and communications that are potentially relevant to, among other things, LINN Energy and LinnCo’s use of non-GAAP financial measures and disclosures related to LINN Energy’s hedging strategy. The SEC staff has stated that the fact of the inquiry should not be construed as an indication that the SEC or its staff has a negative view of any entity, individual or security. Both LINN Energy and LinnCo are cooperating fully with the SEC in this matter. LINN Energy and LinnCo are unable to predict the timing or outcome of the SEC inquiry or estimate the nature or amount of any possible sanction the SEC could seek to impose, which could include a fine, penalty, or court or administrative order prohibiting specific conduct, or a potential restatement of LINN Energy’s or LinnCo’s financial statements, any of which could be material. No provision for losses has been recorded for this exposure.

Supplemental_Oil_and_Natural_G

Supplemental Oil and Natural Gas Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Supplemental Oil and Natural Gas Data	'
	The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.”
	Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
	Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:
			Year Ended December 31,
			2013				2012				2011
			(in thousands)
	Property acquisition costs: (1)
	Proved		$	3,740,379			$	2,531,419			$	1,328,328
	Unproved		1,638,302				181,124				188,409
	Exploration costs		13,096				452				80
	Development costs		1,153,770				1,062,043				639,395
	Asset retirement costs		7,351				4,675				2,427
	Total costs incurred		$	6,552,898			$	3,779,713			$	2,158,639
	(1)	See Note 2 for details about the Company’s acquisitions.
	Oil and Natural Gas Capitalized Costs
	Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:
			December 31,
			2013				2012
			(in thousands)
	Proved properties:
	Leasehold acquisition		$	12,277,089			$	8,603,888
	Development		3,660,277				2,553,127
	Unproved properties		1,951,193				454,315
			17,888,559				11,611,330
	Less accumulated depletion and amortization		(3,546,284		)		(2,025,656		)
			$	14,342,275			$	9,585,674
	Results of Oil and Natural Gas Producing Activities
	The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below:
			Year Ended December 31,
			2013				2012				2011
			(in thousands)
	Revenues and other:
	Oil, natural gas and natural gas liquid sales		$	2,073,240			$	1,601,180			$	1,162,037
	Gains on oil and natural gas derivatives		177,857				124,762				449,940
			2,251,097				1,725,942				1,611,977
	Production costs:
	Lease operating expenses		372,523				317,699				232,619
	Transportation expenses		128,440				77,322				28,358
	Severance and ad valorem taxes		139,202				130,805				78,458
			640,165				525,826				339,435
	Other costs:
	Exploration costs		5,251				1,915				2,390
	Depletion and amortization		790,320				579,382				320,096
	Impairment of long-lived assets		828,317				422,499				—
	Gains on sale of assets and other, net		(138		)		(1,369		)		(1,001		)
	Texas margin tax (benefit) expense		458				(787		)		1,599
			1,624,208				1,001,640				323,084
	Results of operations		$	(13,276	)		$	198,476			$	949,458
	There is no federal tax provision included in the results above because the Company’s subsidiaries subject to federal tax do not own any of the Company’s oil and natural gas interests. Limited liability companies are subject to Texas margin tax and were also subject to state income taxes in the state of Michigan during 2011; however, no taxes were assessed in this state for producing activities during that year. See Note 14 for additional information about income taxes.
	Proved Oil, Natural Gas and NGL Reserves
	The proved reserves of oil, natural gas and NGL of the Company have been prepared by the independent engineering firm, DeGolyer and MacNaughton. In accordance with SEC regulations, reserves at December 31, 2013, December 31, 2012, and December 31, 2011, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below:
			Year Ended December 31, 2013
			Natural Gas			Oil			NGL			Total
			(Bcf)			(MMBbls)			(MMBbls)			(Bcfe)
	Proved developed and undeveloped reserves:
	Beginning of year		2,571			191.5			179.4			4,796
	Revisions of previous estimates		(17	)		(21.3	)		(2.0	)		(157	)
	Purchase of minerals in place		356			191.1			17.8			1,610
	Sales of minerals in place		(24	)		(5.2	)		(2.9	)		(73	)
	Extensions, discoveries and other additions		286			21.7			18.5			527
	Production		(162	)		(12.2	)		(10.8	)		(300	)
	End of year		3,010			365.6			200			6,403
	Proved developed reserves:
Beginning of year		1,661			131.4			113			3,127
End of year		2,027			252.4			133.2			4,340
Proved undeveloped reserves:
Beginning of year		910			60.1			66.4			1,669
End of year		983			113.2			66.8			2,063
		Year Ended December 31, 2012
		Natural Gas (Bcf)			Oil			NGL (MMBbls)			Total
					(MMBbls)						(Bcfe)
Proved developed and undeveloped reserves:
Beginning of year		1,675			189			93.5			3,370
Revisions of previous estimates		(559	)		(26.5	)		(14.1	)		(803	)
Purchase of minerals in place		1,176			23.1			75.3			1,766
Extensions, discoveries and other additions		407			16.6			33.7			709
Production		(128	)		(10.7	)		(9.0	)		(246	)
End of year		2,571			191.5			179.4			4,796
Proved developed reserves:
Beginning of year		998			124.8			47.8			2,034
End of year		1,661			131.4			113			3,127
Proved undeveloped reserves:
Beginning of year		677			64.2			45.7			1,336
End of year		910			60.1			66.4			1,669
		Year Ended December 31, 2011
		Natural Gas (Bcf)			Oil			NGL (MMBbls)			Total
					(MMBbls)						(Bcfe)
Proved developed and undeveloped reserves:
Beginning of year		1,233			156.4			70.9			2,597
Revisions of previous estimates		(71	)		(9.2	)		0.9			(121	)
Purchase of minerals in place		337			39.3			1			579
Extensions, discoveries and other additions		240			10.3			24.6			450
Production		(64	)		(7.8	)		(3.9	)		(135	)
End of year		1,675			189			93.5			3,370
Proved developed reserves:
Beginning of year		805			103			39.9			1,662
End of year		998			124.8			47.8			2,034
Proved undeveloped reserves:
Beginning of year		428			53.4			31			935
End of year		677			64.2			45.7			1,336
The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents at a rate of one barrel per six Mcf.
Proved reserves increased by approximately 1,607 Bcfe to approximately 6,403 Bcfe for the year ended December 31, 2013, from 4,796 Bcfe for the year ended December 31, 2012. The year ended December 31, 2013, includes 157 Bcfe of negative revisions of previous estimates, due primarily to 100 Bcfe of negative revisions due to asset performance and 109 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs, partially offset by 52 Bcfe of positive revisions primarily due to higher natural gas prices. During the year ended December 31, 2013, three acquisitions increased proved reserves by approximately 1,610 Bcfe and the sale of the Panther Operated Cleveland Properties decreased proved reserves by approximately 73 Bcfe. In addition, extensions and discoveries, primarily from 557 productive wells drilled during the year, contributed approximately 527 Bcfe to the increase in proved reserves.
Proved reserves increased by approximately 1,426 Bcfe to approximately 4,796 Bcfe for the year ended December 31, 2012, from 3,370 Bcfe for the year ended December 31, 2011. The year ended December 31, 2012, includes 803 Bcfe of negative revisions of previous estimates, due primarily to 340 Bcfe of negative revisions due to asset performance, 248 Bcfe of negative revisions primarily due to lower natural gas prices and 215 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs. During the year ended December 31, 2012, seven acquisitions increased proved reserves by approximately 1,766 Bcfe. In addition, extensions and discoveries, primarily from 436 productive wells drilled during the year, contributed approximately 709 Bcfe to the increase in proved reserves.
Proved reserves increased by approximately 773 Bcfe to approximately 3,370 Bcfe for the year ended December 31, 2011, from 2,597 Bcfe for the year ended December 31, 2010. The year ended December 31, 2011, includes 121 Bcfe of negative revisions of previous estimates, due primarily to 153 Bcfe of negative revisions due to asset performance. These negative revisions were partially offset by 32 Bcfe of positive revisions primarily due to higher oil prices. During the year ended December 31, 2011, 12 acquisitions increased proved reserves by approximately 579 Bcfe. In addition, extensions and discoveries, primarily from 292 productive wells drilled during the year, contributed approximately 450 Bcfe to the increase in proved reserves.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves
Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to Texas margin tax and were also subject to state income taxes in the state of Michigan during 2011; however, these amounts are not material. See Note 14 for additional information about income taxes.
		December 31,
		2013				2012				2011
		(in thousands)
Future estimated revenues		$	51,112,346			$	30,374,380			$	29,319,369
Future estimated production costs		(19,306,728		)		(11,460,854		)		(9,464,319		)
Future estimated development costs		(5,110,896		)		(3,574,058		)		(2,848,497		)
Future net cash flows		26,694,722				15,339,468				17,006,553
10% annual discount for estimated timing of cash flows		(14,795,393		)		(9,266,487		)		(10,391,693		)
Standardized measure of discounted future net cash flows		$	11,899,329			$	6,072,981			$	6,614,860
Representative NYMEX prices: (1)
Natural gas (MMBtu)		$	3.67			$	2.76			$	4.12
Oil (Bbl)		$	96.89			$	94.64			$	95.84
(1)	In accordance with SEC regulations, reserves at December 31, 2013, December 31, 2012, and December 31, 2011, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.
The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:
		Year Ended December 31,
		2013				2012				2011
		(in thousands)
Sales and transfers of oil, natural gas and NGL produced during the period		$	(1,433,075	)		$	(1,075,354	)		$	(822,602	)
Changes in estimated future development costs		317,064				289,762				27,236
Net change in sales and transfer prices and production costs related to future production		203,370				(1,463,820		)		784,308
Purchase of minerals in place		5,113,335				2,153,651				1,452,169
Sale of minerals in place		(139,384		)		—				—
Extensions, discoveries, and improved recovery		801,254				413,702				552,704
Previously estimated development costs incurred during the period		444,861				442,322				306,827
Net change due to revisions in quantity estimates		(220,224		)		(1,595,302		)		(292,343		)
Accretion of discount		607,298				661,486				422,353
Changes in production rates and other		131,849				(368,326		)		(39,324		)
		$	5,826,348			$	(541,879	)		$	2,391,328
The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

Quarterly_Financial_Data

Quarterly Financial Data	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
Quarterly Financial Information	'
	The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.”
	Quarterly Financial Data
			Quarters Ended
			31-Mar			30-Jun			30-Sep			December 31 (2)
			(in thousands, except per unit amounts)
	2013:00:00
	Oil, natural gas and natural gas liquid sales		$	462,732		$	488,207		$	537,671		$	584,630
	Gains (losses) on oil and natural gas derivatives		(108,370		)	326,733			(63,931		)	23,425
	Total revenues and other		369,060			838,825			494,562			629,208
	Total expenses (1)		478,235			385,540			420,803			1,292,058
	(Gain) losses on sale of assets and other, net		3,172			(959		)	827			10,597
	Net income (loss)		(221,885		)	345,157			(30,060		)	(784,549		)
	Net income (loss) per unit:
	Basic		$	(0.96	)	$	1.47		$	(0.13	)	$	(3.15	)
	Diluted		$	(0.96	)	$	1.46		$	(0.13	)	$	(3.15	)
	(1)	Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.
	(2)	Includes the results of operations of the Berry Acquisition since the acquisition date (see Note 2).
			Quarters Ended
			31-Mar			30-Jun			30-Sep			December 31
			(in thousands, except per unit amounts)
	2012:00:00
	Oil, natural gas and natural gas liquid sales		$	348,895		$	347,227		$	444,082		$	460,976
	Gains (losses) on oil and natural gas derivatives		2,031			439,647			(411,405		)	94,489
	Total revenues and other		354,090			800,597			48,328			571,225
	Total expenses (1)		269,092			460,655			376,323			656,221
	(Gain) losses on sale of assets and other, net		1,494			(2		)	16			31
	Net income (loss)		(6,202		)	237,086			(430,005		)	(187,495		)
	Net income (loss) per unit:
	Basic		$	(0.04	)	$	1.19		$	(2.18	)	$	(0.83	)
	Diluted		$	(0.04	)	$	1.19		$	(2.18	)	$	(0.83	)
	(1)	Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.

Basis_of_Presentation_and_Sign1

Basis of Presentation and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Principles of Consolidation and Reporting	'
	Principles of Consolidation and Reporting
	The Company presents its financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. The Company’s other investment is carried at cost.
	The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss), unitholders’ capital or cash flows.
Use of Estimates	'
	Use of Estimates
	The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. Actual results could differ from these estimates. Any changes in estimates resulting from continuous changes in the economic environment will be reflected in the financial statements in future periods.
Cash Equivalents	'
	Cash Equivalents
	For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows.
Accounts Receivable - Trade, Net	'
	Accounts Receivable – Trade, Net
	Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million at December 31, 2013, and approximately $450,000 at December 31, 2012.
Inventories	'
	Inventories
	Materials, supplies and commodity inventories are valued at the lower of average cost or market.
Oil and Natural Gas Properties	'
	Oil and Natural Gas Properties
	Proved Properties
	The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively.
	The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $2 million for each of the years ended December 31, 2013, December 31, 2012, and December 31, 2011.
	Impairment of Proved Properties
	Based on the analysis described above, for the year ended December 31, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $791 million associated with proved oil and natural gas properties in the Granite Wash formation related to asset performance resulting in reserve revisions and a decline in commodity prices. For the year ended December 31, 2012, the Company recorded a noncash impairment charge, before and after tax, of approximately $422 million associated with proved oil and natural gas properties in the Mississippi Shelf and Mayfield related to the SEC five-year development limitation on PUDs and a decline in commodity prices. The Company recorded no impairment charge for the year ended December 31, 2011. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
	Unproved Properties
	Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past.
	Exploration Costs
	Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $5 million for the year ended December 31, 2013, and approximately $2 million for the years ended December 31, 2012, and December 31, 2011, which are included in “exploration costs” on the consolidated statements of operations.
Impairment of Proved Properties	'
	Impairment of Proved Properties
	Based on the analysis described above, for the year ended December 31, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $791 million associated with proved oil and natural gas properties in the Granite Wash formation related to asset performance resulting in reserve revisions and a decline in commodity prices. For the year ended December 31, 2012, the Company recorded a noncash impairment charge, before and after tax, of approximately $422 million associated with proved oil and natural gas properties in the Mississippi Shelf and Mayfield related to the SEC five-year development limitation on PUDs and a decline in commodity prices. The Company recorded no impairment charge for the year ended December 31, 2011. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
Other Property and Equipment	'
	Other Property and Equipment
	Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from three to 39 years for the individual asset or group of assets.
Revenue Recognition	'
	Revenue Recognition
	Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.
	The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2013, and December 31, 2012, the Company had natural gas production imbalance receivables of approximately $27 million and $28 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $16 million and $18 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets.
	The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing sales and marketing expenses.
	The Company generates electricity with excess natural gas, which it uses to serve certain of its operating facilities in California. Any excess electricity is sold to the California wholesale power market. This revenue is included in “other revenues” on the consolidated statements of operations.
Restricted Cash	'
	Restricted Cash
	Restricted cash of approximately $6 million and $5 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2013, and December 31, 2012, respectively, and primarily represents cash the Company has deposited into a separate account and designated for asset retirement obligations in accordance with contractual agreements.
Derivative Instruments	'
	Derivative Instruments
	The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. These transactions are primarily in the form of swap contracts and put options. In addition, the Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. At December 31, 2013, the Company had no outstanding interest rate swap agreements.
	As part of the Berry acquisition (see Note 2), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price.
	Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.
Unit-Based Compensation	'
	Unit-Based Compensation
	The Company recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based awards granted to employees and nonemployee directors. The fair value of unit-based awards, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company currently does not have any awards accounted for as liability awards.
	The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. See Note 5 for additional details about the Company’s accounting for unit-based compensation.
	The benefit of tax deductions in excess of recognized compensation costs is required to be reported as financing cash flow rather than operating cash flow. This requirement reduces net operating cash flow and increases net financing cash flow in periods in which such tax benefit exists. The amount of the Company’s excess tax benefit is also reported in “excess tax benefit from unit-based compensation” on the consolidated statements of unitholders’ capital.
Deferred Financing Fees	'
	Deferred Financing Fees
	The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2013, and December 31, 2012, net deferred financing fees of approximately $114 million are included in “other noncurrent assets” on the consolidated balance sheets. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense. For the years ended December 31, 2013, December 31, 2012, and December 31, 2011, amortization expense of approximately $18 million, $13 million and $16 million, respectively, is included in “interest expense, net of amounts capitalized.” For the years ended December 31, 2012, and December 31, 2011, approximately $8 million and $1 million, respectively, were written off to “other, net” on the consolidated statements of operations related to amendments of the LINN Credit Facility (as defined in Note 6). No fees related to amendments of the Credit Facilities (as defined in Note 6) were written off and charged to expense during the year ended December 31, 2013.
Fair Value of Financial Instruments	'
	Fair Value of Financial Instruments
	The carrying values of the Company’s receivables, payables and Credit Facilities are estimated to be substantially the same as their fair values at December 31, 2013, and December 31, 2012. See Note 6 for fair value disclosures related to the Company’s other outstanding debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments.
Income Taxes	'
	Income Taxes
	The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income tax and recognition has not been given to federal and state income taxes for the operations of the Company except as described below.
	Limited liability companies are subject to Texas margin tax and were also subject to state income taxes in the state of Michigan during 2011. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes, which are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and tax carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 14 for detail of amounts recorded in the consolidated financial statements.

