Pressburg (ROAN) 10-K 19 Feb 15 2014 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2014	Jan. 31, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Entity Registrant Name	Linn Energy, LLC
Entity Central Index Key	1326428
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$6.50
Entity Common Stock, Shares Outstanding		335,562,043
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$1,809	$52,171
Accounts receivable – trade, net	471,684	488,202
Derivative instruments	1,077,142	176,130
Other current assets	155,955	99,437
Total current assets	1,706,590	815,940
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	18,068,900	17,888,559
Less accumulated depletion and amortization	-4,867,682	-3,546,284
Oil and natural gas properties, successful efforts method, net	13,201,218	14,342,275
Other property and equipment	669,149	647,882
Less accumulated depreciation	-144,282	-110,939
Other property and equipment, net	524,867	536,943
Derivative instruments	848,097	682,002
Other noncurrent assets	142,737	127,804
Noncurrent assets, excluding property, total	990,834	809,806
Total noncurrent assets	14,716,919	15,689,024
Total assets	16,423,509	16,504,964
Current liabilities:
Accounts payable and accrued expenses	814,809	849,624
Derivative instruments	0	28,176
Other accrued liabilities	167,736	163,375
Current portion of long-term debt	0	211,558
Total current liabilities	982,545	1,252,733
Noncurrent liabilities:
Credit facilities	2,968,175	2,733,175
Term loan	500,000	500,000
Senior notes, net	6,827,634	5,725,483
Derivative instruments	684	4,649
Other noncurrent liabilities	600,866	397,497
Total noncurrent liabilities	10,897,359	9,360,804
Commitments and contingencies (Note 11)
Unitholders’ capital:
331,974,913 units and 329,661,161 units issued and outstanding at December 31, 2014, and December 31, 2013, respectively	5,395,811	6,291,824
Accumulated deficit	-852,206	-400,397
Total unitholders' capital	4,543,605	5,891,427
Total liabilities and unitholders’ capital	$16,423,509	$16,504,964

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical)	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Unitholder's capital: Units issued	331,974,913	329,661,161
Unitholders' capital: Units outstanding	331,974,913	329,661,161

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues and other:
Oil, natural gas and natural gas liquids sales	$3,610,539	$2,073,240	$1,601,180
Gains on oil and natural gas derivatives	1,206,179	177,857	124,762
Marketing revenues	135,260	54,171	37,393
Other revenues	31,325	26,387	10,905
Total revenues	4,983,303	2,331,655	1,774,240
Expenses:
Lease operating expenses	805,164	372,523	317,699
Transportation expenses	207,331	128,440	77,322
Marketing expenses	117,465	37,892	31,821
General and administrative expenses	293,073	236,271	173,206
Exploration costs	125,037	5,251	1,915
Depreciation, depletion and amortization	1,073,902	829,311	606,150
Impairment of long-lived assets	2,303,749	828,317	422,499
Taxes, other than income taxes	267,403	138,631	131,679
(Gains) losses on sale of assets and other, net	-366,500	13,637	1,539
Total expenses	4,826,624	2,590,273	1,763,830
Other income and (expenses):
Interest expense, net of amounts capitalized	-587,838	-421,137	-379,937
Loss on extinguishment of debt	0	-5,304	0
Other, net	-16,213	-8,477	-14,299
Total other income and (expenses)	-604,051	-434,918	-394,236
Loss before income taxes	-447,372	-693,536	-383,826
Income tax expense (benefit)	4,437	-2,199	2,790
Net loss	($451,809)	($691,337)	($386,616)
Net loss per unit:
Basic (in usd per unit)	($1.40)	($2.94)	($1.92)
Diluted (in usd per unit)	($1.40)	($2.94)	($1.92)
Weighted average units outstanding:
Basic (in units)	328,918	237,544	203,775
Diluted (in units)	328,918	237,544	203,775
Distributions declared per unit (in usd per unit)	$2.90	$2.90	$2.87

CONSOLIDATED_STATEMENT_OF_UNIT

CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (USD $)	3 Months Ended				12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Sale of units, net of underwriting discounts and expenses of $32,044							$1,942,045
Balance Beginning		5,891,427		4,427,180	5,891,427	4,427,180	3,428,910
Issuance of units					13,354	2,783,907	7,061
Distributions to unitholders					-962,048	-682,241	-596,935
Unit-based compensation expenses					53,284	42,703	29,533
Reclassification of distributions paid on forfeited restricted units					602	176	92
Excess tax benefit from unit-based compensation and other					347	160	3,090
Deferred tax on capital contribution					-1,552	10,879
Net loss	-154,502	-85,337	-784,549	-221,885	-451,809	-691,337	-386,616
Balance Ending	4,543,605		5,891,427		4,543,605	5,891,427	4,427,180
Accumulated Income [Member]
Sale of units, net of underwriting discounts and expenses of $32,044							0
Balance Beginning		-400,397		290,940	-400,397	290,940	677,556
Issuance of units					0	0	0
Distributions to unitholders					0	0	0
Unit-based compensation expenses					0	0	0
Reclassification of distributions paid on forfeited restricted units					0	0	0
Excess tax benefit from unit-based compensation and other					0	0	0
Deferred tax on capital contribution					0	0
Net loss					-451,809	-691,337	-386,616
Balance Ending	-852,206		-400,397		-852,206	-400,397	290,940
Member Units [Member]
Sale of units, net of underwriting discounts and expenses (in units)							55,877
Common Units, Outstanding (in units)		329,661		234,513	329,661	234,513	177,365
Issuance of units (in units)					2,314	95,148	1,271
Common Units, Outstanding (in units)	331,975		329,661		331,975	329,661	234,513
Common Stock Including Additional Paid in Capital [Member]
Sale of units, net of underwriting discounts and expenses of $32,044							1,942,045
Balance Beginning		6,291,824		4,136,240	6,291,824	4,136,240	2,751,354
Issuance of units					13,354	2,783,907	7,061
Distributions to unitholders					-962,048	-682,241	-596,935
Unit-based compensation expenses					53,284	42,703	29,533
Reclassification of distributions paid on forfeited restricted units					602	176	92
Excess tax benefit from unit-based compensation and other					347	160	3,090
Deferred tax on capital contribution					-1,552	10,879
Net loss					0	0	0
Balance Ending	$5,395,811		$6,291,824		$5,395,811	$6,291,824	$4,136,240