Acquisitions_JointVenture_Fund1

Acquisitions, Joint-Venture Funding and Divestiture (Tables)	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	'
	The purchase price is as follows (in thousands, except units and closing unit price):
	LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674
	Closing price of LINN Energy units on December 16, 2013	$	29.47
	LINN Energy unit consideration	$	2,763,009
	Employee unit-based awards	$	18,879
	Total purchase price	$	2,781,888
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	'
	The following presents the values assigned to the net assets acquired in the Permian Basin acquisition as of the acquisition date (in thousands):
	Assets:
	Current	$	1,124
	Noncurrent	10
	Oil and natural gas properties	531,335
	Total assets acquired	532,469
	Liabilities:
	Current	1,808
	Asset retirement obligations, current and noncurrent	2,775
	Total liabilities assumed	4,583
	Net assets acquired	$	527,886
	The following presents the values assigned to the net assets acquired as of the acquisition date (in thousands):
	Assets:
	Cash	$	451,113
	Current	249,564
	Noncurrent	97,202
	Oil and natural gas properties	4,791,394
	Total assets acquired	5,589,273
	Liabilities:
	Current	310,105
	Noncurrent	100,809
	Asset retirement obligations, current and noncurrent	94,612
	Long-term debt, including current portion	2,301,859
	Total liabilities assumed	2,807,385
	Net assets acquired	$	2,781,888
Schedule of Pro Forma Results of Operations	'
	The pro forma financial information has been prepared for informational purposes only and does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The pro forma financial information does not give effect to the costs of any integration activities or benefits that may result from the realization of future cost savings from operating efficiencies, or any other synergies that may result from the transactions and changes in commodity and share prices.
			Year Ended
			December 31,
			2013			2012
			(in thousands, except
			per unit amounts)
	Total revenues and other		$	3,443,246		$	2,989,410
	Total operating expenses		$	3,366,987		$	2,572,921
	Net income (loss)		$	(445,965	)	$	(131,313	)
	Net income (loss) per unit:
	Basic		$	(1.36	)	$	(0.46	)
	Diluted		$	(1.36	)	$	(0.46	)

UnitBased_Compensation_and_Oth1

Unit-Based Compensation and Other Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Unit Based Compensation and Other Benefit Plans [Abstract]	'
Employee Service Share-Based Compensation Expense	'
	A summary of unit-based compensation expenses included in the consolidated statements of operations is presented below:
			Year Ended December 31,
			2013			2012			2011
			(in thousands)
	General and administrative expenses		$	37,375		$	27,641		$	21,131
	Lease operating expenses		5,328			1,892			1,112
	Total unit-based compensation expenses		$	42,703		$	29,533		$	22,243
	Income tax benefit		$	15,779		$	10,912		$	8,219
Nonvested Units	'
	A summary of the status of the nonvested units as of December 31, 2013, is presented below:
			Number of		Weighted Average
			Nonvested		Grant-Date
			Units		Fair Value
	Nonvested units at December 31, 2012		1,953,131		$	36.16
	Granted		1,652,711		$	30.71
	Vested		(889,767	)	$	34.63
	Forfeited		(144,665	)	$	37.09
	Nonvested units at December 31, 2013		2,571,410		$	33.14
Unit Options Activity	'
	The following provides information related to unit option activity for the year ended December 31, 2013:
			Number of		Weighted Average			Weighted Average Remaining Contractual Life in Years		Aggregate Intrinsic Value in Millions
			Units Underlying Options		Exercise Price Per Unit
	Outstanding at December 31, 2012		4,642,805		$	35.25		6.28		$	16
	Berry assumed		2,237,593		$	20.58
	Exercised		(117,175	)	$	18.79
	Forfeited or expired		(330,000	)	$	39.55
	Outstanding at December 31, 2013		6,433,223		$	30.22		6.66		$	33
	Exercisable at December 31, 2013		3,318,226		$	21.08		7.48		$	33
Valuation Assumptions	'
	The fair values of the Company’s unit option grants were based upon the following assumptions:
		2013 (1)		2012
	Expected volatility	29.65% – 50.88%		34.10%
	Expected distributions	9.84%		7.25%
	Risk-free rate	0.13% – 1.55%		0.67%
	Expected term	0.68 years – 5 years		5 years

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Summary of Outstanding Debt	'
			December 31,
			2013			2012
			(in millions, except percentages)
	Berry credit facility (1) (2)		$	1,173		$	—
	LINN credit facility (3)		1,560			1,180
	Term loan (4)		500			—
	10.25% Berry senior notes due June 2014 (2)		205			—
	11.75% senior notes due May 2017		—			41
	9.875% senior notes due July 2018		—			14
	6.50% senior notes due May 2019		750			750
	6.25% senior notes due November 2019		1,800			1,800
	8.625% senior notes due April 2020		1,300			1,300
	6.75% Berry senior notes due November 2020 (2)		300			—
	7.75% senior notes due February 2021		1,000			1,000
	6.375% Berry senior notes due September 2022 (2)		600			—
	Net unamortized discounts and premiums		(18		)	(47		)
	Total debt, net		9,170			6,038
	Less current maturities		(211		)	—
	Total long-term debt, net		$	8,959		$	6,038
	(1)	Variable interest rate of 2.67% at December 31, 2013.
	(2)	Assumed on December 16, 2013.
	(3)	Variable interest rates of 1.92% and 1.97% at December 31, 2013, and December 31, 2012, respectively.
	(4)	Variable interest rate of 2.67% at December 31, 2013.
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	'
			December 31, 2013						December 31, 2012
			Carrying			Fair Value			Carrying		Fair Value
			Value						Value
			(in millions)
	Credit Facilities		$	2,733		$	2,733		$	1,180	$	1,180
	Term loan		500			500			—		—
	Senior notes, net		5,937			6,162			4,858		5,091
	Total debt, net		$	9,170		$	9,395		$	6,038	$	6,271

Derivatives_Tables

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Schedule of Derivative Instruments	'
	The following table summarizes derivative positions for the periods indicated as of December 31, 2013:
		2014			2015			2016			2017			2018
	Natural gas positions:
	Fixed price swaps (NYMEX Henry Hub):
	Hedged volume (MMMBtu)	97,400			118,041			121,841			120,122			36,500
	Average price ($/MMBtu)	$	5.25		$	5.19		$	4.2		$	4.26		$	5
	Put options (NYMEX Henry Hub): (1)
	Hedged volume (MMMBtu)	79,628			71,854			76,269			66,886			—
	Average price ($/MMBtu)	$	5		$	5		$	5		$	4.88		$	—
	Oil positions:
	Fixed price swaps (NYMEX WTI): (2)
	Hedged volume (MBbls)	16,831			11,599			11,465			4,755			—
	Average price ($/Bbl)	$	92.44		$	96.23		$	90.56		$	89.02		$	—
		2014			2015			2016			2017			2018
	Collars (NYMEX WTI):
	Hedged volume (MBbls)	730			—			—			—			—
	Average floor price ($/Bbl)	$	90		$	—		$	—		$	—		$	—
	Average ceiling price ($/Bbl)	$	102.87		$	—		$	—		$	—		$	—
	Three-way collars (NYMEX WTI):
	Hedged volume (MBbls)	3,103			1,095			—			—			—
	Short put ($/Bbl)	$	72.11		$	70		$	—		$	—		$	—
	Long put ($/Bbl)	$	93.76		$	90		$	—		$	—		$	—
	Short call ($/Bbl)	$	109.79		$	101.62		$	—		$	—		$	—
	Put options (NYMEX WTI):
	Hedged volume (MBbls)	3,960			3,426			3,271			384			—
	Average price ($/Bbl)	$	91.3		$	90		$	90		$	90		$	—
	Three-way collars (ICE Brent):
	Hedged volume (MBbls)	365			—			—			—			—
	Short put ($/Bbl)	$	80		$	—		$	—		$	—		$	—
	Long put ($/Bbl)	$	100		$	—		$	—		$	—		$	—
	Short call ($/Bbl)	$	114.05		$	—		$	—		$	—		$	—
	Natural gas basis differential positions: (3)
	Panhandle basis swaps:
	Hedged volume (MMMBtu)	79,388			87,162			59,954			59,138			16,425
	Hedged differential ($/MMBtu)	$	(0.33	)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)
	NWPL Rockies basis swaps:
	Hedged volume (MMMBtu)	39,718			43,292			46,294			38,880			10,804
	Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	(0.19	)	$	(0.19	)
	MichCon basis swaps:
	Hedged volume (MMMBtu)	9,490			9,344			7,768			7,437			2,044
	Hedged differential ($/MMBtu)	$	0.08		$	0.06		$	0.05		$	0.05		$	0.05
	Houston Ship Channel basis swaps:
	Hedged volume (MMMBtu)	5,256			4,891			4,575			3,604			986
	Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.08	)	$	(0.08	)
	Permian basis swaps:
	Hedged volume (MMMBtu)	4,891			5,074			4,219			4,819			1,314
	Hedged differential ($/MMBtu)	$	(0.21	)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)
	Oil basis differential positions:
	ICE Brent - NYMEX WTI basis swaps:
	Hedged volume (MBbls)	3,650			2,920			—			—			—
	Hedged differential ($/Bbl)	$	11.6		$	11.6		$	—		$	—		$	—
	Oil timing differential positions:
	Trade month roll swaps (NYMEX WTI): (4)
	Hedged volume (MBbls)	9,079			7,251			7,446			6,486			—
	Hedged differential ($/Bbl)	$	0.24		$	0.24		$	0.25		$	0.25		$	—
	(1)	Includes certain outstanding natural gas put options of approximately 10,570 MMMBtu for each of the years ending December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to indirectly hedge revenues associated with NGL production.
	(2)	Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.
	(3)	Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.
	(4)	The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).
Fair Value of Derivatives Outstanding on a Gross Basis by Location on the Balance Sheet	'
	The following summarizes the fair value of derivatives outstanding on a gross basis:
			December 31,
			2013			2012
			(in thousands)
	Assets:
	Commodity derivatives		$	1,048,212		$	1,282,390
	Liabilities:
	Commodity derivatives		$	222,905		$	405,619

Fair_Value_Measurements_on_a_R1

Fair Value Measurements on a Recurring Basis (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements on a Recurring Basis	'
	The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
			December 31, 2013
			Level 2		Netting (1)			Total
			(in thousands)
	Assets:
	Commodity derivatives		$	1,048,212	$	(190,080	)	$	858,132
	Liabilities:
	Commodity derivatives		$	222,905	$	(190,080	)	$	32,825
			December 31, 2012
			Level 2		Netting (1)			Total
			(in thousands)
	Assets:
	Commodity derivatives		$	1,282,390	$	(401,479	)	$	880,911
	Liabilities:
	Commodity derivatives		$	405,619	$	(401,479	)	$	4,140
	(1)	Represents counterparty netting under agreements governing such derivatives.

Other_Property_and_Equipment_T

Other Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Other Property and Equipment	'
	Other property and equipment consists of the following:
		December 31,
		2013			2012
		(in thousands)
	Natural gas plant and pipeline	$	507,342		$	371,292
	Buildings and leasehold improvements	32,658			19,999
	Vehicles	27,964			19,731
	Drilling and other equipment	8,618			6,265
	Furniture and office equipment	65,909			47,623
	Land	5,391			4,278
		647,882			469,188
	Less accumulated depreciation	(110,939		)	(73,721		)
		$	536,943		$	395,467

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations Reconciliation	'
	The following presents a reconciliation of the Company’s asset retirement obligations:
		December 31,
		2013			2012
		(in thousands)
	Asset retirement obligations at beginning of year	$	151,974		$	71,142
	Liabilities added from acquisitions	98,343			63,663
	Liabilities added from drilling	4,048			1,799
	Liabilities associated with assets sold	(1,092		)	—
	Current year accretion expense	11,938			8,550
	Settlements	(5,136		)	(3,640		)
	Revision of estimates	29,246			10,460
	Asset retirement obligations at end of year	$	289,321		$	151,974

Earnings_Per_Unit_Tables

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Schedule of Earnings Per Share Reconciliation	'
	The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net income (loss):
		Year Ended December 31,
		2013			2012			2011
		(in thousands, except per unit data)
	Net income (loss)	$	(691,337	)	$	(386,616	)	$	438,439
	Allocated to participating securities	(5,935		)	(4,575		)	(4,739		)
		$	(697,272	)	$	(391,191	)	$	433,700
	Basic net income (loss) per unit	$	(2.94	)	$	(1.92	)	$	2.52
	Diluted net income (loss) per unit	$	(2.94	)	$	(1.92	)	$	2.51
	Basic weighted average units outstanding	237,544			203,775			172,004
	Dilutive effect of unit equivalents	—			—			725
	Diluted weighted average units outstanding	237,544			203,775			172,729

Operating_Leases_Tables

Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2013
Leases, Operating [Abstract]	'
Future Minimum Lease Payments	'
	As of December 31, 2013, future minimum lease payments were as follows (in thousands):
	2014	$	14,222
	2015	11,146
	2016	7,869
	2017	5,958
	2018	5,055
	Thereafter	5,786
		$	50,036

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Components of income tax expense (benefit)	'
	Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Income tax expense (benefit) consisted of the following:
		Year Ended December 31,
		2013				2012				2011
		(in thousands)
	Current taxes:
	Federal	$	144			$	2,711			$	4,551
	State	198				439				605
	Deferred taxes:
	Federal	(2,805		)		323				(1,148		)
	State	264				(683		)		1,458
		$	(2,199	)		$	2,790			$	5,466
Effective income tax rate reconciliation	'
	A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
		Year Ended December 31,
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	State, net of federal tax benefit	(0.1	)		0.1			0.5
	Loss excluded from nontaxable entities	(34.6	)		(35.6	)		(34.4	)
	Other items	—			(0.2	)		0.1
	Effective rate	0.3	%		(0.7	)%		1.2	%
Significant components of the deferred tax assets and liabilities	'
	Significant components of the deferred tax assets and liabilities were as follows:
		December 31,
		2013				2012
		(in thousands)
	Deferred tax assets:
	Net operating loss carryforwards	$	1,129			$	—
	Unit-based compensation	21,965				10,579
	Other	7,759				4,924
	Total deferred tax assets	30,853				15,503
	Deferred tax liabilities:
	Property and equipment principally due to differences in depreciation	(12,525		)		(11,049		)
	Other	(1,509		)		(1,055		)
	Total deferred tax liabilities	(14,034		)		(12,104		)
	Net deferred tax assets	$	16,819			$	3,399
Classification of net deferred tax assets and liabilities in consolidated balance sheets	'
	Net deferred tax assets and liabilities were classified on the consolidated balance sheets as follows:
		December 31,
		2013				2012
		(in thousands)
	Deferred tax assets	$	29,204			$	10,318
	Deferred tax liabilities	(10		)		(612		)
	Other current assets	$	29,194			$	9,706
	Deferred tax assets	$	1,649			$	5,186
	Deferred tax liabilities	(14,024		)		(11,493		)
	Other noncurrent liabilities	$	(12,375	)		$	(6,307	)

Supplemental_Disclosures_to_th1

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2013
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]	'
Other Accrued Liabilities	'
	“Other accrued liabilities” reported on the consolidated balance sheets include the following:
		December 31,
		2013			2012
		(in thousands)
	Accrued compensation	$	55,257		$	35,431
	Accrued interest	93,998			72,668
	Other	14,120			7,146
		$	163,375		$	115,245
Supplemental Cash Flow Disclosures	'
	Supplemental disclosures to the consolidated statements of cash flows are presented below:
		Year Ended December 31,
		2013			2012			2011
		(in thousands)
	Cash payments for interest, net of amounts capitalized	$	392,607		$	343,331		$	247,217
	Cash payments for income taxes	$	14		$	366		$	487
	Noncash investing and financing activities:
	In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follow:
	Fair value of assets acquired	$	5,726,681		$	2,923,990		$	1,523,466
	Cash paid, net of cash acquired	(109,350		)	(2,640,475		)	(1,500,193		)
	Units issued in connection with the Berry acquisition	(2,781,888		)	—			—
	Receivables from sellers	(93		)	2,132			3,557
	Payables to sellers	(6,854		)	443			(4,847		)
	Liabilities assumed	$	2,828,496		$	286,090		$	21,983

Subsidiary_Guarantors_Tables

Subsidiary Guarantors (Tables)	12 Months Ended
	Dec. 31, 2013
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Condensed Consolidating Balance Sheets	'
	CONDENSED CONSOLIDATING BALANCE SHEETS
	31-Dec-13
		LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
								Guarantor Subsidiary
		(in thousands)
	ASSETS
	Current assets:
	Cash and cash equivalents	$	52		$	1,078		$	51,041		$	—		$	52,171
	Accounts receivable – trade, net	—			365,347			122,855			—			488,202
	Accounts receivable – affiliates	4,212,348			16,950			—			(4,229,298		)	—
	Derivative instruments	—			170,534			5,596			—			176,130
	Other current assets	330			68,274			30,833			—			99,437
	Total current assets	4,212,730			622,183			210,325			(4,229,298		)	815,940
	Noncurrent assets:
	Oil and natural gas properties (successful efforts method)	—			13,074,900			4,813,659			—			17,888,559
	Less accumulated depletion and amortization	—			(3,535,890		)	(10,394		)	—			(3,546,284		)
		—			9,539,010			4,803,265			—			14,342,275
	Other property and equipment	—			564,756			83,126			—			647,882
	Less accumulated depreciation	—			(110,706		)	(233		)	—			(110,939		)
		—			454,050			82,893			—			536,943
	Derivative instruments	—			679,491			2,511			—			682,002
	Notes receivable – affiliates	86,200			—			—			(86,200		)	—
	Investments in consolidated subsidiaries	7,139,737			—			—			(7,139,737		)	—
	Other noncurrent assets, net	108,785			10,968			8,051			—			127,804
		7,334,722			690,459			10,562			(7,225,937		)	809,806
	Total noncurrent assets	7,334,722			10,683,519			4,896,720			(7,225,937		)	15,689,024
	Total assets	$	11,547,452		$	11,305,702		$	5,107,045		$	(11,455,235	)	$	16,504,964
	LIABILITIES AND UNITHOLDERS’ CAPITAL
	Current liabilities:
	Accounts payable and accrued expenses	$	14,529		$	587,774		$	247,321		$	—		$	849,624
	Accounts payable – affiliates	—			4,212,348			16,950			(4,229,298		)	—
	Derivative instruments	—			7,783			20,393			—			28,176
	Other accrued liabilities	75,071			59,311			28,993			—			163,375
	Current portion of long-term debt	—			—			211,558			—			211,558
	Total current liabilities	89,600			4,867,216			525,215			(4,229,298		)	1,252,733
	Noncurrent liabilities:
	Credit facilities	1,560,000			—			1,173,175			—			2,733,175
	Term loan	500,000			—			—			—			500,000
	Senior notes, net	4,809,055			—			916,428			—			5,725,483
	Notes payable – affiliates	—			86,200			—			(86,200		)	—
	Derivative instruments	—			—			4,649			—			4,649
	Other noncurrent liabilities	—			205,406			192,091			—			397,497
	Total noncurrent liabilities	6,869,055			291,606			2,286,343			(86,200		)	9,360,804
	Unitholders’ capital:
	Units issued and outstanding	6,282,747			4,833,354			2,315,460			(7,139,737		)	6,291,824
	Accumulated income (deficit)	(1,693,950		)	1,313,526			(19,973		)	—			(400,397		)
		4,588,797			6,146,880			2,295,487			(7,139,737		)	5,891,427
	Total liabilities and unitholders’ capital	$	11,547,452		$	11,305,702		$	5,107,045		$	(11,455,235	)	$	16,504,964
Condensed Consolidating Statements of Operations	'
	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	For the Year Ended December 31, 2013
		LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
								Guarantor Subsidiary
		(in thousands)
	Revenues and other:
	Oil, natural gas and natural gas liquids sales	$	—		$	2,022,916		$	50,324		$	—		$	2,073,240
	Gains (losses) on oil and natural gas derivatives	—			182,906			(5,049		)	—			177,857
	Marketing revenues	—			53,772			399			—			54,171
	Other revenues	—			24,943			1,444			—			26,387
		—			2,284,537			47,118			—			2,331,655
	Expenses:
	Lease operating expenses	—			357,113			15,410			—			372,523
	Transportation expenses	—			125,864			2,576			—			128,440
	Marketing expenses	—			36,259			1,633			—			37,892
	General and administrative expenses	—			215,973			20,298			—			236,271
	Exploration costs	—			5,251			—			—			5,251
	Depreciation, depletion and amortization	—			818,466			10,845			—			829,311
	Impairment of long-lived assets	—			828,317			—			—			828,317
	Taxes, other than income taxes	—			136,501			2,130			—			138,631
	Losses on sale of assets and other, net	724			2,705			10,208			—			13,637
		724			2,526,449			63,100			—			2,590,273
	Other income and (expenses):
	Interest expense, net of amounts capitalized	(415,670		)	(1,504		)	(3,963		)	—			(421,137		)
	Interest expense – affiliates	—			(5,543		)	—			5,543			—
	Loss on extinguishment of debt	(5,304		)	—			—			—			(5,304		)
	Interest income – affiliates	5,543			—			—			(5,543		)	—
	Other, net	(8,283		)	(166		)	(28		)	—			(8,477		)
		(423,714		)	(7,213		)	(3,991		)	—			(434,918		)
	Loss before income taxes	(424,438		)	(249,125		)	(19,973		)	—			(693,536		)
	Income tax benefit	—			2,199			—			—			2,199
	Net loss	$	(424,438	)	$	(246,926	)	$	(19,973	)	$	—		$	(691,337	)
Condensed Consolidating Statements of Cash Flow	'
	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	For the Year Ended December 31, 2013
		LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
								Guarantor Subsidiary
		(in thousands)
	Cash flow from operating activities:
	Net loss	$	(424,438	)	$	(246,926	)	$	(19,973	)	$	—		$	(691,337	)
	Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
	Depreciation, depletion and amortization	—			818,466			10,845			—			829,311
	Impairment of long-lived assets	—			828,317			—			—			828,317
	Unit-based compensation expenses	—			42,703			—			—			42,703
	Loss on extinguishment of debt	5,304			—			—			—			5,304
	Amortization and write-off of deferred financing fees	22,122			—			(615		)	—			21,507
	Losses on sale of assets and other, net	—			37,232			—			—			37,232
	Deferred income tax	—			(2,541		)	—			—			(2,541		)
	Derivatives activities:
	Total (gains) losses	—			(182,906		)	5,049			—			(177,857		)
	Cash settlements	—			248,862			—			—			248,862
	Changes in assets and liabilities:
	Decrease in accounts receivable – trade, net	—			17,754			71,434			—			89,188
	(Increase) decrease in accounts receivable – affiliates	(120,967		)	(16,950		)	—			137,917			—
	(Increase) decrease in other assets	(330		)	5,896			10,613			—			16,179
	Increase (decrease) in accounts payable and accrued expenses	178			(52,143		)	(25,028		)	—			(76,993		)
	Increase (decrease) in accounts payable and accrued expenses – affiliates	—			120,967			16,950			(137,917		)	—
	Increase (decrease) in other liabilities	2,092			6,842			(12,597		)	—			(3,663		)
	Net cash provided by (used in) operating activities	(516,039		)	1,625,573			56,678			—			1,166,212
	Cash flow from investing activities:
	Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	—			(730,326		)	451,113			—			(279,213		)
	Development of oil and natural gas properties	—			(1,060,547		)	(17,478		)	—			(1,078,025		)
	Purchases of other property and equipment	—			(92,352		)	—			—			(92,352		)
	Investment in affiliates	435,000			—			—			(435,000		)	—
	Change in notes receivable with affiliate	(26,700		)	—			—			26,700			—
	Proceeds from sale of properties and equipment and other	(22,039		)	218,312			—			—			196,273
	Net cash provided by (used in) investing activities	386,261			(1,664,913		)	433,635			(408,300		)	(1,253,317		)
		LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
								Guarantor Subsidiary
		(in thousands)
	Cash flow from financing activities:
	Proceeds from borrowings	2,230,000			—			—			—			2,230,000
	Repayments of debt	(1,404,898		)	—			—			—			(1,404,898		)
	Distributions to unitholders	(682,241		)	—			—			—			(682,241		)
	Financing fees, offering expenses and other, net	(13,138		)	12,422			(4,272		)	—			(4,988		)
	Change in note payable with affiliate	—			26,700			—			(26,700		)	—
	Capital contribution – affiliates	—			—			(435,000		)	435,000			—
	Excess tax benefit from unit-based compensation	—			160			—			—			160
	Net cash provided by (used in) financing activities	129,723			39,282			(439,272		)	408,300			138,033
	Net increase (decrease) in cash and cash equivalents	(55		)	(58		)	51,041			—			50,928
	Cash and cash equivalents:
	Beginning	107			1,136			—			—			1,243
	Ending	$	52		$	1,078		$	51,041		$	—		$	52,171

Supplemental_Oil_and_Natural_G1

Supplemental Oil and Natural Gas Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development	'
	Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:
			Year Ended December 31,
			2013				2012				2011
			(in thousands)
	Property acquisition costs: (1)
	Proved		$	3,740,379			$	2,531,419			$	1,328,328
	Unproved		1,638,302				181,124				188,409
	Exploration costs		13,096				452				80
	Development costs		1,153,770				1,062,043				639,395
	Asset retirement costs		7,351				4,675				2,427
	Total costs incurred		$	6,552,898			$	3,779,713			$	2,158,639
	(1)	See Note 2 for details about the Company’s acquisitions.
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities	'
	Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:
			December 31,
			2013				2012
			(in thousands)
	Proved properties:
	Leasehold acquisition		$	12,277,089			$	8,603,888
	Development		3,660,277				2,553,127
	Unproved properties		1,951,193				454,315
			17,888,559				11,611,330
	Less accumulated depletion and amortization		(3,546,284		)		(2,025,656		)
			$	14,342,275			$	9,585,674
Results of Operations for Oil and Gas Producing Activities	'
	The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below:
			Year Ended December 31,
			2013				2012				2011
			(in thousands)
	Revenues and other:
	Oil, natural gas and natural gas liquid sales		$	2,073,240			$	1,601,180			$	1,162,037
	Gains on oil and natural gas derivatives		177,857				124,762				449,940
			2,251,097				1,725,942				1,611,977
	Production costs:
	Lease operating expenses		372,523				317,699				232,619
	Transportation expenses		128,440				77,322				28,358
	Severance and ad valorem taxes		139,202				130,805				78,458
			640,165				525,826				339,435
	Other costs:
	Exploration costs		5,251				1,915				2,390
	Depletion and amortization		790,320				579,382				320,096
	Impairment of long-lived assets		828,317				422,499				—
	Gains on sale of assets and other, net		(138		)		(1,369		)		(1,001		)
	Texas margin tax (benefit) expense		458				(787		)		1,599
			1,624,208				1,001,640				323,084
	Results of operations		$	(13,276	)		$	198,476			$	949,458
Estimated Quantities of Oil, Natural Gas and NGL Reserves	'
	An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below:
			Year Ended December 31, 2013
			Natural Gas			Oil			NGL			Total
			(Bcf)			(MMBbls)			(MMBbls)			(Bcfe)
	Proved developed and undeveloped reserves:
	Beginning of year		2,571			191.5			179.4			4,796
	Revisions of previous estimates		(17	)		(21.3	)		(2.0	)		(157	)
	Purchase of minerals in place		356			191.1			17.8			1,610
	Sales of minerals in place		(24	)		(5.2	)		(2.9	)		(73	)
	Extensions, discoveries and other additions		286			21.7			18.5			527
	Production		(162	)		(12.2	)		(10.8	)		(300	)
	End of year		3,010			365.6			200			6,403
	Proved developed reserves:
	Beginning of year		1,661			131.4			113			3,127
	End of year		2,027			252.4			133.2			4,340
	Proved undeveloped reserves:
	Beginning of year		910			60.1			66.4			1,669
	End of year		983			113.2			66.8			2,063
			Year Ended December 31, 2012
			Natural Gas (Bcf)			Oil			NGL (MMBbls)			Total
						(MMBbls)						(Bcfe)
	Proved developed and undeveloped reserves:
	Beginning of year		1,675			189			93.5			3,370
	Revisions of previous estimates		(559	)		(26.5	)		(14.1	)		(803	)
	Purchase of minerals in place		1,176			23.1			75.3			1,766
	Extensions, discoveries and other additions		407			16.6			33.7			709
	Production		(128	)		(10.7	)		(9.0	)		(246	)
	End of year		2,571			191.5			179.4			4,796
	Proved developed reserves:
	Beginning of year		998			124.8			47.8			2,034
	End of year		1,661			131.4			113			3,127
	Proved undeveloped reserves:
	Beginning of year		677			64.2			45.7			1,336
	End of year		910			60.1			66.4			1,669
			Year Ended December 31, 2011
			Natural Gas (Bcf)			Oil			NGL (MMBbls)			Total
						(MMBbls)						(Bcfe)
	Proved developed and undeveloped reserves:
	Beginning of year		1,233			156.4			70.9			2,597
	Revisions of previous estimates		(71	)		(9.2	)		0.9			(121	)
	Purchase of minerals in place		337			39.3			1			579
	Extensions, discoveries and other additions		240			10.3			24.6			450
	Production		(64	)		(7.8	)		(3.9	)		(135	)
	End of year		1,675			189			93.5			3,370
	Proved developed reserves:
	Beginning of year		805			103			39.9			1,662
	End of year		998			124.8			47.8			2,034
	Proved undeveloped reserves:
	Beginning of year		428			53.4			31			935
	End of year		677			64.2			45.7			1,336
	The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents at a rate of one barrel per six Mcf.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves	'
	Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to Texas margin tax and were also subject to state income taxes in the state of Michigan during 2011; however, these amounts are not material. See Note 14 for additional information about income taxes.
			December 31,
			2013				2012				2011
			(in thousands)
	Future estimated revenues		$	51,112,346			$	30,374,380			$	29,319,369
	Future estimated production costs		(19,306,728		)		(11,460,854		)		(9,464,319		)
	Future estimated development costs		(5,110,896		)		(3,574,058		)		(2,848,497		)
	Future net cash flows		26,694,722				15,339,468				17,006,553
	10% annual discount for estimated timing of cash flows		(14,795,393		)		(9,266,487		)		(10,391,693		)
	Standardized measure of discounted future net cash flows		$	11,899,329			$	6,072,981			$	6,614,860
	Representative NYMEX prices: (1)
	Natural gas (MMBtu)		$	3.67			$	2.76			$	4.12
	Oil (Bbl)		$	96.89			$	94.64			$	95.84
	(1)	In accordance with SEC regulations, reserves at December 31, 2013, December 31, 2012, and December 31, 2011, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow	'
	The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:
			Year Ended December 31,
			2013				2012				2011
			(in thousands)
	Sales and transfers of oil, natural gas and NGL produced during the period		$	(1,433,075	)		$	(1,075,354	)		$	(822,602	)
	Changes in estimated future development costs		317,064				289,762				27,236
	Net change in sales and transfer prices and production costs related to future production		203,370				(1,463,820		)		784,308
	Purchase of minerals in place		5,113,335				2,153,651				1,452,169
	Sale of minerals in place		(139,384		)		—				—
	Extensions, discoveries, and improved recovery		801,254				413,702				552,704
	Previously estimated development costs incurred during the period		444,861				442,322				306,827
	Net change due to revisions in quantity estimates		(220,224		)		(1,595,302		)		(292,343		)
	Accretion of discount		607,298				661,486				422,353
	Changes in production rates and other		131,849				(368,326		)		(39,324		)
			$	5,826,348			$	(541,879	)		$	2,391,328

Quarterly_Financial_Data_Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
Quarterly financial data	'
	Quarterly Financial Data
			Quarters Ended
			31-Mar			30-Jun			30-Sep			December 31 (2)
			(in thousands, except per unit amounts)
	2013:00:00
	Oil, natural gas and natural gas liquid sales		$	462,732		$	488,207		$	537,671		$	584,630
	Gains (losses) on oil and natural gas derivatives		(108,370		)	326,733			(63,931		)	23,425
	Total revenues and other		369,060			838,825			494,562			629,208
	Total expenses (1)		478,235			385,540			420,803			1,292,058
	(Gain) losses on sale of assets and other, net		3,172			(959		)	827			10,597
	Net income (loss)		(221,885		)	345,157			(30,060		)	(784,549		)
	Net income (loss) per unit:
	Basic		$	(0.96	)	$	1.47		$	(0.13	)	$	(3.15	)
	Diluted		$	(0.96	)	$	1.46		$	(0.13	)	$	(3.15	)
	(1)	Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.
	(2)	Includes the results of operations of the Berry Acquisition since the acquisition date (see Note 2).
			Quarters Ended
			31-Mar			30-Jun			30-Sep			December 31
			(in thousands, except per unit amounts)
	2012:00:00
	Oil, natural gas and natural gas liquid sales		$	348,895		$	347,227		$	444,082		$	460,976
	Gains (losses) on oil and natural gas derivatives		2,031			439,647			(411,405		)	94,489
	Total revenues and other		354,090			800,597			48,328			571,225
	Total expenses (1)		269,092			460,655			376,323			656,221
	(Gain) losses on sale of assets and other, net		1,494			(2		)	16			31
	Net income (loss)		(6,202		)	237,086			(430,005		)	(187,495		)
	Net income (loss) per unit:
	Basic		$	(0.04	)	$	1.19		$	(2.18	)	$	(0.83	)
	Diluted		$	(0.04	)	$	1.19		$	(2.18	)	$	(0.83	)
	(1)	Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.

Basis_of_Presentation_and_Sign2

Basis of Presentation and Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Basis of Presentation and Significant Accounting Policies [Abstract]	'	'	'
Allowance for doubtful accounts	$1,000,000	$0	'
Capitalized interest costs	2,000,000	2,000,000	2,000,000
Impairment of long-lived assets, before tax	791,000,000	422,499,000	0
Impairment of long-lived assets, after tax	791,000,000	452,499,000	0
Impairment of unproved oil and gas properties	5,000,000	2,000,000	2,000,000
Natural gas production imbalance receivables	27,000,000	28,000,000	'
Natural gas production imbalance payables	16,000,000	18,000,000	'
Restricted cash	6,000,000	5,000,000	'
Net deferred financing fees	114,000,000	114,000,000	'
Debt issuance fees amortization expense	18,000,000	13,000,000	16,000,000
Write-off of deferred financing fees	$0	$8,000,000	$1,000,000
Statement [Line Items]	'	'	'
Useful lives of other property and equipment (in years)	'20 years	'	'
Minimum [Member]	'	'	'
Statement [Line Items]	'	'	'
Useful lives of other property and equipment (in years)	'3 years	'	'
Maximum [Member]	'	'	'
Statement [Line Items]	'	'	'
Useful lives of other property and equipment (in years)	'39 years	'	'

Acquisitions_JointVenture_Fund2

Acquisitions, Joint-Venture Funding and Divestiture (Acquisitions, Joint-Venture Funding) (Details) (USD $)

12 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

21 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 16, 2013

Dec. 31, 2013

Dec. 17, 2013

Dec. 16, 2013

Dec. 17, 2013

Dec. 17, 2013

Oct. 31, 2013

Dec. 31, 2013

Jul. 31, 2012

1-May-12

Apr. 03, 2012

Dec. 31, 2013

Dec. 31, 2013

Mar. 30, 2012

Dec. 15, 2011

Nov. 18, 2011

Jun. 01, 2011

11-May-11

Apr. 05, 2011

Mar. 31, 2011

Mcfe

Mcfe

Mcfe

Business Acquisition, Berry

Business Acquisition, Berry

Business Acquisition, Berry

Business Acquisition, Berry

Business Acquisition, Berry

Business Acquisition, Permian, BC Operating

Business Acquisition Various

Business Acquisition BP Green River

Business Acquisition East Texas

Business Acquisition Anadarko

Business Acquisition Anadarko

Business Acquisition Anadarko

Business Acquisition BP

Business Acquisition Plains

Business Acquisition Permian

Business Acquisition Panther

Business Acquisition Williston Basin

Business Acquisition SandRidge

Business Acquisition Concho

acre

MMcfe_Per_Day

Mcfe

Linn Energy, LLC

LinnCo

Wells

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exchange ratio

'

'

'

'

'

168.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

LinnCo common shares issued to acquire Berry

'

'

'

'

'

'

'

93,756,674

93,756,674

'

'

'

'

'

'

'

'

'

'

'

'

'

'

LINN Energy units issued to LinnCo for LinnCo common shares issued

'

'

'

'

'

'

'

93,756,674

93,756,674

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preliminary value of acquisition

'

'

'

'

'

$4,600,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt assumed

'

'