CONSOLIDATED_STATEMENT_OF_UNIT1

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

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flow from operating activities:
Net loss	($451,809)	($691,337)	($386,616)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	1,073,902	829,311	606,150
Impairment of long-lived assets	2,303,749	828,317	422,499
Unit-based compensation expenses	53,284	42,703	29,533
Loss on extinguishment of debt	0	5,304	0
Amortization and write-off of deferred financing fees	50,926	21,507	25,598
(Gains) losses on sale of assets and other, net	-261,571	37,232	92
Deferred income taxes	3,943	-2,541	-360
Derivatives activities:
Total gains	-1,206,179	-177,857	-124,762
Cash settlements	95,514	248,862	390,765
Cash settlements on canceled derivatives	12,281	0	0
Premiums paid for derivatives	0	0	-583,434
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	5,064	89,188	-77,573
(Increase) decrease in other assets	-17,824	16,179	-5,451
Increase (decrease) in accounts payable and accrued expenses	99,029	-76,993	26,372
Increase (decrease) in other liabilities	-48,419	-3,663	28,094
Net cash provided by operating activities	1,711,890	1,166,212	350,907
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	-2,479,252	-279,213	-2,640,475
Development of oil and natural gas properties	-1,569,877	-1,078,025	-984,530
Purchases of other property and equipment	-74,540	-92,352	-60,549
Proceeds from sale of properties and equipment and other	2,203,565	196,273	725
Net cash used in investing activities	-1,920,104	-1,253,317	-3,684,829
Cash flow from financing activities:
Proceeds from sale of units	0	0	1,973,989
Proceeds from borrowings	5,940,024	2,230,000	5,439,802
Repayments of debt	-4,811,124	-1,404,898	-3,400,000
Distributions to unitholders	-962,048	-682,241	-596,935
Financing fees and offering expenses	69,694	16,033	73,320
Excess tax benefit from unit-based compensation	766	160	3,090
Other	59,928	11,045	-12,575
Net cash provided by financing activities	157,852	138,033	3,334,051
Net increase (decrease) in cash and cash equivalents	-50,362	50,928	129
Cash and cash equivalents:
Beginning	52,171	1,243	1,114
Ending	$1,809	$52,171	$1,243

Basis_of_Presentation_and_Sign

Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Significant Accounting Policies	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 eight operating regions in the United States (“U.S.”): Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin), North Dakota (Williston Basin) and Colorado (Piceance Basin); Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; California, which includes properties located in the San Joaquin Valley and Los Angeles basins; TexLa, which includes properties located in east Texas and north Louisiana; Mid-Continent, which includes properties located in the Anadarko and Arkoma basins in Oklahoma, as well as waterfloods in the Central Oklahoma Platform; Permian Basin, which includes properties located in west Texas and southeast New Mexico; Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; and South 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, as amended (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 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. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
	Recently Issued Accounting Standards
	In May 2014, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU will be applied either retrospectively or as a cumulative-effect adjustment as of the date of adoption and is effective for fiscal years beginning after December 15, 2016, and interim periods within those years (early adoption prohibited). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.
	In April 2014, the FASB issued an ASU that changes the criteria for reporting discontinued operations and enhances disclosures in this area. This ASU is effective for annual and interim periods beginning after December 15, 2014, with early adoption permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Company early adopted this ASU on a prospective basis beginning with the third quarter of 2014. The adoption had no effect on the Company’s consolidated financial statements.
	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 both December 31, 2014, and December 31, 2013.
	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 of proved and risk-adjusted probable and possible reserves 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 $9 million for the year ended December 31, 2014, and $2 million for each of the years ended December 31, 2013, and December 31, 2012.
	Impairment of Proved Properties
	Based on the analysis described above, for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company recorded noncash impairment charges, before and after tax, of approximately $2.3 billion, $791 million and $422 million, respectively, associated with proved oil and natural gas properties. 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 impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
	During the fourth quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $1.7 billion associated with proved oil and natural gas properties throughout its various operating regions. The impairment was due to a steep decline in commodity prices. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas forward price curves decreased approximately 24% and 12%, respectively. Following are the impairment charges recorded by operating region:
	•	Permian Basin – $735 million;
	•	Rockies – $586 million (in the Powder River Basin and Uinta Basin);
	•	Mid-Continent – $244 million;
	•	South Texas – $131 million; and
	•	TexLa – $5 million.
	In addition, during the third quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $603 million associated with proved oil and natural gas properties in the Permian Basin region. The impairment was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for the proved oil and natural gas properties.
	During 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. During the year ended December 31, 2012, the Company recorded noncash impairment charges, 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.
	Subsequent to December 31, 2014, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results 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. 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 $125 million, $5 million and $2 million for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively, 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 two 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. Imbalance receivables and payables are valued at the lower of the price in effect at the time of production, the current market value or, if a contract is in hand, the contract price. At December 31, 2014, and December 31, 2013, the Company had natural gas production imbalance receivables of approximately $17 million and $27 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $13 million and $16 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 revenues 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. The revenue from this activity is included in “other revenues” on the consolidated statements of operations.
	Restricted Cash
	Restricted cash of approximately $6 million is included in “other noncurrent assets” on the consolidated balance sheets at both December 31, 2014, and December 31, 2013, 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 net cash provided by operating activities due to fluctuations in commodity prices.
	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. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date. Also, 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, 2014, the Company had no outstanding derivative contracts in the form of interest rate swaps.
	In addition, as part of the 2013 acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”) (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 and other” 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, 2014, and December 31, 2013, net deferred financing fees of approximately $129 million and $114 million, respectively, 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, 2014, December 31, 2013, and December 31, 2012, amortization expense of approximately $46 million, $18 million and $13 million, respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations. For the year ended December 31, 2014, approximately $8 million were written off to expense and included in “other, net” on the consolidated statement of operations related to the VIE Term Loan (as defined in Note 6) and amendments to the Credit Facilities (as defined in Note 6). For the year ended December 31, 2012, approximately $8 million were written off to expense and included in “other, net” on the consolidated statement of operations related to amendments of the LINN Credit Facility (as defined in Note 6). No fees related to amendments of the Credit Facilities were written off 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, 2014, and December 31, 2013. 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. 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.