'

'

'

'

2,301,859,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash acquired

'

'

'

'

'

'

451,113,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proved reserves purchased

1,610,000,000

1,766,000,000

579,000,000

'

'

1,408,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Average daily production

'

'

'

'

267

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gross productive wells

'

'

'

'

3,400

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current receivables acquired

'

'

'

'

'

'

194,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative instruments acquired, current

'

'

'

'

'

'

14,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative instruments acquired, noncurrent

'

'

'

'

'

'

6,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other property and equipment acquired

'

'

'

'

'

'

83,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current payables acquired

'

'

'

'

'

'

272,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Out-of-market natural gas transportation contracts acquired, current

'

'

'

'

'

'

19,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Out-of-market natural gas transportation contracts acquired, current

'

'

'

'

'

'

88,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Useful lives of other property and equipment (in years)

'20 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Business Acquisition, Transaction Costs

'

'

'

'

48,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Severance and unit based compensation costs incurred to consummate the business acquisition

'

'

'

18,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total consideration transferred

'

'

'

'

'

'

'

'

'

528,000,000

40,000,000

988,000,000

164,000,000

'

'

'

1,170,000,000

540,000,000

110,000,000

220,000,000

150,000,000

240,000,000

190,000,000

Joint venture interest acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

23.00%

'

'

'

'

'

'

'

'

'

Business acquisitions - Net assets acquired

'

'

'

'

'

'

2,781,888,000

'

'

527,886,000

'

'

'

392,000,000

'

'

'

'

'

'

'

'

'

Imputed discount on future funding of joint venture

'

'

'

'

'

'

'

'

'

'

'

'

'

8,000,000

'

'

'

'

'

'

'

'

'

Future funding commitment of joint venture consideration transferred

'

'

'

'

'

'

'

'

'

'

'

'

'

'

173,000,000

375,000,000

'

'

'

'

'

'

'

Future Funding Of Joint Venture Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

400,000,000

'

'

'

'

'

'

'

'

'

Term loan

$500,000,000

$0

'

'

'

'

'

'

'

$500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Net acres

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Acquisitions_JointVenture_Fund3

Acquisitions, Joint-Venture Funding and Divestiture Purchase Price (Details) (USD $)	0 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 17, 2013	Dec. 16, 2013
Business Acquisition [Line Items]	'	'
LINN Energy unit consideration	'	$2,763,009
Employee unit-based awards	'	18,879
Total purchase price	'	$2,781,888
Business Acquisition, Berry | Linn Energy, LLC	'	'
Business Acquisition [Line Items]	'	'
LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674	'
Closing price of LINN Energy units on December 16, 2013	'	$29.47

Acquisitions_JointVenture_Fund4

Acquisitions, Joint-Venture Funding and Divestiture (Purchase Price Allocation) (Details) (USD $)	Dec. 16, 2013	Oct. 31, 2013
In Thousands, unless otherwise specified	Business Acquisition, Berry	Business Acquisition, Permian, BC Operating
Assets:	'	'
Cash	$451,113	'
Current	249,564	1,124
Noncurrent	97,202	10
Oil and natural gas properties	4,791,394	531,335
Total assets acquired	5,589,273	532,469
Liabilities:	'	'
Current	310,105	1,808
Noncurrent	100,809	'
Asset retirement obligations, current and noncurrent	94,612	2,775
Long-term debt, including current portion	2,301,859	'
Total liabilities assumed	2,807,385	4,583
Net assets acquired	$2,781,888	$527,886

Acquisitions_JointVenture_Fund5

Acquisitions, Joint-Venture Funding and Divestiture (Pro Forma Financial Information) (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition Pro Forma Results of Operations	'	'
Total revenues and other	$3,443,246	$2,989,410
Total operating expenses	3,366,987	2,572,921
Net income (loss)	($445,965)	($131,313)
Basic net income (loss) per unit	($1,360)	($460)
Diluted net income (loss) per unit	($1,360)	($460)

Acquisitions_JointVenture_Fund6

Acquisitions, Joint-Venture Funding and Divestiture (Divestiture) (Details) (USD $)	0 Months Ended	12 Months Ended
	31-May-13	Dec. 31, 2013
Gain (Loss) on Disposition of Oil and Gas and Timber Property [Abstract]	'	'
Impairment of long-lived assets	'	$37,000,000
Proceeds from sale of Panther properties	218,000,000	'
Costs to sell Panther properties	$2,000,000	'

Unitholders_Capital_Details

Unitholders' Capital (Details) (USD $)

1 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

Jan. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Aug. 31, 2011

Mar. 31, 2011

Oct. 31, 2008

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 16, 2013

Oct. 17, 2012

Dec. 17, 2013

Dec. 17, 2013

Dec. 16, 2013

Dec. 17, 2013

Feb. 14, 2014

Jan. 17, 2014

Jan. 03, 2014

LinnCo

Berry

Berry

Berry

Berry

Distribution declared

Distribution declared

Distribution declared

Linn Energy, LLC

Linn Energy, LLC

LinnCo

Subsequent Event [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Per unit cash dividend paid (in dollars per unit)

'

'

'

'

'

'

$2.90

$2.87

$2.70

'

'

'

'

'

'

'

'

$0.73

Common Stock, Dividends, Per Share, Declared, Monthly (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$0.24

Distribution paid during period

'

'

'

'

'

'

$682,241,000

$596,935,000

$466,488,000

'

'

'

'

'

'

$80,000,000

$80,000,000

'

Related Party Transaction [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exchange ratio

'

'

'

'

'

'

'

'

'

'

'

168.00%

'

'

'

'

'

'

LinnCo common shares issued to acquire Berry

'

'

'

'

'

'

'

'

'

'

'

'

93,756,674

'

93,756,674

'

'

'

LINN Energy units issued to LinnCo for LinnCo common shares issued

'

'

'

'

'

'

'

'

'

'

'

'

93,756,674

'

93,756,674

'

'

'

Value of units issued to acquire Berry

'

'

'

'

'

'

'

'

'

2,763,009,000

'

'

'

2,800,000,000

'

'

'

'

Inital public offering, shares issued (in shares)

'

'

'

'

'

'

'

'

'

'

34,787,500

'

'

'

'

'

'

'

Inital public offering, price per share (in usd per share)

'

'

'

'

'

'

'

'

'

'

$36.50

'

'

'

'

'

'

'

Initial public offering, price per share, net (in usd per share)

'

'

'

'

'

'

'

'

'

'

$34.86

'

'

'

'

'

'

'

Initial public offering, proceeds

'

'

'

'

'

'

'

'

'

'

1,200,000,000

'

'

'

'

'

'

'

Public offering underwriting discount and offering expenses

28,000,000

'

'

'

26,000,000

'

'

'

'

'

57,000,000

'

'

'

'

'

'

'

Units of LINN Energy acquired

'

'

'

'

'

'

'

'

'

'

34,787,500

'

'

'

'

'

'

'

Public Offering of Units [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public offering units sold

19,550,000

'

'

'

16,726,067

'

'

'

'

'

'

'

'

'

'

'

'

'

Public offering price per unit

$35.95

'

'

'

$38.80

'

'

'

'

'

'

'

'

'

'

'

'

'

Public offering price per unit, net of underwriting discount

$34.51

'

'

'

$37.25

'

'

'

'

'

'

'

'

'

'

'

'

'

Public offering net proceeds

674,000,000

'

'

'

623,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Public offering underwriting discount and offering expenses

28,000,000

'

'

'

26,000,000

'

'

'

'

'

57,000,000

'

'

'

'

'

'

'

Equity Distribution Agreement [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity distribution agreement maximum value

'

'

'

500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity distribution agreement professional service expenses

700,000

139,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity distribution agreement units sold

1,539,651

772,104

16,060

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity distribution agreement price per unit sold

$38.02

$38.03

$38.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity distribution agreement net proceeds

57,000,000

29,000,000

602,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Distribution Agreement Commissions And Professional Service Expenses

1,000,000

587,000

12,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity distribution agreement remaining balance

'

'

'

'

'

'

411,000,000

'

'

'

'

'

'

'

'

'

'

'

Unit Repurchase Plan [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Authorized repurchase value of units

'

'

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Units repurchased during the period (in units)

'

'

'

'

'

'

'

'

529,734

'

'

'

'

'

'

'

'

'

Average unit price of units repurchased (in dollars per unit)

'

'

'

'

'

'

'

'

$32.76

'

'

'

'

'

'

'

'

'

Total cost of units repurchased

'

'

'

'

'

'

'

'

17,000,000

'

'

'

'

'

'

'

'

'

Remaining balance of units under unit repurchase program

'

'

'

'

'

'

$56,000,000

'

'

'

'

'

'

'

'

'

'

'

Business_and_Credit_Concentrat1

Business and Credit Concentrations (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Sales [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Total number of largest customers represented in sales	1	2	3
Sales [Member] | Customer 1 [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk percentage (in hundredths)	12.00%	12.00%	13.00%
Sales [Member] | Customer 2 [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk percentage (in hundredths)	'	11.00%	10.00%
Sales [Member] | Customer 3 [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk percentage (in hundredths)	'	'	10.00%
Accounts Receivable [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Total number of largest customers represented in sales	2	2	'
Accounts Receivable [Member] | Customer 1 [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk percentage (in hundredths)	19.00%	21.00%	'
Accounts Receivable [Member] | Customer 2 [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk percentage (in hundredths)	14.00%	11.00%	'

UnitBased_Compensation_and_Oth2

Unit-Based Compensation and Other Benefit Plans (Details) (USD $)

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 16, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Jan. 31, 2014

Jan. 31, 2014

Jan. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

General and Administrative Expenses [Member]

General and Administrative Expenses [Member]

General and Administrative Expenses [Member]

Lease Operating Expense [Member]

Lease Operating Expense [Member]

Lease Operating Expense [Member]

Unit Options [Member]

Unit Options [Member]

Unit Options [Member]

Unit Options [Member]

Phantom Units [Member]

Performance Units [Member]

Restricted Units [Member]

Restricted Units [Member]

Restricted Units [Member]

Restricted Units [Member]

Restricted/Unrestricted Units [Member]

Restricted/Unrestricted Units [Member]

Restricted/Unrestricted Units [Member]

Minimum [Member]

Maximum [Member]

Tranche One

Tranche Two

Nonemployee [Member]

Unit Options [Member]

Unit Options [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Berry employee unit-based awards

'

'

'

$18,879,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Awards vesting period (in years)

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'2 years

'3 years

Award vesting rights

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

50.00%

Contractual life of unit options (in years)

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of shares available for grant (in units)

6,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

21,000,000

'

'

'

'

'

'

Units authorized for issuance (in units)

9,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Units reserved for future issuance (in units)

6,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

21,000,000

'

'

'

'

'

'

Share-based Compensation [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Allocated Share Based Compensation Expense

42,703,000

29,533,000

22,243,000

'

37,375,000

27,641,000

21,131,000

5,328,000

1,892,000

1,112,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Income tax benefit

15,779,000

10,912,000

8,219,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restricted/Unrestricted Nonvested Units [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Nonvested units, beginning (in units)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,571,410

1,953,131

'

'

'

'

'

Granted (in units)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

213,710

212,524

1,435,192

'

'

'

1,652,711

'

'

'

'

'

'

Vested (in units)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-889,767

'

'

'

'

'

'

Forfeited (in units)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-144,665

'

'

'

'

'

'

Nonvested units, ending (in units)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,571,410

1,953,131

'

'

'

'

'

Outstanding, beginning (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$33.14

$36.16

'

'

'

'

'

Granted (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$30.71

$37.42

$38.54

'

'

'

'

Vested (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$34.63

'

'

'

'

'

'

Forfeited (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$37.09

'

'

'

'

'

'

Outstanding, ending (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$33.14

$36.16

'

'

'

'

'

Restricted/Unrestricted Units [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of units vested

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

31,000,000

24,000,000

13,000,000

'

'

'

'

'

'

'

Unrecognized compensation cost

'

'

'

'

'

'

'

'

'

'

9,000,000

'

'

'

'

'

'

40,000,000

'

'

'

'

'

'

'

'

'

Unrecognized compensation cost recognition period (in years)

'

'

'

'

'

'

'

'

'

'

'2 years 7 months 1 day

'

'

'

'

'

'

'1 year 7 months 6 days

'

'

'

'

'

'

'

'

'

Granted (in units)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

213,710

212,524

1,435,192

'

'

'

1,652,711

'

'

'

'

'

'

Unit Options Activity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding, beginning (in units)

'

'

'

'

'

'

'

'

'

'

6,433,223

4,642,805

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Berry assumed (in units)

'

'

'

'

'

'

'

'

'

'

2,237,593

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exercised (in units)

'

'

'

'

'

'

'

'

'

'

-117,175

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Forfeited or expired (in units)

'

'

'

'

'

'

'

'

'

'

-330,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding, ending (in units)

'

'

'

'

'

'

'

'

'

'

6,433,223

4,642,805

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exercisable (in units)

'

'

'

'

'

'

'

'

'

'

3,318,226

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Exercise Price Per Unit [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding, beginning (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

$30.22

$35.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Berry assumed (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

$20.58

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exercised (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

$18.79

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Forfeited or expired (in dollars per unit)

$39.55

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding, ending (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

$30.22

$35.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exercisable (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

$21.08

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unit-based compensation expenses

42,703,000

29,533,000

22,243,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Grant Date Fair Value Per Unit [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average grant date fair value of options granted (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

$7.52

$5.31

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted Average Remaining Contractual Life in Years [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding, beginning (in years)

'

'

'

'

'

'

'

'

'

'

'6 years 7 months 28 days

'6 years 3 months 10 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding, ending (in years)

'

'

'

'

'

'

'

'

'

'

'6 years 7 months 28 days

'6 years 3 months 10 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exercisable (in years)

'

'

'

'

'

'

'

'

'

'

'7 years 5 months 23 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Change in Unit Options and Unit Options Outstanding [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average grant date fair value of options granted (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

$7.52

$5.31

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Intrinsic value of options exercised

'

'

'

'

'

'

'

'

'

'

2,000,000

3,000,000

5,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from exercise of unit warrants

'

'

'

'

'

'

'

'

'

'

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation cost

'

'

'

'

'

'

'

'

'

'

9,000,000

'

'

'

'

'

'

40,000,000

'

'

'

'

'

'

'

'

'

Unrecognized compensation cost recognition period (in years)

'

'

'

'

'

'

'

'

'

'

'2 years 7 months 1 day

'

'

'

'

'

'

'1 year 7 months 6 days

'

'

'

'

'

'

'

'

'

Intrinsic value of outstanding unit options

'

'

'

'

'

'

'

'

'

'

33

16

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Intrinsic value of exercisable unit options

'

'

'

'

'

'

'

'

'

'

33

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected volatility (in hundredths)

'

34.10%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected volatility, minimum (in hundredths)

29.65%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected volatility, maximum (in hundredths)

50.88%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected distributions (in hundredths)

9.84%

7.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Risk free interest rate (in hundredths)

'

0.67%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Risk free interest rate, minimum (in hundredths)

0.13%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Risk free interest rate, minimum (in hundredths)

1.55%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected term (in years)

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'0 years 8 months 5 days

'5 years

'

'

Nonemployee Grants [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unit warrants oustanding (in units)

'

'

'

'

'

'

'

'

'

'

'

'

'

15,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Exercise price of unit warrants (in dollars per unit)

'

'

'

'

'

'

'

'

'

'

'

'

'

$25.50

'

'

'

'

'

'

'

'

'

'

'

'

'

Defined Contribution Plan [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Entity's matching contribution (in hundredths)

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Participant's eligible contribution, (in hundredths)

6.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Contribution to 401 (k) defined contribution plan

$7,000,000

$5,000,000

$4,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt_Details

Debt (Details) (USD $)

12 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Line of Credit

Line of Credit

Loans Payable

Loans Payable

Subordinated Debt

Subordinated Debt

Subordinated Debt

Berry

Berry

Berry

Berry

Berry

Berry

Berry

Berry

Berry

Berry

Berry

Berry

Berry

Berry

Berry

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Linn Energy, LLC

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Senior Notes Due November 2019

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Current Maturities

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Loans Payable

Loans Payable

Loans Payable

Loans Payable

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Senior Notes Due 2014

Senior Notes Due 2014

Senior Notes Due 2020

Senior Notes Due 2020

Senior Notes Due 2022

Senior Notes Due 2022

Senior Notes Due 2014

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Senior Notes Due 2017

Senior Notes Due 2017

Senior Notes Due 2018

Senior Notes Due 2018

Original Senior Notes

Senior Notes Due May 2019

Senior Notes Due May 2019

Senior Notes Due November 2019

Senior Notes Due November 2019

Senior Notes Due 2020

Senior Notes Due 2020

Senior Notes Due 2021

Senior Notes Due 2021

Minimum [Member]

Maximum [Member]

LIBOR

LIBOR

ABR

ABR

Minimum [Member]

Maximum [Member]

LIBOR

LIBOR

ABR

ABR

LIBOR

ABR

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Gross

$9,170,000,000

$6,038,000,000

'

$2,733,000,000

$1,180,000,000

$500,000,000

[1]

$0

[1]

$5,937,000,000

$4,858,000,000

'

$1,173,000,000

[2],[3]

$0

[2],[3]

'

'

'

'

'

'

$205,000,000

[2]

$0

[2]

$300,000,000

[2]

$0

[2]

$600,000,000

[2]

$0

[2]

'

$1,560,000,000

[4]

$1,180,000,000

[4]

'

'

'

'

'

'

'

$500,000,000

[1]

'

'

$0

$41,000,000

$0

$14,000,000

'

$750,000,000

$750,000,000

$1,800,000,000

$1,800,000,000

$1,300,000,000

$1,300,000,000

$1,000,000,000

$1,000,000,000

Net unamortized discounts and premiums

'

'

'

'

'

'

'

-18,000,000

-47,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt

9,170,000,000

6,038,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Current Maturities

'

'

'

'

'

'

'

-211,000,000

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Excluding Current Maturities

8,959,000,000

6,038,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate at Period End (in hundredths)

'

'

'

'

1.97%

'

'

'

'

'

2.67%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.92%

'

'

'

'

'

'

'

2.67%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Fair Value

9,395,000,000

6,271,000,000

'

2,733,000,000

1,180,000,000

500,000,000

0

6,162,000,000

5,091,000,000

'

'

'

'

'

'

'

'

'

212,000,000

'

310,000,000

'

607,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Maximum Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Borrowing Base

'

'

'

'

'

'

'

'

'

'

1,400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Amount Outstanding

2,733,175,000

1,180,000,000

'

'

'

'

'

'

'

'

1,200,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Remaining Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding letters of credit that reduce the credit facility availability

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

The percentage of properties that the company is required to maintain mortgages on (in hundredths)

'

'

'

'

'

'

'

'

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80.00%

'

'

'

'

'

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line Of Credit Facility Collateral Coverage Ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.5

'

'

'

'

'

'

'

2.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Basis Spread on Variable Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.50%

2.50%

0.50%

1.50%

'

'

'

'

'

'

'

'

'

'

'

1.50%

2.50%

0.50%

1.50%

'

'

2.50%

1.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility unused capacity commitment fee percentage (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

0.38%

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

0.38%

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

205,000,000

'

300,000,000

'

600,000,000

'

205,000,000

'

'

'

'

'

'

'

'

'

'

'

'

41,000,000

'

14,000,000

'

'

750,000,000

'

1,800,000,000

'

1,300,000,000

'

1,000,000,000

'

Debt Instrument, Interest Rate, Stated Percentage (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.25%

'

6.75%

'

6.38%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11.75%

'

9.88%

'

'

6.50%

'

6.25%

'

8.63%

'

7.75%

'

Debt Instrument, Unamortized Premium

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,000,000

'

10,000,000

'

7,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of days for effective registration statement

'

'

'

'

'

'

'

'

'

'400 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Additional interest due to late registration

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7,000,000

'

'

'

'

'

Loss on extinguishment of debt

$5,304,000

$0

$94,612,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

($5,000,000)

'

'

'

'

'

'

'

'

Increase in Interest Accruing on Long-Term Debt Due to Notes Not Yet Declared Effective

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.25%

'

'

'

'

'

[1]

Variable interest rate of 2.67% at December 31, 2013.