Exchanges_of_Properties_Acquis

Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding	Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding
	Exchanges of Properties – 2014
	On November 21, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation in exchange for properties in California’s South Belridge Field. The noncash exchange was accounted for at fair value and the Company recognized a net gain of approximately $20 million, including costs to sell of approximately $3 million. The gain is equal to the difference between the carrying value and the fair value of the assets exchanged less costs to sell, and is included in “(gains) losses on sale of assets and other, net” on the consolidated statement of operations. The fair value measurements were based on inputs that are not observable and therefore represent Level 3 inputs under the fair value hierarchy.
	On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., in exchange for properties in the Hugoton Basin. The noncash exchange was accounted for at fair value and the Company recognized a net gain of approximately $65 million, including costs to sell of approximately $3 million. The gain is equal to the difference between the carrying value and the fair value of the assets exchanged less costs to sell, and is included in “(gains) losses on sale of assets and other, net” on the consolidated statement of operations. The fair value measurements were based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy.
	Acquisitions – 2014
	On September 11, 2014, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin from Pioneer Natural Resources Company (“Pioneer” and the acquisition, the “Pioneer Assets Acquisition”) for total consideration of approximately $328 million.
	On August 29, 2014, the Company completed the acquisition of certain oil and natural gas properties located in five operating regions in the U.S. from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) for total consideration of approximately $2.1 billion.
	The Pioneer Assets Acquisition was initially financed with borrowings under the LINN Credit Facility, and the Devon Assets Acquisition was initially financed with proceeds from the Bridge Loan and borrowings under the VIE Term Loan (see Note 6). The Company used the net proceeds from the sales of its Granite Wash properties as well as certain of its Wolfberry properties (see below) to repay the VIE Term Loan in full as well as repay a portion of the borrowings outstanding under the LINN Credit Facility.
	The Pioneer Assets Acquisition and the Devon Assets Acquisition were structured as reverse like-kind exchanges pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchanges”). In connection with the Reverse 1031 Exchanges, the Company, through a subsidiary, assigned the rights to acquire legal title to the oil and natural gas properties from Pioneer and Devon to a variable interest entity (“VIE”) formed by an exchange accommodation titleholder. A subsidiary of LINN Energy operated the properties pursuant to management agreements with the VIE. Because the Company was the primary beneficiary of the VIE, the VIE was included in the consolidated financial statements from the time of its formation.
	The assets acquired by the VIE in the Pioneer Assets Acquisition and the Devon Assets Acquisition were conveyed to LINN Energy and its subsidiaries, and the VIE structure was terminated, upon the completion of the Reverse 1031 Exchanges (which occurred in December 2014 and included the Granite Wash Assets Sale and the Permian Basin Assets Sale, each as defined below).
	During the year ended December 31, 2014, 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 $5 million in total consideration for these properties.
	These acquisitions were 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 dates, 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.
	The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):
	Assets:
	Current	$	26,007
	Oil and natural gas properties	2,532,439
	Other property and equipment	121,101
	Total assets acquired	2,679,547
	Liabilities:
	Current	21,976
	Asset retirement obligations, current and noncurrent	171,057
	Noncurrent	18,380
	Total liabilities assumed	211,413
	Net assets acquired	$	2,468,134
	Current assets include receivables and inventory. Current liabilities include payables and environmental liabilities. Noncurrent liabilities include out-of-market contracts.
	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 under the fair value hierarchy. 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, 2014, and December 31, 2013, assuming the Devon Assets Acquisition and the 2013 acquisition of Berry (see below) had been completed as of January 1, 2013, 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,
			2014			2013
			(in thousands, except
			per unit amounts)
	Total revenues and other		$	5,335,442		$	3,973,605
	Total operating expenses		$	5,039,311		$	3,711,868
	Net loss		$	(403,447	)	$	(397,070	)
	Net loss per unit:
	Basic		$	(1.25	)	$	(1.22	)
	Diluted		$	(1.25	)	$	(1.22	)
	The pro forma condensed combined statements of operations include adjustments to:
	•	Reflect the results of the Devon Assets Acquisition and the Berry acquisition for all periods presented.
	•	Reflect incremental depreciation, depletion and amortization expense, using the unit-of-production method related to oil and natural gas properties acquired and an estimated useful life of 10 years and 20 years for other property and equipment acquired in the Devon Assets Acquisition and the Berry acquisition, respectively.
	•	Reflect incremental accretion expense related to asset retirement obligations on oil and natural gas properties acquired in the Devon Assets Acquisition.
	•	Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price of the Devon Assets Acquisition and a reduction in interest expense related to the amortization of the adjustment to fair value of Berry’s debt using the effective interest method.
	•	Reflect incremental amortization of deferred financing fees associated with debt incurred to fund the purchase price of the Devon Assets Acquisition.
	•	Exclude transaction costs related to the Devon Assets Acquisition and the Berry acquisition included in the historical statements of operations as they reflect nonrecurring charges not expected to have a continuing impact on the combined results.
	•	Reflect approximately 93.8 million LINN Energy units assumed to be issued on January 1, 2013, in conjunction with the Berry acquisition.
	Divestitures – 2014
	On December 15, 2014, the Company completed the sale of its entire position in the Granite Wash and Cleveland plays located in the Texas Panhandle and western Oklahoma to privately held institutional affiliates of EnerVest, Ltd. and its joint venture partner FourPoint Energy, LLC (the “Granite Wash Assets Sale”). Cash proceeds received from the sale of these properties were approximately $1.8 billion, net of costs to sell of approximately $10 million, and the Company recognized a net gain of approximately $294 million.
	On November 14, 2014, the Company completed the sale of certain of its Wolfberry properties in Ector and Midland counties in the Permian Basin to Fleur de Lis Energy, LLC (the “Permian Basin Assets Sale”). Cash proceeds received from the sale of these properties were approximately $351 million, net of costs to sell of approximately $2 million, and the Company recognized a net loss of approximately $28 million.
	On October 30, 2014, the Company completed the sale of its interests in certain non-producing oil and natural gas properties located in the Mid-Continent region. Cash proceeds received from the sale of these properties were approximately $44 million, and the Company recognized a net gain of approximately $36 million.
	The gains and losses on divestitures are included in “(gains) losses on sales of assets and other, net” on the consolidated statement of operations.
	The Company used the net cash proceeds received from these sales to repay in full the VIE Term Loan, as defined below, as well as repay a portion of the borrowings outstanding under the LINN Credit Facility, also defined below.
	Joint-Venture Funding
	For the year ended December 31, 2014, the Company paid approximately $25 million, including interest, to fund the commitment related to the joint-venture agreement it entered into with an affiliate of Anadarko in April 2012. For the years ended December 31, 2013, and December 31, 2012, the Company paid approximately $173 million and $202 million, respectively, to fund the commitment. As of February 2014, the Company had fully funded the total commitment of $400 million.
	Berry Acquisition – 2013
	On December 16, 2013, the Company completed the 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 was valued at 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.
	Other Acquisitions – 2013 and 2012
	The following is a summary of significant acquisitions completed by the Company during the years ended December 31, 2013, and December 31, 2012:
	•	On October 31, 2013, the Company completed the acquisition of certain oil and natural gas properties located in the Permian Basin for approximately $528 million.
	•	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 Petroleum Corporation (“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.
	Divestiture – 2013
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. Cash proceeds received from the sale of these 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.