[2]

Assumed on DecemberB 16, 2013.

[3]

Variable interest rate of 2.67% at DecemberB 31, 2013.

[4]

Variable interest rates of 1.92% and 1.97% at December 31, 2013, and December 31, 2012, respectively.

Derivatives_Commodity_Derivati

Derivatives (Commodity Derivatives) (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
	MBbls		MBbls
	MMMBTU		MMMBTU
Derivative [Line Items]	'		'
Volumes of natural gas production on settled derivatives (in MMMbtu)	173,488		140,884
Average contract price per MMBtu on settled derivatives	5.29		5.41
Volumes of oil production on settled derivatives (in MBbls)	15,590		11,289
Average contract price per barrel on settled derivatives	95.35		97.61
2014 | Natural Gas Derivative Instruments | Fixed price swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	97,400		'
Weighted Average Fixed Price (in usd per energy unit)	5.25		'
2014 | Natural Gas Derivative Instruments | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	79,628	[1]	'
Weighted Average Short Put Price (in usd per energy unit)	5	[1]	'
2014 | Oil Derivative Instruments | Fixed price swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	16,831	[2]	'
Weighted Average Fixed Price (in usd per energy unit)	92.44	[2]	'
2014 | Oil Derivative Instruments | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	3,960		'
Weighted Average Short Put Price (in usd per energy unit)	91.3		'
2014 | Oil Derivative Instruments | Collars	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	730		'
Derivative, Floor Price	90		'
Derivative, Cap Price	102.87		'
2014 | Oil Derivative Instruments | Three-way collars (NYMEX WTI)	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	3,103		'
2014 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	72.11		'
Derivative, Cap Price	109.79		'
2014 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	93.76		'
2014 | Oil Derivative Instruments | Three-way collars (ICE Brent)	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	365		'
2014 | Oil Derivative Instruments | Three-way collars (ICE Brent) | Short	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	80		'
Derivative, Cap Price	114.05		'
2014 | Oil Derivative Instruments | Three-way collars (ICE Brent) | Long	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	100		'
2014 | Natural Gas Basis Differential Positions | Panhandle basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	79,388	[3]	'
Hedged Differential (in usd per energy unit)	-0.33	[3]	'
2014 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	39,718	[3]	'
Hedged Differential (in usd per energy unit)	-0.2	[3]	'
2014 | Natural Gas Basis Differential Positions | MichCon basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	9,490	[3]	'
Hedged Differential (in usd per energy unit)	0.08	[3]	'
2014 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	5,256	[3]	'
Hedged Differential (in usd per energy unit)	-0.1	[3]	'
2014 | Natural Gas Basis Differential Positions | Permian basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	4,891	[3]	'
Hedged Differential (in usd per energy unit)	-0.21	[3]	'
2014 | Oil Basis Differential Commodity Contract [Member] | ICE Brent - NYMEX WTI basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	3,650		'
Hedged Differential (in usd per energy unit)	11.6		'
2014 | Oil Timing Differential Positions | Trade month roll swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	9,079	[4]	'
Hedged Differential (in usd per energy unit)	0.24	[4]	'
2014 | Natural Gas Liquid Commodity Contract | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	10,570		'
2015 | Natural Gas Derivative Instruments | Fixed price swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	118,041		'
Weighted Average Fixed Price (in usd per energy unit)	5.19		'
2015 | Natural Gas Derivative Instruments | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	71,854	[1]	'
Weighted Average Short Put Price (in usd per energy unit)	5	[1]	'
2015 | Oil Derivative Instruments | Fixed price swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	11,599	[2]	'
Weighted Average Fixed Price (in usd per energy unit)	96.23	[2]	'
2015 | Oil Derivative Instruments | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	3,426		'
Weighted Average Short Put Price (in usd per energy unit)	90		'
2015 | Oil Derivative Instruments | Collars	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
Derivative, Floor Price	0		'
Derivative, Cap Price	0		'
2015 | Oil Derivative Instruments | Three-way collars (NYMEX WTI)	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	1,095		'
2015 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	70		'
Derivative, Cap Price	101.62		'
2015 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	90		'
2015 | Oil Derivative Instruments | Three-way collars (ICE Brent)	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
2015 | Oil Derivative Instruments | Three-way collars (ICE Brent) | Short	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
Derivative, Cap Price	0		'
2015 | Oil Derivative Instruments | Three-way collars (ICE Brent) | Long	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
2015 | Natural Gas Basis Differential Positions | Panhandle basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	87,162	[3]	'
Hedged Differential (in usd per energy unit)	-0.33	[3]	'
2015 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	43,292	[3]	'
Hedged Differential (in usd per energy unit)	-0.2	[3]	'
2015 | Natural Gas Basis Differential Positions | MichCon basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	9,344	[3]	'
Hedged Differential (in usd per energy unit)	0.06	[3]	'
2015 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	4,891	[3]	'
Hedged Differential (in usd per energy unit)	-0.1	[3]	'
2015 | Natural Gas Basis Differential Positions | Permian basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	5,074	[3]	'
Hedged Differential (in usd per energy unit)	-0.21	[3]	'
2015 | Oil Basis Differential Commodity Contract [Member] | ICE Brent - NYMEX WTI basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	2,920		'
Hedged Differential (in usd per energy unit)	11.6		'
2015 | Oil Timing Differential Positions | Trade month roll swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	7,251	[4]	'
Hedged Differential (in usd per energy unit)	0.24	[4]	'
2015 | Natural Gas Liquid Commodity Contract | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	10,570		'
2016 | Natural Gas Derivative Instruments | Fixed price swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	121,841		'
Weighted Average Fixed Price (in usd per energy unit)	4.2		'
2016 | Natural Gas Derivative Instruments | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	76,269	[1]	'
Weighted Average Short Put Price (in usd per energy unit)	5	[1]	'
2016 | Oil Derivative Instruments | Fixed price swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	11,465	[2]	'
Weighted Average Fixed Price (in usd per energy unit)	90.56	[2]	'
2016 | Oil Derivative Instruments | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	3,271		'
Weighted Average Short Put Price (in usd per energy unit)	90		'
2016 | Oil Derivative Instruments | Collars	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
Derivative, Floor Price	0		'
Derivative, Cap Price	0		'
2016 | Oil Derivative Instruments | Three-way collars (NYMEX WTI)	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
2016 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
Derivative, Cap Price	0		'
2016 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
2016 | Oil Derivative Instruments | Three-way collars (ICE Brent)	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
2016 | Oil Derivative Instruments | Three-way collars (ICE Brent) | Short	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
Derivative, Cap Price	0		'
2016 | Oil Derivative Instruments | Three-way collars (ICE Brent) | Long	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
2016 | Natural Gas Basis Differential Positions | Panhandle basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	59,954	[3]	'
Hedged Differential (in usd per energy unit)	-0.32	[3]	'
2016 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	46,294	[3]	'
Hedged Differential (in usd per energy unit)	-0.2	[3]	'
2016 | Natural Gas Basis Differential Positions | MichCon basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	7,768	[3]	'
Hedged Differential (in usd per energy unit)	0.05	[3]	'
2016 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	4,575	[3]	'
Hedged Differential (in usd per energy unit)	-0.1	[3]	'
2016 | Natural Gas Basis Differential Positions | Permian basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	4,219	[3]	'
Hedged Differential (in usd per energy unit)	-0.2	[3]	'
2016 | Oil Basis Differential Commodity Contract [Member] | ICE Brent - NYMEX WTI basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
Hedged Differential (in usd per energy unit)	0		'
2016 | Oil Timing Differential Positions | Trade month roll swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	7,446	[4]	'
Hedged Differential (in usd per energy unit)	0.25	[4]	'
2016 | Natural Gas Liquid Commodity Contract | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	10,599		'
2017 | Natural Gas Derivative Instruments | Fixed price swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	120,122		'
Weighted Average Fixed Price (in usd per energy unit)	4.26		'
2017 | Natural Gas Derivative Instruments | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	66,886	[1]	'
Weighted Average Short Put Price (in usd per energy unit)	4.88	[1]	'
2017 | Oil Derivative Instruments | Fixed price swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	4,755	[2]	'
Weighted Average Fixed Price (in usd per energy unit)	89.02	[2]	'
2017 | Oil Derivative Instruments | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	384		'
Weighted Average Short Put Price (in usd per energy unit)	90		'
2017 | Oil Derivative Instruments | Collars	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
Derivative, Floor Price	0		'
Derivative, Cap Price	0		'
2017 | Oil Derivative Instruments | Three-way collars (NYMEX WTI)	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
2017 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
Derivative, Cap Price	0		'
2017 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
2017 | Oil Derivative Instruments | Three-way collars (ICE Brent)	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
2017 | Oil Derivative Instruments | Three-way collars (ICE Brent) | Short	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
Derivative, Cap Price	0		'
2017 | Oil Derivative Instruments | Three-way collars (ICE Brent) | Long	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
2017 | Oil Derivative Instruments | Extendible Fixed Price Swaps	'		'
Derivative [Line Items]	'		'
Weighted Average Fixed Price (in usd per energy unit)	100		'
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384		'
2017 | Natural Gas Basis Differential Positions | Panhandle basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	59,138	[3]	'
Hedged Differential (in usd per energy unit)	-0.33	[3]	'
2017 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	38,880	[3]	'
Hedged Differential (in usd per energy unit)	-0.19	[3]	'
2017 | Natural Gas Basis Differential Positions | MichCon basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	7,437	[3]	'
Hedged Differential (in usd per energy unit)	0.05	[3]	'
2017 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	3,604	[3]	'
Hedged Differential (in usd per energy unit)	-0.08	[3]	'
2017 | Natural Gas Basis Differential Positions | Permian basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	4,819	[3]	'
Hedged Differential (in usd per energy unit)	-0.2	[3]	'
2017 | Oil Basis Differential Commodity Contract [Member] | ICE Brent - NYMEX WTI basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
Hedged Differential (in usd per energy unit)	0		'
2017 | Oil Timing Differential Positions | Trade month roll swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	6,486	[4]	'
Hedged Differential (in usd per energy unit)	0.25	[4]	'
2018 | Natural Gas Derivative Instruments | Fixed price swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	36,500		'
Weighted Average Fixed Price (in usd per energy unit)	5		'
2018 | Natural Gas Derivative Instruments | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0	[1]	'
Weighted Average Short Put Price (in usd per energy unit)	0	[1]	'
2018 | Oil Derivative Instruments | Fixed price swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0	[2]	'
Weighted Average Fixed Price (in usd per energy unit)	0	[2]	'
2018 | Oil Derivative Instruments | Puts	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
Weighted Average Short Put Price (in usd per energy unit)	0		'
2018 | Oil Derivative Instruments | Collars	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
Derivative, Floor Price	0		'
Derivative, Cap Price	0		'
2018 | Oil Derivative Instruments | Three-way collars (NYMEX WTI)	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
2018 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
Derivative, Cap Price	0		'
2018 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
2018 | Oil Derivative Instruments | Three-way collars (ICE Brent)	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
2018 | Oil Derivative Instruments | Three-way collars (ICE Brent) | Short	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
Derivative, Cap Price	0		'
2018 | Oil Derivative Instruments | Three-way collars (ICE Brent) | Long	'		'
Derivative [Line Items]	'		'
Derivative, Floor Price	0		'
2018 | Oil Derivative Instruments | Extendible Fixed Price Swaps	'		'
Derivative [Line Items]	'		'
Weighted Average Fixed Price (in usd per energy unit)	100		'
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384		'
2018 | Natural Gas Basis Differential Positions | Panhandle basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	16,425	[3]	'
Hedged Differential (in usd per energy unit)	-0.33	[3]	'
2018 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	10,804	[3]	'
Hedged Differential (in usd per energy unit)	-0.19	[3]	'
2018 | Natural Gas Basis Differential Positions | MichCon basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	2,044	[3]	'
Hedged Differential (in usd per energy unit)	0.05	[3]	'
2018 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	986	[3]	'
Hedged Differential (in usd per energy unit)	-0.08	[3]	'
2018 | Natural Gas Basis Differential Positions | Permian basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	1,314	[3]	'
Hedged Differential (in usd per energy unit)	-0.2	[3]	'
2018 | Oil Basis Differential Commodity Contract [Member] | ICE Brent - NYMEX WTI basis swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0		'
Hedged Differential (in usd per energy unit)	0		'
2018 | Oil Timing Differential Positions | Trade month roll swaps	'		'
Derivative [Line Items]	'		'
Annual Hedged Volume (in energy unit)	0	[4]	'
Hedged Differential (in usd per energy unit)	0	[4]	'
2019 | Oil Derivative Instruments | Extendible Fixed Price Swaps	'		'
Derivative [Line Items]	'		'
Weighted Average Fixed Price (in usd per energy unit)	90		'
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384		'
[1]	Includes certain outstanding natural gas put options of approximately 10,570 MMMBtu for each of the years ending DecemberB 31, 2014, and DecemberB 31, 2015, and 10,599 MMMBtu for the year ending DecemberB 31, 2016, used to indirectly hedge revenues associated with NGL production.
[2]	Includes certain outstanding fixed price oilB swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending DecemberB 31, 2017, and DecemberB 31, 2018, and $90.00 per Bbl for the year ending DecemberB 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.
[3]	Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.
[4]	The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the btrade month rollb).

Derivatives_Balance_Sheet_Pres

Derivatives (Balance Sheet Presentation) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
Derivative Asset, Fair Value	$1,048,212,000	$1,282,390,000
Derivative Liability, Fair Value	222,905,000	405,619,000
Maximum Loss Upon All Counterparties Failing To Perform	$1,000,000,000	'

Derivatives_Gains_Losses_On_De

Derivatives (Gains (Losses) On Derivatives) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Gains (Losses) on Derivatives	'	'	'
Total Gains Losses On Derivative Instruments	$178,000	$124,762	$449,940

Fair_Value_Measurements_on_a_R2

Fair Value Measurements on a Recurring Basis (Details) (Commodity Contracts, USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions	'		'
Fair value assets measured on recurring basis, derivative financial instruments, assets	$858,132		$880,911
Fair value assets measured on recurring basis, derivative financial instruments, liabilities	32,825		4,140
Fair Value, Inputs, Level 2	'		'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions	'		'
Fair value assets measured on recurring basis, derivative financial instruments, assets	1,048,212		1,282,390
Fair value assets measured on recurring basis, derivative financial instruments, liabilities	222,905		405,619
Counterparty netting under agreements governing derivatives	'		'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions	'		'
Fair value assets measured on recurring basis, derivative financial instruments, assets	-190,080	[1]	-401,479	[1]
Fair value assets measured on recurring basis, derivative financial instruments, liabilities	($190,080)	[1]	($401,479)	[1]
[1]	Represents counterparty netting under agreements governing such derivatives.