Unitholders_Capital

Unitholders' Capital	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Unitholders' Capital	Unitholders’ Capital
	Berry Acquisition
	On December 16, 2013, the Company completed the 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 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 these units to LinnCo to pay the expenses of the offering and repay a portion of the borrowings outstanding 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 borrowings outstanding under the LINN Credit Facility.
	At-the-Market Offering Program
	In January 2012, the Company, under an equity distribution agreement pursuant to which it may from time to time issue and sell units representing limited liability company interests, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for net proceeds of approximately $57 million (net of approximately $1 million in commissions). In connection with the issuance 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 borrowings outstanding under the LINN Credit Facility.
	In August 2014, the Board of Directors increased the authority under the existing at-the-market offering program to $500 million, and as of December 31, 2014, no units had been sold under the increased authority. 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.
	Unit Repurchase Plan
	In August 2014, the Board of Directors of the Company authorized the repurchase of up to $250 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. 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. The Company did not repurchase any units during the years ended December 31, 2014, December 31, 2013, and December 31, 2012, and as of December 31, 2014, the entire amount remained available for unit repurchase under the program.
	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, 2015, the Company’s Board of Directors declared a cash distribution of $0.3125 per unit with respect to the fourth quarter of 2014, to be paid in three equal monthly installments of $0.1042 per unit. The current distribution represents an approximate 57% decrease from the distribution of $0.725 paid for the previous quarter. The first monthly distribution, totaling approximately $35 million, was paid on January 15, 2015, to unitholders of record as of the close of business on January 12, 2015, and the second monthly distribution, totaling approximately $35 million, was paid on February 17, 2015, to unitholders of record as of the close of business on February 10, 2015.

Business_and_Credit_Concentrat

Business and Credit Concentrations	12 Months Ended
	Dec. 31, 2014
Risks and Uncertainties [Abstract]
Business and Credit Concentrations	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, 2014, the Company’s largest customer represented approximately 14% of the Company’s sales. 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.
	At December 31, 2014, trade accounts receivable from one customer represented approximately 11% of the Company’s receivables. At December 31, 2013, trade accounts receivable from two customers represented approximately 19% and 14%, respectively, of the Company’s receivables.

UnitBased_Compensation_and_Oth

Unit-Based Compensation and Other Benefit Plans	12 Months Ended
	Dec. 31, 2014
Unit Based Compensation and Other Benefit Plans [Abstract]
Unit-Based Compensation and Other Benefit Plans	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. Performance units granted in January 2015 vest 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 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, 2014, approximately 8.3 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 4.7 million additional units were reserved for future issuance under the Plan.
	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,
			2014			2013			2012
			(in thousands)
	General and administrative expenses		$	45,195		$	37,375		$	27,641
	Lease operating expenses		8,089			5,328			1,892
	Total unit-based compensation expenses		$	53,284		$	42,703		$	29,533
	Income tax benefit		$	19,688		$	15,779		$	10,912
	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, 2014, is presented below:
			Number of		Weighted Average
			Nonvested		Grant-Date
			Units		Fair Value
	Nonvested units at December 31, 2013		2,571,410		$	33.14
	Granted		1,789,038		$	33.1
	Vested		(1,282,509	)	$	32.77
	Forfeited		(238,966	)	$	32.25
	Nonvested units at December 31, 2014		2,838,973		$	32.7
	The weighted average grant-date fair value of restricted units, phantom units and unrestricted units granted was $30.71 and $37.42 during the years ended December 31, 2013, and December 31, 2012, respectively. The total fair value of units that vested was approximately $42 million, $31 million and $24 million for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. As of December 31, 2014, 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 2015, the Company granted 3,468,245 restricted units and 697,120 phantom units as part of its annual review of its employees’, including executives, compensation. The Company also granted 283,660 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, 2014:
			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, 2013		6,433,223		$	30.22		6.66		$	33
	Exercised		(813,806	)	$	16.56
	Forfeited or expired		(175,000	)	$	40.01
	Outstanding at December 31, 2014		5,444,417		$	31.95		5.12		$	—
	Exercisable at December 31, 2014		2,510,457		$	22.57		5.5		$	—
	No unit options were granted during the year ended December 31, 2014. 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. The total intrinsic value of unit options exercised was approximately $11 million, $2 million and $3 million, during the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. The Company received approximately $13 million from the exercise of unit options during the year ended December 31, 2014. As of December 31, 2014, total unrecognized compensation cost related to nonvested unit options was approximately $4 million. The cost is expected to be recognized over a weighted average period of approximately 1.1 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.
	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 RSUs 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 RSUs) 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 is recognized as compensation expense over the vesting period.
	Nonemployee Grants
	At December 31, 2014, 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 $10 million, $7 million and $5 million during the years ended December 31, 2014, December 31, 2013, and December 31, 2012, 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, 2014
Debt Disclosure [Abstract]
Debt	Debt
	The following summarizes the Company’s outstanding debt:
			December 31,
			2014			2013
			(in thousands, except percentages)
	LINN credit facility (1)		$	1,795,000		$	1,560,000
	Berry credit facility (2)		1,173,175			1,173,175
	Term loan (3)		500,000			500,000
	10.25% Berry senior notes due June 2014		—			205,257
	6.50% senior notes due May 2019 (4)		1,200,000			750,000
	6.25% senior notes due November 2019		1,800,000			1,800,000
	8.625% senior notes due April 2020		1,300,000			1,300,000
	6.75% Berry senior notes due November 2020		299,970			300,000
	7.75% senior notes due February 2021		1,000,000			1,000,000
	6.50% senior notes due September 2021 (4)		650,000			—
	6.375% Berry senior notes due September 2022		599,163			600,000
	Net unamortized discounts and premiums		(21,499		)	(18,216		)
	Total debt, net		10,295,809			9,170,216
	Less current maturities		—			(211,558		)
	Total long-term debt, net		$	10,295,809		$	8,958,658
	(1)	Variable interest rate of 1.92% at both December 31, 2014, and December 31, 2013.
	(2)	Variable interest rate of 2.67% at both December 31, 2014, and December 31, 2013.
	(3)	Variable interest rates of 2.66% and 2.67% at December 31, 2014 and December 31, 2013, respectively.
	(4)	$450 million of senior notes due May 2019 and $650 million of senior notes due September 2021 were issued on September 9, 2014.
	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, 2014						December 31, 2013
			Carrying			Fair Value			Carrying		Fair Value
			Value						Value
			(in thousands)
	Credit facilities		$	2,968,175		$	2,968,175		$	2,733,175	$	2,733,175
	Term loan		500,000			500,000			500,000		500,000
	Senior notes, net		6,827,634			5,703,649			5,937,041		6,162,402
	Total debt, net		$	10,295,809		$	9,171,824		$	9,170,216	$	9,395,577
	Credit Facilities
	LINN Credit Facility
	The Company’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) provides for (1) a senior secured revolving credit facility and (2) a $500 million senior secured term loan, in aggregate subject to the then-effective borrowing base. Borrowing capacity under the revolving credit facility is limited to the lesser of (i) the then-effective borrowing base reduced by the $500 million term loan and (ii) the maximum commitment amount of $4.0 billion, and is currently $4.0 billion. At December 31, 2014, the borrowing base under the LINN Credit Facility was $4.5 billion and availability under the revolving credit facility was approximately $2.2 billion, which includes a $5 million reduction for outstanding letters of credit.
	In April 2014, the Company entered into an amendment to the LINN Credit Facility to extend the maturity date from April 2018 to April 2019, among other items. In August 2014 and September 2014, the Company entered into amendments to the LINN Credit Facility to permit the Devon Assets Acquisition and the Pioneer Assets Acquisition, respectively, and the related Reverse 1031 Exchanges (see Note 2). As a result of the debt incurred under the Bridge Loan, as defined below, the borrowing base was reduced by 25% of the gross proceeds from the Bridge Loan, or $250 million, from $4.5 billion to $4.25 billion, resulting in a reduction of availability under the revolving credit facility of $250 million. Additionally, upon the issuance of an aggregate $1.1 billion of senior notes in the September 2014 offering (see below), the borrowing base was further reduced by $25 million to $4.225 billion, resulting in a further reduction of availability under the revolving credit facility of $25 million. The fall 2014 semi-annual redetermination occurred in December 2014 in order to coincide with the completion of the Reverse 1031 Exchanges, and as part of that redetermination, the borrowing base was restored to $4.5 billion with a maximum commitment amount of $4.0 billion.
	Redetermination of the borrowing base under the LINN Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. The administrative agent, at the direction of a super majority 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 its 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.
	The $500 million term loan has a maturity date of April 2019 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 its 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.