Other_Property_and_Equipment_D

Other Property and Equipment (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'
Other property and equipment	$647,882	$469,188
Less accumulated depreciation	-110,939	-73,721
Other preperty and equipment, net	536,943	395,467
Natural Gas Compression Plant and Pipeline [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Other property and equipment	507,342	371,292
Building and Leasehold Improvements [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Other property and equipment	32,658	19,999
Vehicles [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Other property and equipment	27,964	19,731
Drilling and Other Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Other property and equipment	8,618	6,265
Furniture and Office Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Other property and equipment	65,909	47,623
Land [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Other property and equipment	$5,391	$4,278

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation Disclosure [Abstract]	'	'	'
Future inflation factor used in the calculation of the asset retirement obligations	2.00%	2.00%	2.00%
Credit adjusted risk-free interest rate for the calculation of the asset retirement obligations	6.20%	6.80%	7.50%
Asset retirement obligations rollforward	'	'	'
Asset retirement obligations at beginning of year	$151,974	$71,142	'
Liabilities added from acquisitions	98,343	63,663	'
Liabilities added from drilling	4,048	1,799	'
Liabilities associated with assets sold	-1,092	0	'
Current year accretion expense	11,938	8,550	'
Settlements	-5,136	-3,640	'
Revision of estimates	29,246	10,460	'
Asset retirement obligations at end of year	$289,321	$151,974	$71,142

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	1 Months Ended	12 Months Ended		20 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013
Loss Contingency, Estimate [Abstract]	'	'	'	'
Amount of general unsecured claims from termination agreements	$51	'	'	'
Distribution received under termination agreement	'	11	28	39
Recovery of bankruptcy claim included in gains (losses) on oil and natural gas derivatives	'	'	22	'
Pending Litigation [Member]	'	'	'	'
Loss Contingency, Estimate [Abstract]	'	'	'	'
Loss Contingency, Range of Possible Loss, Minimum	'	1	'	1
Loss Contingency, Range of Possible Loss, Maximum	'	$4.50	'	$4.50

Earnings_Per_Unit_Details

Earnings Per Unit (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share [Abstract]	'	'	'
Net income (loss)	($691,337)	($386,616)	$438,439
Allocated to participating securities	-5,935	-4,575	-4,739
Net income (loss) available to common unitholders, basic	($697,272)	($391,191)	$433,700
Earnings per share reconciliation	'	'	'
Basic net income (loss) per unit	($2.94)	($1.92)	$2.52
Diluted net income (loss) per unit	($2.94)	($1.92)	$2.51
Weighted average units outstanding	'	'	'
Basic weighted average units outstanding	237,544,000	203,775,000	172,004,000
Dilutive effect of unit equivalents	0	0	725,000
Diluted weighted average units outstanding	237,544,000	203,775,000	172,729,000
Unit options and warrants	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'
Weighted average anti-dilutive unit equivalents excluded from computation of earnings per unit (in units)	4,000,000	2,000,000	0

Operating_Leases_Details

Operating Leases (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Leases, Operating [Abstract]	'	'	'
Operating lease expense	$7,000,000	$7,000,000	$5,000,000
Future Minimum Lease Payments [Abstract]	'	'	'
2014	14,222,000	'	'
2015	11,146,000	'	'
2016	7,869,000	'	'
2017	5,958,000	'	'
2018	5,055,000	'	'
Thereafter	5,786,000	'	'
Operating Leases, Future Minimum Payments Due, Total	$50,036,000	'	'

Income_Taxes_Details

Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current taxes [Abstract]	'	'	'
Federal	$144,000	$2,711,000	$4,551,000
State	198,000	439,000	605,000
Deferred taxes [Abstract]	'	'	'
Federal	-2,805,000	323,000	-1,148,000
State	264,000	-683,000	1,458,000
Income tax expense (benefit)	-2,199,000	2,790,000	5,466,000
Effective income tax rate reconciliation [Abstract]	'	'	'
Federal statutory rate (in hundredths)	35.00%	35.00%	35.00%
State, net of federal tax benefit (in hundredths)	-0.10%	0.10%	0.50%
Loss excluded from nontaxable entities (in hundredths)	34.60%	35.60%	34.40%
Other items (in hundredths)	0.00%	-0.20%	0.10%
Effective rate (in hundredths)	0.30%	-0.70%	1.20%
Deferred tax assets [Abstract]	'	'	'
Net operating loss carryforwards	1,129,000	0	'
Unit-based compensation	21,965,000	10,579,000	'
Other	7,759,000	4,924,000	'
Total deferred tax assets	30,853,000	15,503,000	'
Deferred tax liabilities [Abstract]	'	'	'
Property and equipment principally due to differences in depreciation	-12,525,000	-11,049,000	'
Other	-1,509,000	-1,055,000	'
Total deferred tax liabilities	-14,034,000	-12,104,000	'
Net deferred tax assets	16,819,000	3,399,000	'
Net deferred tax assets and liabilities classified in consolidated balance sheets [Abstract]	'	'	'
Deferred tax assets	29,204,000	10,318,000	'
Deferred tax liabilities	-10,000	-612,000	'
Other current assets	29,194,000	9,706,000	'
Deferred tax assets	1,649,000	5,186,000	'
Deferred tax liabilities	-14,024,000	-11,493,000	'
Other noncurrent assets	-12,375,000	-6,307,000	'
Federal [Member]	'	'	'
Operating Loss Carryforwards [Line Items]	'	'	'
Net operating loss carryforwards	$10,000,000	'	'
Net operating loss carryforwards, expiration dates	31-Dec-32	'	'

Supplemental_Disclosures_to_th2

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Balance Sheets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]	'	'
Accrued compensation	$55,257,000	$35,431,000
Accrued interest	93,998,000	72,668,000
Other	14,120,000	7,146,000
Other accrued liabilities	163,375,000	115,245,000
Restricted cash	6,000,000	5,000,000
Net Outstanding Checks	$48,000,000	$35,000,000

Supplemental_Disclosures_to_th3

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Cash Flows) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]	'	'	'
Cash payments for interest, net of amounts capitalized	$392,607,000	$343,331,000	$247,217,000
Cash payments for income taxes	14,000	366,000	487,000
Noncash investing and financing activities:	'	'	'
Fair value of assets acquired	5,726,681,000	2,923,990,000	1,523,466,000
Cash paid, net of cash acquired	-109,350,000	-2,640,475,000	-1,500,193,000
Units issued in connection with the Berry acquisition	2,781,888,000	0	0
Receivables from sellers	-93,000	2,132,000	3,557,000
Payables to sellers	-6,854,000	443,000	-4,847,000
Liabilities assumed	2,828,496,000	286,090,000	21,983,000
Joint-venture funding	$170,000,000	'	'

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 16, 2013

Oct. 17, 2012

Dec. 31, 2013

Dec. 17, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 17, 2013

Dec. 16, 2013

Dec. 17, 2013

LinnCo

LinnCo

Berry

Director

Director

Linn Energy, LLC

Linn Energy, LLC

LinnCo

Berry

Berry

Berry

Related Party Transaction [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Initial public offering, proceeds

'

'

'

'

$1,200,000,000

'

'

'

'

'

'

'

Units of LINN Energy acquired

'

'

'

'

34,787,500

'

'

'

'

'

'

'

Exchange ratio

'

'

'

'

'

'

168.00%

'

'

'

'

'

LinnCo common shares issued to acquire Berry

'

'

'

'

'

'

'

'

'

93,756,674

'

93,756,674

LINN Energy units issued to LinnCo for LinnCo common shares issued

'

'

'

'

'

'

'

'

'

93,756,674

'

93,756,674

Value of units issued to acquire Berry

'

'

'

2,763,009,000

'

'

'

'

'

'

2,800,000,000

'

Ownership percentage

'

'

'

'

'

39.00%

'

'

'

'

'

'

General and administrative expenses

236,271,000

173,206,000

133,272,000

'

'

42,000,000

'

'

'

'

'

'

General and administrative expenses paid on behalf of related party

'

'

'

'

'

22,000,000

'

'

'

'

'

'

Third party transaction costs related to the pending acquisition of Berry

'

'

'

'

'

40,000,000

'

'

'

'

'

'

Share-based compensation expense

42,703,000

29,533,000

22,243,000

'

'

9,000,000

'

'

'

'

'

'

Related party transaction, amounts of transaction

'

'

'

'

'

2,000,000

'

26,000,000

21,000,000

'

'

'

Offering costs paid on behalf of related party

'

'

'

'

'

0

'

'

'

'

'

'

Distribution paid during period

'

'

'

'

'

$101,000,000

'

'

'

'

'

'

Subsidiary_Guarantors_Condense

Subsidiary Guarantors Condensed Consolidating Balance Sheets (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Current assets	'	'	'	'
Cash and cash equivalents	$52,171	$1,243	$1,114	$236,001
Accounts receivable - trade, net	488,202	371,333	'	'
Accounts receivable b affiliates	0	'	'	'
Derivative instruments	176,130	350,695	'	'
Other current assets	99,437	88,157	'	'
Total current assets	815,940	811,428	'	'
Noncurrent assets	'	'	'	'
Oil and natural gas properties (successful efforts method)	17,888,559	11,611,330	'	'
Less accumulated depletion and amortization	-3,546,284	-2,025,656	'	'
Oil and natural gas properties, successful efforts method, net	14,342,275	9,585,674	'	'
Other property and equipment	647,882	469,188	'	'
Less accumulated depreciation	-110,939	-73,721	'	'
Other property and equipment, net	536,943	395,467	'	'
Derivative instruments	682,002	530,216	'	'
Notes receivable b affiliates	0	'	'	'
Investments in consolidated subsidiaries	0	'	'	'
Other noncurrent assets	127,804	128,453	'	'
Noncurrent assets, excluding property, total	809,806	658,669	'	'
Total noncurrent assets	15,689,024	10,639,810	'	'
Total assets	16,504,964	11,451,238	'	'
Current liabilities	'	'	'	'
Accounts payable and accrued expenses	849,624	707,861	'	'
Accounts payable b affiliates	0	'	'	'
Derivative instruments	28,176	26	'	'
Other accrued liabilities	163,375	115,245	'	'
Current portion of long-term debt	211,558	0	'	'
Total current liabilities	1,252,733	823,132	'	'
Noncurrent liabilities	'	'	'	'
Credit facilities	2,733,175	1,180,000	'	'
Term loan	500,000	0	'	'
Senior notes, net	5,725,483	4,857,817	'	'
Notes payable b affiliates	0	'	'	'
Derivative instruments	4,649	4,114	'	'
Other noncurrent liabilities	397,497	158,995	'	'
Total noncurrent liabilities	9,360,804	6,200,926	'	'
Unitholders' capital	'	'	'	'
Units issued and outstanding	6,291,824	4,136,240	'	'
Accumulated income (deficit)	-400,397	290,940	'	'
Total unitholders' capital	5,891,427	4,427,180	3,428,910	2,788,216
Total liabilities and unitholders' capital	16,504,964	11,451,238	'	'
Eliminations	'	'	'	'
Current assets	'	'	'	'
Cash and cash equivalents	0	0	'	'
Accounts receivable - trade, net	0	'	'	'
Accounts receivable b affiliates	-4,229,298	'	'	'
Derivative instruments	0	'	'	'
Other current assets	0	'	'	'
Total current assets	-4,229,298	'	'	'
Noncurrent assets	'	'	'	'
Oil and natural gas properties (successful efforts method)	0	'	'	'
Less accumulated depletion and amortization	0	'	'	'
Oil and natural gas properties, successful efforts method, net	0	'	'	'
Other property and equipment	0	'	'	'
Less accumulated depreciation	0	'	'	'
Other property and equipment, net	0	'	'	'
Derivative instruments	0	'	'	'
Notes receivable b affiliates	-86,200	'	'	'
Investments in consolidated subsidiaries	-7,139,737	'	'	'
Other noncurrent assets	0	'	'	'
Noncurrent assets, excluding property, total	-7,225,937	'	'	'
Total noncurrent assets	-7,225,937	'	'	'
Total assets	-11,455,235	'	'	'
Current liabilities	'	'	'	'
Accounts payable and accrued expenses	0	'	'	'
Accounts payable b affiliates	-4,229,298	'	'	'
Derivative instruments	0	'	'	'
Other accrued liabilities	0	'	'	'
Current portion of long-term debt	0	'	'	'
Total current liabilities	-4,229,298	'	'	'
Noncurrent liabilities	'	'	'	'
Credit facilities	0	'	'	'
Term loan	0	'	'	'
Senior notes, net	0	'	'	'
Notes payable b affiliates	-86,200	'	'	'
Derivative instruments	0	'	'	'
Other noncurrent liabilities	0	'	'	'
Total noncurrent liabilities	-86,200	'	'	'
Unitholders' capital	'	'	'	'
Units issued and outstanding	-7,139,737	'	'	'
Accumulated income (deficit)	0	'	'	'
Total unitholders' capital	-7,139,737	'	'	'
Total liabilities and unitholders' capital	-11,455,235	'	'	'
Linn Energy, LLC | Reportable Legal Entities	'	'	'	'
Current assets	'	'	'	'
Cash and cash equivalents	52	107	'	'
Accounts receivable - trade, net	0	'	'	'
Accounts receivable b affiliates	4,212,348	'	'	'
Derivative instruments	0	'	'	'
Other current assets	330	'	'	'
Total current assets	4,212,730	'	'	'
Noncurrent assets	'	'	'	'
Oil and natural gas properties (successful efforts method)	0	'	'	'
Less accumulated depletion and amortization	0	'	'	'
Oil and natural gas properties, successful efforts method, net	0	'	'	'
Other property and equipment	0	'	'	'
Less accumulated depreciation	0	'	'	'
Other property and equipment, net	0	'	'	'
Derivative instruments	0	'	'	'
Notes receivable b affiliates	86,200	'	'	'
Investments in consolidated subsidiaries	7,139,737	'	'	'
Other noncurrent assets	108,785	'	'	'
Noncurrent assets, excluding property, total	7,334,722	'	'	'
Total noncurrent assets	7,334,722	'	'	'
Total assets	11,547,452	'	'	'
Current liabilities	'	'	'	'
Accounts payable and accrued expenses	14,529	'	'	'
Accounts payable b affiliates	0	'	'	'
Derivative instruments	0	'	'	'
Other accrued liabilities	75,071	'	'	'
Current portion of long-term debt	0	'	'	'
Total current liabilities	89,600	'	'	'
Noncurrent liabilities	'	'	'	'
Credit facilities	1,560,000	'	'	'
Term loan	500,000	'	'	'
Senior notes, net	4,809,055	'	'	'
Notes payable b affiliates	0	'	'	'
Derivative instruments	0	'	'	'
Other noncurrent liabilities	0	'	'	'
Total noncurrent liabilities	6,869,055	'	'	'
Unitholders' capital	'	'	'	'
Units issued and outstanding	6,282,747	'	'	'
Accumulated income (deficit)	-1,693,950	'	'	'
Total unitholders' capital	4,588,797	'	'	'
Total liabilities and unitholders' capital	11,547,452	'	'	'
Guarantor Subsidiaries | Reportable Legal Entities	'	'	'	'
Current assets	'	'	'	'
Cash and cash equivalents	1,078	1,136	'	'
Accounts receivable - trade, net	365,347	'	'	'
Accounts receivable b affiliates	16,950	'	'	'
Derivative instruments	170,534	'	'	'
Other current assets	68,274	'	'	'
Total current assets	622,183	'	'	'
Noncurrent assets	'	'	'	'
Oil and natural gas properties (successful efforts method)	13,074,900	'	'	'
Less accumulated depletion and amortization	-3,535,890	'	'	'
Oil and natural gas properties, successful efforts method, net	9,539,010	'	'	'
Other property and equipment	564,756	'	'	'
Less accumulated depreciation	-110,706	'	'	'
Other property and equipment, net	454,050	'	'	'
Derivative instruments	679,491	'	'	'
Notes receivable b affiliates	0	'	'	'
Investments in consolidated subsidiaries	0	'	'	'
Other noncurrent assets	10,968	'	'	'
Noncurrent assets, excluding property, total	690,459	'	'	'
Total noncurrent assets	10,683,519	'	'	'
Total assets	11,305,702	'	'	'
Current liabilities	'	'	'	'
Accounts payable and accrued expenses	587,774	'	'	'
Accounts payable b affiliates	4,212,348	'	'	'
Derivative instruments	7,783	'	'	'
Other accrued liabilities	59,311	'	'	'
Current portion of long-term debt	0	'	'	'
Total current liabilities	4,867,216	'	'	'
Noncurrent liabilities	'	'	'	'
Credit facilities	0	'	'	'
Term loan	0	'	'	'
Senior notes, net	0	'	'	'
Notes payable b affiliates	86,200	'	'	'
Derivative instruments	0	'	'	'
Other noncurrent liabilities	205,406	'	'	'
Total noncurrent liabilities	291,606	'	'	'
Unitholders' capital	'	'	'	'
Units issued and outstanding	4,833,354	'	'	'
Accumulated income (deficit)	1,313,526	'	'	'
Total unitholders' capital	6,146,880	'	'	'
Total liabilities and unitholders' capital	11,305,702	'	'	'
Non-Guarantor Subsidiary | Reportable Legal Entities	'	'	'	'
Current assets	'	'	'	'
Cash and cash equivalents	51,041	0	'	'
Accounts receivable - trade, net	122,855	'	'	'
Accounts receivable b affiliates	0	'	'	'
Derivative instruments	5,596	'	'	'
Other current assets	30,833	'	'	'
Total current assets	210,325	'	'	'
Noncurrent assets	'	'	'	'
Oil and natural gas properties (successful efforts method)	4,813,659	'	'	'
Less accumulated depletion and amortization	-10,394	'	'	'
Oil and natural gas properties, successful efforts method, net	4,803,265	'	'	'
Other property and equipment	83,126	'	'	'
Less accumulated depreciation	-233	'	'	'
Other property and equipment, net	82,893	'	'	'
Derivative instruments	2,511	'	'	'
Notes receivable b affiliates	0	'	'	'
Investments in consolidated subsidiaries	0	'	'	'
Other noncurrent assets	8,051	'	'	'
Noncurrent assets, excluding property, total	10,562	'	'	'
Total noncurrent assets	4,896,720	'	'	'
Total assets	5,107,045	'	'	'
Current liabilities	'	'	'	'
Accounts payable and accrued expenses	247,321	'	'	'
Accounts payable b affiliates	16,950	'	'	'
Derivative instruments	20,393	'	'	'
Other accrued liabilities	28,993	'	'	'
Current portion of long-term debt	211,558	'	'	'
Total current liabilities	525,215	'	'	'
Noncurrent liabilities	'	'	'	'
Credit facilities	1,173,175	'	'	'
Term loan	0	'	'	'
Senior notes, net	916,428	'	'	'
Notes payable b affiliates	0	'	'	'
Derivative instruments	4,649	'	'	'
Other noncurrent liabilities	192,091	'	'	'
Total noncurrent liabilities	2,286,343	'	'	'
Unitholders' capital	'	'	'	'
Units issued and outstanding	2,315,460	'	'	'
Accumulated income (deficit)	-19,973	'	'	'
Total unitholders' capital	2,295,487	'	'	'
Total liabilities and unitholders' capital	$5,107,045	'	'	'