	Berry Credit Facility
	Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) has a borrowing base of $1.4 billion, subject to lender commitments. At December 31, 2014, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit. In February 2014, Berry entered into an amendment to the Berry Credit Facility to amend the terms of certain financial and reporting covenants, among other items. In April 2014, Berry entered into an amendment to the Berry Credit Facility to extend the maturity date from May 2016 to April 2019 and to amend the terms of certain financial covenants and definitions, among other items.
	Redetermination of the borrowing base under the Berry Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. A super-majority of the lenders under the Berry Credit Facility and Berry also have the right to request interim borrowing base redeterminations once between scheduled redeterminations. 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 in compliance with all financial and other covenants of the Berry Credit Facility.
	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.”
	Bridge Loan
	On August 29, 2014, the Company entered into a bridge loan agreement (the “Bridge Loan”) pursuant to which the Company borrowed an aggregate principal amount of $1.0 billion of term loans. The proceeds from the Bridge Loan were advanced to the VIE and used to partially fund the Devon Assets Acquisition (see Note 2). The Bridge Loan agreement was unsecured and was guaranteed by all of the Company’s material domestic subsidiaries which guarantee the LINN Credit Facility.
	The Bridge Loan had an initial maturity date of August 29, 2015, with interest on the initial term loans determined by reference to either (i) LIBOR plus 5.0% plus an applicable margin per annum or (ii) alternate base rate plus 4.0% plus an applicable margin per annum. The applicable margin would have been 0% for the first three months after the funding date and, thereafter, increased by 0.50% at the end of each subsequent three-month period.
	On September 9, 2014, the Company paid in full the outstanding indebtedness under the Bridge Loan using proceeds from the issuance of the New May 2019 Senior Notes and the September 2021 Senior Notes, each as defined below.
	VIE Term Loan
	On August 29, 2014, a subsidiary of the VIE, formed to facilitate the Reverse 1031 Exchange for the Devon Assets Acquisition (see Note 2) entered into a 364-day term loan agreement (the “VIE Term Loan”) pursuant to which it borrowed an aggregate principal amount of $1.3 billion of term loans. The proceeds from the VIE Term Loan were used to partially fund the Devon Assets Acquisition. The obligations under the VIE Term Loan were required to be secured by certain of the oil and natural gas properties and personal property of the VIE’s subsidiary and its material subsidiaries (if any), as well as a pledge of 100% of the equity interests in the subsidiary. Specifically, the VIE’s subsidiary was required to maintain mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report. Additionally, the obligations under the VIE Term Loan were to be guaranteed by all of the material subsidiaries of the VIE’s subsidiary (if any).
	In December 2014, the outstanding indebtedness under the VIE Term Loan was paid in full using a portion of the net cash proceeds received from the Granite Wash Assets Sale and the Permian Basin Assets Sale (see Note 2).
	Senior Notes Due May 2019 and Senior Notes Due September 2021
	On September 9, 2014, the Company issued $1.1 billion in aggregate principal amount of senior notes consisting of $450 million aggregate principal amount of 6.50% senior notes due May 2019 (the “New May 2019 Senior Notes”) at a price of 102% of par and $650 million in aggregate principal amount of 6.50% senior notes due September 2021 (the “September 2021 Senior Notes”) at a price of 98.619% of par. The New May 2019 Senior Notes and the September 2021 Senior Notes were registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to a shelf registration statement on Form S-3 filed on September 4, 2014, which was automatically effective upon filing. The Company received net proceeds of approximately $450 million from the issuance of the New May 2019 Senior Notes (after adding the premium of $9 million and deducting offering expenses of approximately $9 million) and approximately $628 million from the issuance of the September 2021 Senior Notes (after deducting the discount of approximately $9 million and offering expenses of approximately $13 million). The Company used the net proceeds from the New May 2019 Senior Notes and the September 2021 Senior Notes to repay all indebtedness outstanding under the Company’s Bridge Loan (see above) as well as repay a portion of the borrowings outstanding under the LINN Credit Facility. The financing fees and expenses of approximately $22 million incurred in connection with the New May 2019 Senior Notes and the September 2021 Senior Notes will be amortized over the life of the notes. Such amortized expenses, premium and discount are recorded in “interest expense, net of amounts capitalized” on the consolidated statements of operations.
	The New May 2019 Senior Notes were issued as additional notes to the original $750 million in aggregate principal amount issued under an indenture (the “May 2019 Indenture”), dated as of May 13, 2011, mature May 15, 2019, and bear interest at 6.50%. Interest is payable in cash semi-annually in arrears on each May 15 and November 15. Interest will be payable to holders of record on the May 1 and November 1 immediately preceding the related interest payment date, and will be computed on the basis of a 360-day year consisting of twelve 30-day months. The May 2019 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries, other than Berry, has guaranteed the May 2019 Senior Notes on a senior unsecured basis. The May 2019 Indenture provides that the Company may redeem: (i) prior to May 15, 2015, all or part of the May 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the May 2019 Indenture) and accrued and unpaid interest; and (ii) on or after May 15, 2015, all or part of the May 2019 Senior Notes at a redemption price equal to 103.250%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The May 2019 Indenture also provides that, if a change of control (as defined in the May 2019 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the May 2019 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.
	The September 2021 Senior Notes were issued under an indenture dated September 9, 2014 (the “September 2021 Indenture”), mature September 15, 2021, and bear interest at 6.50%. Interest is payable in cash semi-annually in arrears on each March 15 and September 15, commencing March 15, 2015. Interest will be payable to holders of record on the March 1 and September 1 immediately preceding the related interest payment date, and will be computed on the basis of a 360-day year consisting of twelve 30-day months. The September 2021 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries, other than Berry, has guaranteed the September 2021 Senior Notes on a senior unsecured basis. The September 2021 Indenture provides that the Company may redeem: (i) prior to September 15, 2017, up to 35% of the aggregate principal amount of the September 2021 Senior Notes at a redemption price of 106.500% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to September 15, 2017, all or part of the September 2021 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the September 2021 Indenture) and accrued and unpaid interest; and (iii) on or after September 15, 2017, all or part of the September 2021 Senior Notes at a redemption price equal to 103.250%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The September 2021 Indenture also provides that, if a change of control (as defined in the September 2021 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the September 2021 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.