Subsidiary_Guarantors_Condense1

Subsidiary Guarantors Condensed Consolidating Statements of Operations (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Revenues and other:

'

'

'

'

'

'

'

'

'

'

'

Oil, natural gas and natural gas liquids sales

$584,630

[1]

$537,671

$488,207

$462,732

$460,976

$444,082

$347,227

$348,895

$2,073,240

$1,601,180

$1,162,037

Gains on oil and natural gas derivatives

23,425

[1]

-63,931

326,733

-108,370

94,489

-411,405

439,647

2,031

177,857

124,762

449,940

Marketing revenues

'

'

'

'

'

'

'

'

54,171

37,393

5,868

Other revenues

'

'

'

'

'

'

'

'

26,387

10,905

4,609

Total revenues

629,208

[1]

494,562

838,825

369,060

571,225

48,328

800,597

354,090

2,331,655

1,774,240

1,622,454

Expenses:

'

'

'

'

'

'

'

'

'

'

'

Lease operating expenses

'

'

'

'

'

'

'

'

372,523

317,699

232,619

Transportation expenses

'

'

'

'

'

'

'

'

128,440

77,322

28,358

Marketing expenses

'

'

'

'

'

'

'

'

37,892

31,821

3,681

General and administrative expenses

'

'

'

'

'

'

'

'

236,271

173,206

133,272

Exploration costs

'

'

'

'

'

'

'

'

5,251

1,915

2,390

Depreciation, depletion and amortization

'

'

'

'

'

'

'

'

829,311

606,150

334,084

Impairment of long-lived assets

'

'

'

'

'

'

'

'

828,317

422,499

0

Taxes, other than income taxes

'

'

'

'

'

'

'

'

138,631

131,679

78,522

Losses on sale of assets and other, net

-10,597

[1]

-827

959

-3,172

-31

-16

2

-1,494

13,637

1,539

3,494

Total expenses

1,292,058

[1],[2]

420,803

[2]

385,540

[2]

478,235

[2]

656,221

[2]

376,323

[2]

460,655

[2]

269,092

[2]

2,590,273

1,763,830

816,420

Other income and (expenses):

'

'

'

'

'

'

'

'

'

'

'

Interest expense, net of amounts capitalized

'

'

'

'

'

'

'

'

-421,137

-379,937

-259,725

Interest expense b affiliates

'

'

'

'

'

'

'

'

0

'

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

-5,304

0

-94,612

Interest income b affiliates

'

'

'

'

'

'

'

'

0

'

'

Other, net

'

'

'

'

'

'

'

'

-8,477

-14,299

-7,792

Total other income and (expenses)

'

'

'

'

'

'

'

'

-434,918

-394,236

-362,129

Income (loss) before income taxes

'

'

'

'

'

'

'

'

-693,536

-383,826

443,905

Income tax expense (benefit)

'

'

'

'

'

'

'

'

2,199

-2,790

-5,466

Net income (loss)

-784,549

[1]

-30,060

345,157

-221,885

-187,495

-430,005

237,086

-6,202

-691,337

-386,616

438,439

Eliminations

'

'

'

'

'

'

'

'

'

'

'

Revenues and other:

'

'

'

'

'

'

'

'

'

'

'

Oil, natural gas and natural gas liquids sales

'

'

'

'

'

'

'

'

0

'

'

Gains on oil and natural gas derivatives

'

'

'

'

'

'

'

'

0

'

'

Marketing revenues

'

'

'

'

'

'

'

'

0

'

'

Other revenues

'

'

'

'

'

'

'

'

0

'

'

Total revenues

'

'

'

'

'

'

'

'

0

'

'

Expenses:

'

'

'

'

'

'

'

'

'

'

'

Lease operating expenses

'

'

'

'

'

'

'

'

0

'

'

Transportation expenses

'

'

'

'

'

'

'

'

0

'

'

Marketing expenses

'

'

'

'

'

'

'

'

0

'

'

General and administrative expenses

'

'

'

'

'

'

'

'

0

'

'

Exploration costs

'

'

'

'

'

'

'

'

0

'

'

Depreciation, depletion and amortization

'

'

'

'

'

'

'

'

0

'

'

Impairment of long-lived assets

'

'

'

'

'

'

'

'

0

'

'

Taxes, other than income taxes

'

'

'

'

'

'

'

'

0

'

'

Losses on sale of assets and other, net

'

'

'

'

'

'

'

'

0

'

'

Total expenses

'

'

'

'

'

'

'

'

0

'

'

Other income and (expenses):

'

'

'

'

'

'

'

'

'

'

'

Interest expense, net of amounts capitalized

'

'

'

'

'

'

'

'

0

'

'

Interest expense b affiliates

'

'

'

'

'

'

'

'

5,543

'

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

0

'

'

Interest income b affiliates

'

'

'

'

'

'

'

'

-5,543

'

'

Other, net

'

'

'

'

'

'

'

'

0

'

'

Total other income and (expenses)

'

'

'

'

'

'

'

'

0

'

'

Income (loss) before income taxes

'

'

'

'

'

'

'

'

0

'

'

Income tax expense (benefit)

'

'

'

'

'

'

'

'

0

'

'

Net income (loss)

'

'

'

'

'

'

'

'

0

'

'

Linn Energy, LLC | Reportable Legal Entities

'

'

'

'

'

'

'

'

'

'

'

Revenues and other:

'

'

'

'

'

'

'

'

'

'

'

Oil, natural gas and natural gas liquids sales

'

'

'

'

'

'

'

'

0

'

'

Gains on oil and natural gas derivatives

'

'

'

'

'

'

'

'

0

'

'

Marketing revenues

'

'

'

'

'

'

'

'

0

'

'

Other revenues

'

'

'

'

'

'

'

'

0

'

'

Total revenues

'

'

'

'

'

'

'

'

0

'

'

Expenses:

'

'

'

'

'

'

'

'

'

'

'

Lease operating expenses

'

'

'

'

'

'

'

'

0

'

'

Transportation expenses

'

'

'

'

'

'

'

'

0

'

'

Marketing expenses

'

'

'

'

'

'

'

'

0

'

'

General and administrative expenses

'

'

'

'

'

'

'

'

0

'

'

Exploration costs

'

'

'

'

'

'

'

'

0

'

'

Depreciation, depletion and amortization

'

'

'

'

'

'

'

'

0

'

'

Impairment of long-lived assets

'

'

'

'

'

'

'

'

0

'

'

Taxes, other than income taxes

'

'

'

'

'

'

'

'

0

'

'

Losses on sale of assets and other, net

'

'

'

'

'

'

'

'

724

'

'

Total expenses

'

'

'

'

'

'

'

'

724

'

'

Other income and (expenses):

'

'

'

'

'

'

'

'

'

'

'

Interest expense, net of amounts capitalized

'

'

'

'

'

'

'

'

-415,670

'

'

Interest expense b affiliates

'

'

'

'

'

'

'

'

0

'

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

-5,304

'

'

Interest income b affiliates

'

'

'

'

'

'

'

'

5,543

'

'

Other, net

'

'

'

'

'

'

'

'

-8,283

'

'

Total other income and (expenses)

'

'

'

'

'

'

'

'

-423,714

'

'

Income (loss) before income taxes

'

'

'

'

'

'

'

'

-424,438

'

'

Income tax expense (benefit)

'

'

'

'

'

'

'

'

0

'

'

Net income (loss)

'

'

'

'

'

'

'

'

-424,438

'

'

Guarantor Subsidiaries | Reportable Legal Entities

'

'

'

'

'

'

'

'

'

'

'

Revenues and other:

'

'

'

'

'

'

'

'

'

'

'

Oil, natural gas and natural gas liquids sales

'

'

'

'

'

'

'

'

2,022,916

'

'

Gains on oil and natural gas derivatives

'

'

'

'

'

'

'

'

182,906

'

'

Marketing revenues

'

'

'

'

'

'

'

'

53,772

'

'

Other revenues

'

'

'

'

'

'

'

'

24,943

'

'

Total revenues

'

'

'

'

'

'

'

'

2,284,537

'

'

Expenses:

'

'

'

'

'

'

'

'

'

'

'

Lease operating expenses

'

'

'

'

'

'

'

'

357,113

'

'

Transportation expenses

'

'

'

'

'

'

'

'

125,864

'

'

Marketing expenses

'

'

'

'

'

'

'

'

36,259

'

'

General and administrative expenses

'

'

'

'

'

'

'

'

215,973

'

'

Exploration costs

'

'

'

'

'

'

'

'

5,251

'

'

Depreciation, depletion and amortization

'

'

'

'

'

'

'

'

818,466

'

'

Impairment of long-lived assets

'

'

'

'

'

'

'

'

828,317

'

'

Taxes, other than income taxes

'

'

'

'

'

'

'

'

136,501

'

'

Losses on sale of assets and other, net

'

'

'

'

'

'

'

'

2,705

'

'

Total expenses

'

'

'

'

'

'

'

'

2,526,449

'

'

Other income and (expenses):

'

'

'

'

'

'

'

'

'

'

'

Interest expense, net of amounts capitalized

'

'

'

'

'

'

'

'

-1,504

'

'

Interest expense b affiliates

'

'

'

'

'

'

'

'

-5,543

'

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

0

'

'

Interest income b affiliates

'

'

'

'

'

'

'

'

0

'

'

Other, net

'

'

'

'

'

'

'

'

-166

'

'

Total other income and (expenses)

'

'

'

'

'

'

'

'

-7,213

'

'

Income (loss) before income taxes

'

'

'

'

'

'

'

'

-249,125

'

'

Income tax expense (benefit)

'

'

'

'

'

'

'

'

2,199

'

'

Net income (loss)

'

'

'

'

'

'

'

'

-246,926

'

'

Non-Guarantor Subsidiary | Reportable Legal Entities

'

'

'

'

'

'

'

'

'

'

'

Revenues and other:

'

'

'

'

'

'

'

'

'

'

'

Oil, natural gas and natural gas liquids sales

'

'

'

'

'

'

'

'

50,324

'

'

Gains on oil and natural gas derivatives

'

'

'

'

'

'

'

'

-5,049

'

'

Marketing revenues

'

'

'

'

'

'

'

'

399

'

'

Other revenues

'

'

'

'

'

'

'

'

1,444

'

'

Total revenues

'

'

'

'

'

'

'

'

47,118

'

'

Expenses:

'

'

'

'

'

'

'

'

'

'

'

Lease operating expenses

'

'

'

'

'

'

'

'

15,410

'

'

Transportation expenses

'

'

'

'

'

'

'

'

2,576

'

'

Marketing expenses

'

'

'

'

'

'

'

'

1,633

'

'

General and administrative expenses

'

'

'

'

'

'

'

'

20,298

'

'

Exploration costs

'

'

'

'

'

'

'

'

0

'

'

Depreciation, depletion and amortization

'

'

'

'

'

'

'

'

10,845

'

'

Impairment of long-lived assets

'

'

'

'

'

'

'

'

0

'

'

Taxes, other than income taxes

'

'

'

'

'

'

'

'

2,130

'

'

Losses on sale of assets and other, net

'

'

'

'

'

'

'

'

10,208

'

'

Total expenses

'

'

'

'

'

'

'

'

63,100

'

'

Other income and (expenses):

'

'

'

'

'

'

'

'

'

'

'

Interest expense, net of amounts capitalized

'

'

'

'

'

'

'

'

-3,963

'

'

Interest expense b affiliates

'

'

'

'

'

'

'

'

0

'

'

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

0

'

'

Interest income b affiliates

'

'

'

'

'

'

'

'

0

'

'

Other, net

'

'

'

'

'

'

'

'

-28

'

'

Total other income and (expenses)

'

'

'

'

'

'

'

'

-3,991

'

'

Income (loss) before income taxes

'

'

'

'

'

'

'

'

-19,973

'

'

Income tax expense (benefit)

'

'

'

'

'

'

'

'

0

'

'

Net income (loss)

'

'

'

'

'

'

'

'

($19,973)

'

'

[1]

Includes the results of operations of the Berry Acquisition since the acquisition date (see NoteB 2).

[2]

Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.

Subsidiary_Guarantors_Condense2

Subsidiary Guarantors Condensed Consolidating Statements of Cash Flow (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flow from operating activities:	'	'	'
Net income (loss)	($691,337)	($386,616)	$438,439
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:	'	'	'
Depreciation, depletion and amortization	829,311	606,150	334,084
Impairment of long-lived assets	828,317	422,499	0
Unit-based compensation expenses	42,703	29,533	22,243
Loss on extinguishment of debt	5,304	0	94,612
Amortization and write-off of deferred financing fees	21,507	25,598	21,526
Losses on sale of assets and other, net	37,232	92	2,021
Deferred income tax	-2,541	-360	310
Derivatives activities:	'	'	'
Total (gains) losses	-177,857	-124,762	-449,940
Cash settlements	248,862	390,765	237,134
Changes in assets and liabilities:	'	'	'
(Increase) decrease in accounts receivable - trade, net	89,188	-77,573	-191,338
(Increase) decrease in accounts receivable b affiliates	0	'	'
(Increase) decrease in other assets	16,179	-5,451	-2,951
Increase (decrease) in accounts payable and accrued expenses	-76,993	26,372	129,499
Increase (decrease) in accounts payable and accrued expenses b affiliates	0	'	'
Increase (decrease) in other liabilities	-3,663	28,094	-9,333
Net cash provided by (used in) operating activities	1,166,212	350,907	518,706
Cash flow from investing activities:	'	'	'
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	-279,213	-2,640,475	-1,500,193
Development of oil and natural gas properties	-1,078,025	-984,530	-574,635
Purchases of other property and equipment	-92,352	-60,549	-55,229
Investment in affiliates	0	'	'
Change in notes receivable with affiliate	0	'	'
Proceeds from sale of properties and equipment and other	196,273	725	-303
Net cash provided by (used in) investing activities	-1,253,317	-3,684,829	-2,130,360
Cash flow from financing activities:	'	'	'
Proceeds from borrowings	2,230,000	5,439,802	2,534,240
Repayments of debt	-1,404,898	-3,400,000	-1,301,029
Distributions to unitholders	-682,241	-596,935	-466,488
Financing fees, offering expenses and other, net	-4,988	-85,895	-56,358
Change in note payable with affiliate	0	'	'
Capital contribution b affiliates	0	'	'
Excess tax benefit from unit-based compensation	160	3,090	4,805
Net cash provided by (used in) financing activities	138,033	3,334,051	1,376,767
Net increase (decrease) in cash and cash equivalents	50,928	129	-234,887
Cash and cash equivalents:	'	'	'
Beginning	1,243	1,114	236,001
Ending	52,171	1,243	1,114
Eliminations	'	'	'
Cash flow from operating activities:	'	'	'
Net income (loss)	0	'	'
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:	'	'	'
Depreciation, depletion and amortization	0	'	'
Impairment of long-lived assets	0	'	'
Unit-based compensation expenses	0	'	'
Loss on extinguishment of debt	0	'	'
Amortization and write-off of deferred financing fees	0	'	'
Losses on sale of assets and other, net	0	'	'
Deferred income tax	0	'	'
Derivatives activities:	'	'	'
Total (gains) losses	0	'	'
Cash settlements	0	'	'
Changes in assets and liabilities:	'	'	'
(Increase) decrease in accounts receivable - trade, net	0	'	'
(Increase) decrease in accounts receivable b affiliates	137,917	'	'
(Increase) decrease in other assets	0	'	'
Increase (decrease) in accounts payable and accrued expenses	0	'	'
Increase (decrease) in accounts payable and accrued expenses b affiliates	-137,917	'	'
Increase (decrease) in other liabilities	0	'	'
Net cash provided by (used in) operating activities	0	'	'
Cash flow from investing activities:	'	'	'
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	0	'	'
Development of oil and natural gas properties	0	'	'
Purchases of other property and equipment	0	'	'
Investment in affiliates	-435,000	'	'
Change in notes receivable with affiliate	26,700	'	'
Proceeds from sale of properties and equipment and other	0	'	'
Net cash provided by (used in) investing activities	-408,300	'	'
Cash flow from financing activities:	'	'	'
Proceeds from borrowings	0	'	'
Repayments of debt	0	'	'
Distributions to unitholders	0	'	'
Financing fees, offering expenses and other, net	0	'	'
Change in note payable with affiliate	-26,700	'	'
Capital contribution b affiliates	435,000	'	'
Excess tax benefit from unit-based compensation	0	'	'
Net cash provided by (used in) financing activities	408,300	'	'
Net increase (decrease) in cash and cash equivalents	0	'	'
Cash and cash equivalents:	'	'	'
Beginning	0	'	'
Ending	0	'	'
Linn Energy, LLC | Reportable Legal Entities	'	'	'
Cash flow from operating activities:	'	'	'
Net income (loss)	-424,438	'	'
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:	'	'	'
Depreciation, depletion and amortization	0	'	'
Impairment of long-lived assets	0	'	'
Unit-based compensation expenses	0	'	'
Loss on extinguishment of debt	5,304	'	'
Amortization and write-off of deferred financing fees	22,122	'	'
Losses on sale of assets and other, net	0	'	'
Deferred income tax	0	'	'
Derivatives activities:	'	'	'
Total (gains) losses	0	'	'
Cash settlements	0	'	'
Changes in assets and liabilities:	'	'	'
(Increase) decrease in accounts receivable - trade, net	0	'	'
(Increase) decrease in accounts receivable b affiliates	-120,967	'	'
(Increase) decrease in other assets	-330	'	'
Increase (decrease) in accounts payable and accrued expenses	178	'	'
Increase (decrease) in accounts payable and accrued expenses b affiliates	0	'	'
Increase (decrease) in other liabilities	2,092	'	'
Net cash provided by (used in) operating activities	-516,039	'	'
Cash flow from investing activities:	'	'	'
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	0	'	'
Development of oil and natural gas properties	0	'	'
Purchases of other property and equipment	0	'	'
Investment in affiliates	435,000	'	'
Change in notes receivable with affiliate	-26,700	'	'
Proceeds from sale of properties and equipment and other	-22,039	'	'
Net cash provided by (used in) investing activities	386,261	'	'
Cash flow from financing activities:	'	'	'
Proceeds from borrowings	2,230,000	'	'
Repayments of debt	-1,404,898	'	'
Distributions to unitholders	-682,241	'	'
Financing fees, offering expenses and other, net	-13,138	'	'
Change in note payable with affiliate	0	'	'
Capital contribution b affiliates	0	'	'
Excess tax benefit from unit-based compensation	0	'	'
Net cash provided by (used in) financing activities	129,723	'	'
Net increase (decrease) in cash and cash equivalents	-55	'	'
Cash and cash equivalents:	'	'	'
Beginning	107	'	'
Ending	52	'	'
Guarantor Subsidiaries | Reportable Legal Entities	'	'	'
Cash flow from operating activities:	'	'	'
Net income (loss)	-246,926	'	'
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:	'	'	'
Depreciation, depletion and amortization	818,466	'	'
Impairment of long-lived assets	828,317	'	'
Unit-based compensation expenses	42,703	'	'
Loss on extinguishment of debt	0	'	'
Amortization and write-off of deferred financing fees	0	'	'
Losses on sale of assets and other, net	37,232	'	'
Deferred income tax	-2,541	'	'
Derivatives activities:	'	'	'
Total (gains) losses	-182,906	'	'
Cash settlements	248,862	'	'
Changes in assets and liabilities:	'	'	'
(Increase) decrease in accounts receivable - trade, net	17,754	'	'
(Increase) decrease in accounts receivable b affiliates	-16,950	'	'
(Increase) decrease in other assets	5,896	'	'
Increase (decrease) in accounts payable and accrued expenses	-52,143	'	'
Increase (decrease) in accounts payable and accrued expenses b affiliates	120,967	'	'
Increase (decrease) in other liabilities	6,842	'	'
Net cash provided by (used in) operating activities	1,625,573	'	'
Cash flow from investing activities:	'	'	'
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	-730,326	'	'
Development of oil and natural gas properties	-1,060,547	'	'
Purchases of other property and equipment	-92,352	'	'
Investment in affiliates	0	'	'
Change in notes receivable with affiliate	0	'	'
Proceeds from sale of properties and equipment and other	218,312	'	'
Net cash provided by (used in) investing activities	-1,664,913	'	'
Cash flow from financing activities:	'	'	'
Proceeds from borrowings	0	'	'
Repayments of debt	0	'	'
Distributions to unitholders	0	'	'
Financing fees, offering expenses and other, net	12,422	'	'
Change in note payable with affiliate	26,700	'	'
Capital contribution b affiliates	0	'	'
Excess tax benefit from unit-based compensation	160	'	'
Net cash provided by (used in) financing activities	39,282	'	'
Net increase (decrease) in cash and cash equivalents	-58	'	'
Cash and cash equivalents:	'	'	'
Beginning	1,136	'	'
Ending	1,078	'	'
Non-Guarantor Subsidiary | Reportable Legal Entities	'	'	'
Cash flow from operating activities:	'	'	'
Net income (loss)	-19,973	'	'
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:	'	'	'
Depreciation, depletion and amortization	10,845	'	'
Impairment of long-lived assets	0	'	'
Unit-based compensation expenses	0	'	'
Loss on extinguishment of debt	0	'	'
Amortization and write-off of deferred financing fees	-615	'	'
Losses on sale of assets and other, net	0	'	'
Deferred income tax	0	'	'
Derivatives activities:	'	'	'
Total (gains) losses	5,049	'	'
Cash settlements	0	'	'
Changes in assets and liabilities:	'	'	'
(Increase) decrease in accounts receivable - trade, net	71,434	'	'
(Increase) decrease in accounts receivable b affiliates	0	'	'
(Increase) decrease in other assets	10,613	'	'
Increase (decrease) in accounts payable and accrued expenses	-25,028	'	'
Increase (decrease) in accounts payable and accrued expenses b affiliates	16,950	'	'
Increase (decrease) in other liabilities	-12,597	'	'
Net cash provided by (used in) operating activities	56,678	'	'
Cash flow from investing activities:	'	'	'
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	451,113	'	'
Development of oil and natural gas properties	-17,478	'	'
Purchases of other property and equipment	0	'	'
Investment in affiliates	0	'	'
Change in notes receivable with affiliate	0	'	'
Proceeds from sale of properties and equipment and other	0	'	'
Net cash provided by (used in) investing activities	433,635	'	'
Cash flow from financing activities:	'	'	'
Proceeds from borrowings	0	'	'
Repayments of debt	0	'	'
Distributions to unitholders	0	'	'
Financing fees, offering expenses and other, net	-4,272	'	'
Change in note payable with affiliate	0	'	'
Capital contribution b affiliates	-435,000	'	'
Excess tax benefit from unit-based compensation	0	'	'
Net cash provided by (used in) financing activities	-439,272	'	'
Net increase (decrease) in cash and cash equivalents	51,041	'	'
Cash and cash equivalents:	'	'	'
Beginning	0	'	'
Ending	$51,041	'	'