	The May 2019 Indenture and the September 2021 Indenture contain covenants that, among other things, limit the Company’s ability and the ability of the Company’s restricted subsidiaries 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.
	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 SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially similar 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. On June 2, 2014, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $1.8 billion outstanding principal amount of November 2019 Senior Notes for an equal amount of new November 2019 Senior Notes.
	The terms of the new November 2019 Senior Notes are substantially similar in all material respects to those of the outstanding November 2019 Senior Notes, except that the transfer restrictions, registration rights and additional interest provisions related to the outstanding November 2019 Senior Notes do not apply to the new November 2019 Senior Notes. The exchange offer expired on June 28, 2014. The effective date of the registration statement was past the deadline in the registration rights agreement, and therefore, the Company paid additional interest of approximately $15 million since the deadline.
	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 including a $10 million premium which is being amortized to interest expense over the life of the related notes.
Berry Senior Notes Due September 2022
Berry has $599 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 approximately $607 million on the Berry acquisition date including a $7 million premium which is being amortized to interest expense over the life of the related notes.
Payment of Berry June 2014 Senior Notes
On May 30, 2014, in accordance with the provisions of the indenture related to the Berry June 2014 Senior Notes, the Company paid in full the remaining outstanding principal amount of approximately $205 million.
Repurchases of Berry Senior Notes
In February 2014, in accordance with the indentures related to Berry’s senior notes, the Company repurchased through cash tender offers $321,000, $30,000 and $837,000 of Berry’s 10.25% senior notes due June 2014 (the “Berry June 2014 Senior Notes”), November 2020 Senior Notes and September 2022 Senior Notes, respectively.
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.
Senior Notes Covenants
The Company’s senior notes contain covenants that, among other things, may limit its 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.
In addition, any cash generated by Berry is currently being used by Berry to fund its activities and is not currently being distributed to LINN Energy. To the extent that Berry generates cash in excess of its needs, the indentures governing Berry’s senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and Berry may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Berry indentures. Berry’s restricted payments basket may be increased in accordance with the terms of the Berry indentures by, among other things, 50% of Berry’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2014
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. 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 swap contracts, collars and three-way collars. The Company did not designate any of its 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, 2014:
		2015			2016			2017			2018
	Natural gas positions:
	Fixed price swaps (NYMEX Henry Hub):
	Hedged volume (MMMBtu)	118,041			121,841			120,122			36,500
	Average price ($/MMBtu)	$	5.19		$	4.2		$	4.26		$	5
	Put options (NYMEX Henry Hub):
	Hedged volume (MMMBtu)	71,854			76,269			66,886			—
	Average price ($/MMBtu)	$	5		$	5		$	4.88		$	—
	Oil positions:
	Fixed price swaps (NYMEX WTI): (1)
	Hedged volume (MBbls)	11,599			11,465			4,755			—
	Average price ($/Bbl)	$	96.23		$	90.56		$	89.02		$	—
	Three-way collars (NYMEX WTI):
	Hedged volume (MBbls)	1,095			—			—			—
	Short put ($/Bbl)	$	70		$	—		$	—		$	—
	Long put ($/Bbl)	$	90		$	—		$	—		$	—
	Short call ($/Bbl)	$	101.62		$	—		$	—		$	—
	Put options (NYMEX WTI):
	Hedged volume (MBbls)	3,426			3,271			384			—
	Average price ($/Bbl)	$	90		$	90		$	90		$	—
	Natural gas basis differential positions: (2)
	Panhandle basis swaps:
	Hedged volume (MMMBtu)	87,162			59,954			59,138			16,425
	Hedged differential ($/MMBtu)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)
	NWPL Rockies basis swaps:
	Hedged volume (MMMBtu)	43,292			46,294			38,880			10,804
	Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.19	)	$	(0.19	)
	MichCon basis swaps:
	Hedged volume (MMMBtu)	9,344			7,768			7,437			2,044
	Hedged differential ($/MMBtu)	$	0.06		$	0.05		$	0.05		$	0.05
	Houston Ship Channel basis swaps:
	Hedged volume (MMMBtu)	4,891			4,575			3,604			986
	Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.08	)	$	(0.08	)
	Permian basis swaps:
	Hedged volume (MMMBtu)	5,074			4,219			4,819			1,314
	Hedged differential ($/MMBtu)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)
	Oil timing differential positions:
	Trade month roll swaps (NYMEX WTI): (3)
	Hedged volume (MBbls)	7,251			7,446			6,486			—
	Hedged differential ($/Bbl)	$	0.24		$	0.25		$	0.25		$	—
	(1)	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.
	(2)	Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.
	(3)	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 fourth quarter of 2014, the Company canceled all of its ICE Brent – NYMEX WTI basis swaps for 2015 and received cash settlements of approximately $12 million. Currently, the Company has no outstanding ICE Brent – NYMEX WTI basis swaps.
	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. Also, 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.
	During the year ended December 31, 2012, the Company entered into commodity derivative contracts consisting of oil swaps for 2012 through 2017, natural gas swaps for 2012 through 2018, and oil and natural gas puts for 2012 through 2017 and paid premiums for put options of approximately $583 million. The Company also entered into natural gas basis swaps for 2012 through 2016 and trade month roll swaps for 2012 through 2017.
	Settled derivatives on natural gas production for the year ended December 31, 2014, included volumes of 177,029 MMMBtu at an average contract price of $5.14 per MMBtu. Settled derivatives on oil production for the year ended December 31, 2014, included volumes of 24,988 MBbls at an average contract price of $92.39 per Bbl. 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 prices of NYMEX WTI and ICE Brent 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,
			2014			2013
			(in thousands)
	Assets:
	Commodity derivatives		$	2,014,815		$	1,048,212
	Liabilities:
	Commodity derivatives		$	90,260		$	222,905
	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, natural gas and NGL 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 $2.0 billion at December 31, 2014. 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 due to counterparty nonperformance is somewhat mitigated.
	Gains (Losses) on Derivatives
Gains and losses on derivatives were net gains of approximately $1.2 billion, $178 million and $125 million for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively, and are reported on the consolidated statements of operations in “gains on oil and natural gas derivatives.” For the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company received cash settlements of approximately $108 million, $249 million and $391 million, respectively.