Supplemental_Oil_and_Natural_G2

Supplemental Oil and Natural Gas Data (Unaudited) (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mcfe

Mcfe

Mcfe

Mcfe

Mcfe

Mcfe

Mcfe

Property acquisition costs [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Proved

'

'

'

'

'

'

'

'

$3,740,379

[1]

$2,531,419

[1]

$1,328,328

[1]

Unproved

'

'

'

'

'

'

'

'

1,638,302

[1]

181,124

[1]

188,409

[1]

Exploration costs

'

'

'

'

'

'

'

'

13,096

452

80

Development costs

'

'

'

'

'

'

'

'

1,153,770

1,062,043

639,395

Asset retirement costs

7,351

'

'

'

4,675

'

'

'

7,351

4,675

2,427

Total costs incurred

'

'

'

'

'

'

'

'

6,552,898

3,779,713

2,158,639

Proved properties [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Leasehold acquisition

12,277,089

'

'

'

8,603,888

'

'

'

12,277,089

8,603,888

'

Development

3,660,277

'

'

'

2,553,127

'

'

'

3,660,277

2,553,127

'

Unproved properties

1,951,193

'

'

'

454,315

'

'

'

1,951,193

454,315

'

Capitalized cost, oil and gas producing activities

17,888,559

'

'

'

11,611,330

'

'

'

17,888,559

11,611,330

'

Less accumulated depletion and amortization

-3,546,284

'

'

'

-2,025,656

'

'

'

-3,546,284

-2,025,656

'

Capitalized costs, oil and gas producing activities, net

14,342,275

'

'

'

9,585,674

'

'

'

14,342,275

9,585,674

'

Revenues and other:

'

'

'

'

'

'

'

'

'

'

'

Oil, natural gas and natural gas liquid sales

'

'

'

'

'

'

'

'

2,073,240

1,601,180

1,162,037

Gains on oil and natural gas derivatives

23,425

[2]

-63,931

326,733

-108,370

94,489

-411,405

439,647

2,031

177,857

124,762

449,940

Results of Operations, Revenue from Oil and Gas Producing Activities

'

'

'

'

'

'

'

'

2,251,097

1,725,942

1,611,977

Production costs [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Lease operating expenses

'

'

'

'

'

'

'

'

372,523

317,699

232,619

Transportation expenses

'

'

'

'

'

'

'

'

128,440

77,322

28,358

Severance and ad valorem taxes

'

'

'

'

'

'

'

'

139,202

130,805

78,458

Total production costs

'

'

'

'

'

'

'

'

640,165

525,826

339,435

Other costs [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Exploration costs

'

'

'

'

'

'

'

'

5,251

1,915

2,390

Depletion and amortization

'

'

'

'

'

'

'

'

790,320

579,382

320,096

Impairment of long-lived assets

'

'

'

'

'

'

'

'

828,317

422,499

0

Gains on sale of assets and other, net

'

'

'

'

'

'

'

'

-138

-1,369

-1,001

Texas margin tax expense

'

'

'

'

'

'

'

'

458

-787

1,599

Total other costs

'

'

'

'

'

'

'

'

1,624,208

1,001,640

323,084

Results of operations

'

'

'

'

'

'

'

'

-13,276

198,476

949,458

Proved developed and undeveloped reserves [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

4,796,000,000

'

'

'

3,370,000,000

4,796,000,000

3,370,000,000

2,597,000,000

Revisions of previous estimates

'

'

'

'

'

'

'

'

-157,000,000

-803,000,000

-121,000,000

Purchase of minerals in place

'

'

'

'

'

'

'

'

1,610,000,000

1,766,000,000

579,000,000

Sales of minerals in place

'

'

'

'

'

'

'

'

-73,000,000

'

'

Extensions, discoveries and other additions

'

'

'

'

'

'

'

'

527,000,000

709,000,000

450,000,000

Production

'

'

'

'

'

'

'

'

-300,000,000

-246,000,000

-135,000,000

End of year

6,403,000,000

'

'

'

4,796,000,000

'

'

'

6,403,000,000

4,796,000,000

3,370,000,000

Proved developed reserves [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

3,127,000,000

'

'

'

2,034,000,000

3,127,000,000

2,034,000,000

1,662,000,000

End of year

4,340,000,000

'

'

'

3,127,000,000

'

'

'

4,340,000,000

3,127,000,000

2,034,000,000

Proved undeveloped reserves [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

1,669,000,000

'

'

'

1,336,000,000

1,669,000,000

1,336,000,000

935,000,000

End of year

2,063,000,000

'

'

'

1,669,000,000

'

'

'

2,063,000,000

1,669,000,000

1,336,000,000

Conversion rate between oil and NGL volumes to natural gas

'

'

'

'

'

'

'

'

6

'

'

Change in proved reserves (in Mcfe)

'

'

'

'

'

'

'

'

1,607,000,000

1,426,000,000

773,000,000

Change in proved reserves due to asset performance (in Mcfe)

'

'

'

'

'

'

'

'

100,000,000

340,000,000

-153,000,000

Change in proved reserves due to change in commodity prices (in Mcfe)

'

'

'

'

'

'

'

'

52,000,000

-248,000,000

32,000,000

Change in proved reserves due to the SEC five-year development limitation on PUDs

'

'

'

'

'

'

'

'

109,000,000

215,000,000

'

Number of acquisition of oil and natural gas properties

'

'

'

'

'

'

'

'

3

7

12

Productive wells drilled

'

'

'

'

'

'

'

'

557

436

292

Discounted future net cash flows relating to proved oil and gas reserves, future net cash Flows [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Future estimated revenues

'

'

'

'

'

'

'

'

51,112,346

30,374,380

29,319,369

Future estimated production costs

'

'

'

'

'

'

'

'

-19,306,728

-11,460,854

-9,464,319

Future estimated development costs

'

'

'

'

'

'

'

'

-5,110,896

-3,574,058

-2,848,497

Future net cash flows

'

'

'

'

'

'

'

'

26,694,722

15,339,468

17,006,553

10% annual discount for estimated timing of cash flows

'

'

'

'

'

'

'

'

-14,795,393

-9,266,487

-10,391,693

Standardized measure of discounted future net cash flows

'

'

'

'

'

'

'

'

11,899,329

6,072,981

6,614,860

Representative NYMEX prices [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Natural gas (dollars per MMBtu)

'

'

'

'

'

'

'

'

3.67

[3]

2.76

[3]

4.12

[3]

Oil (dollars per Bbl)

'

'

'

'

'

'

'

'

96.89

[3]

94.64

[3]

95.84

[3]

Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Sales and transfers of oil, natural gas and NGL produced during the period

'

'

'

'

'

'

'

'

-1,433,075

-1,075,354

-822,602

Changes in estimated future development costs

'

'

'

'

'

'

'

'

317,064

289,762

27,236

Net change in sales and transfer prices and production costs related to future production

'

'

'

'

'

'

'

'

203,370

-1,463,820

784,308

Purchase of minerals in place

'

'

'

'

'

'

'

'

5,113,335

2,153,651

1,452,169

Extensions, discoveries, and improved recovery

'

'

'

'

'

'

'

'

801,254

413,702

552,704

Previously estimated development costs incurred during the period

'

'

'

'

'

'

'

'

444,861

442,322

306,827

Net change due to revisions in quantity estimates

'

'

'

'

'

'

'

'

-220,224

-1,595,302

-292,343

Accretion of discount

'

'

'

'

'

'

'

'

607,298

661,486

422,353

Changes in production rates and other

'

'

'

'

'

'

'

'

131,849

-368,326

-39,324

Change in the standardized measure of discounted future net cash flows

'

'

'

'

'

'

'

'

$5,826,348

($541,879)

$2,391,328

Natural Gas [Member]

'

'

'

'

'

'

'

'

'

'

'

Proved developed and undeveloped reserves [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

2,571,000,000

'

'

'

1,675,000,000

2,571,000,000

1,675,000,000

1,233,000,000

Revisions of previous estimates

'

'

'

'

'

'

'

'

-17,000,000

-559,000,000

-71,000,000

Purchase of minerals in place

'

'

'

'

'

'

'

'

356,000,000

1,176,000,000

337,000,000

Sales of minerals in place

'

'

'

'

'

'

'

'

-24,000,000

'

'

Extensions, discoveries and other additions

'

'

'

'

'

'

'

'

286,000,000

407,000,000

240,000,000

Production

'

'

'

'

'

'

'

'

-162,000,000

-128,000,000

-64,000,000

End of year

3,010,000,000

'

'

'

2,571,000,000

'

'

'

3,010,000,000

2,571,000,000

1,675,000,000

Proved developed reserves [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

1,661,000,000

'

'

'

998,000,000

1,661,000,000

998,000,000

805,000,000

End of year

2,027,000,000

'

'

'

1,661,000,000

'

'

'

2,027,000,000

1,661,000,000

998,000,000

Proved undeveloped reserves [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

910,000,000

'

'

'

677,000,000

910,000,000

677,000,000

428,000,000

End of year

983,000,000

'

'

'

910,000,000

'

'

'

983,000,000

910,000,000

677,000,000

Oil [Member]

'

'

'

'

'

'

'

'

'

'

'

Proved developed and undeveloped reserves [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

191.5

'

'

'

189

191.5

189

156.4

Revisions of previous estimates

'

'

'

'

'

'

'

'

-21.3

-26.5

-9.2

Purchase of minerals in place

'

'

'

'

'

'

'

'

191.1

23.1

39.3

Sales of minerals in place

'

'

'

'

'

'

'

'

-5.2

'

'

Extensions, discoveries and other additions

'

'

'

'

'

'

'

'

21.7

16.6

10.3

Production

'

'

'

'

'

'

'

'

-12.2

-10.7

-7.8

End of year

365.6

'

'

'

191.5

'

'

'

365.6

191.5

189

Proved developed reserves [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

131.4

'

'

'

124.8

131.4

124.8

103

End of year

252.4

'

'

'

131.4

'

'

'

252.4

131.4

124.8

Proved undeveloped reserves [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

60.1

'

'

'

64.2

60.1

64.2

53.4

End of year

113.2

'

'

'

60.1

'

'

'

113.2

60.1

64.2

NGL [Member]

'

'

'

'

'

'

'

'

'

'

'

Proved developed and undeveloped reserves [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

179.4

'

'

'

93.5

179.4

93.5

70.9

Revisions of previous estimates

'

'

'

'

'

'

'

'

-2

-14.1

0.9

Purchase of minerals in place

'

'

'

'

'

'

'

'

17.8

75.3

1

Sales of minerals in place

'

'

'

'

'

'

'

'

-2.9

'

'

Extensions, discoveries and other additions

'

'

'

'

'

'

'

'

18.5

33.7

24.6

Production

'

'

'

'

'

'

'

'

-10.8

-9

-3.9

End of year

200

'

'

'

179.4

'

'

'

200

179.4

93.5

Proved developed reserves [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

113

'

'

'

47.8

113

47.8

39.9

End of year

133.2

'

'

'

113

'

'

'

133.2

113

47.8

Proved undeveloped reserves [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Beginning of year

'

'

'

66.4

'

'

'

45.7

66.4

45.7

31

End of year

66.8

'

'

'

66.4

'

'

'

66.8

66.4

45.7

[1]

See NoteB 2 for details about the Companybs acquisitions.

[2]

Includes the results of operations of the Berry Acquisition since the acquisition date (see NoteB 2).

[3]

In accordance with SEC regulations, reserves at DecemberB 31, 2013, DecemberB 31, 2012, and DecemberB 31, 2011, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.

Quarterly_Financial_Data_Detai

Quarterly Financial Data (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Data [Abstract]	'		'		'		'		'		'		'		'		'	'	'
Oil, natural gas and natural gas liquids sales	$584,630	[1]	$537,671		$488,207		$462,732		$460,976		$444,082		$347,227		$348,895		$2,073,240	$1,601,180	$1,162,037
Gains (losses) on oil and natural gas derivatives	23,425	[1]	-63,931		326,733		-108,370		94,489		-411,405		439,647		2,031		177,857	124,762	449,940
Total revenues and other	629,208	[1]	494,562		838,825		369,060		571,225		48,328		800,597		354,090		2,331,655	1,774,240	1,622,454
Total expenses	1,292,058	[1],[2]	420,803	[2]	385,540	[2]	478,235	[2]	656,221	[2]	376,323	[2]	460,655	[2]	269,092	[2]	2,590,273	1,763,830	816,420
(Gain) losses on sale of assets and other, net	10,597	[1]	827		-959		3,172		31		16		-2		1,494		-13,637	-1,539	-3,494
Net income (loss)	($784,549)	[1]	($30,060)		$345,157		($221,885)		($187,495)		($430,005)		$237,086		($6,202)		($691,337)	($386,616)	$438,439
Net income (loss) per unit:	'		'		'		'		'		'		'		'		'	'	'
Basic (in usd per unit)	($3.15)	[1]	($0.13)		$1.47		($0.96)		($0.83)		($2.18)		$1.19		($0.04)		($2.94)	($1.92)	$2.52
Diluted (in usd per unit)	($3.15)	[1]	($0.13)		$1.46		($0.96)		($0.83)		($2.18)		$1.19		($0.04)		($2.94)	($1.92)	$2.51
[1]	Includes the results of operations of the Berry Acquisition since the acquisition date (see NoteB 2).
[2]	Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.