Fair_Value_Measurements_on_a_R

Fair Value Measurements on a Recurring Basis	12 Months Ended
	Dec. 31, 2014
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).
	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, 2014
			Level 2		Netting (1)			Total
			(in thousands)
	Assets:
	Commodity derivatives		$	2,014,815	$	(89,576	)	$	1,925,239
	Liabilities:
	Commodity derivatives		$	90,260	$	(89,576	)	$	684
			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
	(1)	Represents counterparty netting under agreements governing such derivatives.

Other_Property_and_Equipment

Other Property and Equipment	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Other Property and Equipment	Other Property and Equipment
	Other property and equipment consists of the following:
		December 31,
		2014			2013
		(in thousands)
	Natural gas plant and pipeline	$	479,754		$	507,342
	Buildings and leasehold improvements	49,046			32,658
	Vehicles	36,534			27,964
	Drilling and other equipment	6,994			8,618
	Furniture and office equipment	88,893			65,909
	Land	7,928			5,391
		669,149			647,882
	Less accumulated depreciation	(144,282		)	(110,939		)
		$	524,867		$	536,943

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations
	The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities 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% for each of the years in the three-year period ended December 31, 2014); and (iv) a credit-adjusted risk-free interest rate (average of 5.3%, 6.2% and 6.8% for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, 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,
		2014			2013
		(in thousands)
	Asset retirement obligations at beginning of year	$	289,321		$	151,974
	Liabilities added from acquisitions	176,538			98,343
	Liabilities added from drilling	10,476			4,048
	Liabilities associated with assets divested	(25,656		)	(1,092		)
	Current year accretion expense	22,164			11,938
	Settlements	(12,620		)	(5,136		)
	Revision of estimates	37,347			29,246
	Asset retirement obligations at end of year	$	497,570		$	289,321

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
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 Company has filed a motion to dismiss the case for failure to state a claim on which relief may be granted, and that motion has not yet been ruled on by the Court. While that motion has remained pending, the parties have agreed on a scheduling order, which provides for briefing on the class certification issues in late 2015 and first part of 2016. The Company has denied that it has liability on the claims asserted in the case and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. For another statewide class action royalty payment dispute, briefing on class certification issues is expected to be completed during the summer of 2015. The Company has denied that it has any liability on the claims and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. The Company is unable to estimate a possible loss, or range of possible loss, if any, in these cases. 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.
	Prior to the Company’s acquisition of Berry, Berry became a defendant in a certain statewide royalty class action case. The parties entered into a settlement agreement to settle past claims for approximately $2.4 million, which the Court approved on October 29, 2014. On December 17, 2014, Berry made a one-time lump sum payment of $2.4 million for damages related to production through April 30, 2014. On December 29, 2014, the Court issued an Order dismissing the matter with prejudice. Per the parties’ settlement agreement, Berry has agreed to a new methodology for calculating royalty payments beginning May 1, 2014.
	In 2013, several class action complaints were filed and ultimately consolidated in the United States District Court, Southern District of New York (the “Federal Actions”) against LINN Energy, LinnCo, certain of their officers and directors and the various underwriters for LinnCo’s initial public offering. These cases collectively asserted claims based on allegations that LINN Energy made false or misleading statements relating to its (i) hedging strategy, (ii) the cash flow available for distribution to unitholders, and (iii) LINN Energy’s energy production in its Exchange Act filings; and additional claims based on alleged misstatements relating to these issues in the prospectus and registration statement for LinnCo’s initial public offering. Several derivative actions were also filed in federal and state court in Texas, and in the Delaware Court of Chancery (the “Derivative Actions”) asserting derivative claims on behalf of LINN Energy against the individual officers and directors 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 Federal Actions.
	In July 2014, the Court dismissed the claims of the plaintiffs in the Federal Actions with prejudice, concluding that the plaintiffs failed to demonstrate any material misstatement or omission by LINN Energy or LinnCo, or their officers and directors. The plaintiffs in the Federal Actions did not appeal the Court’s dismissal, and the appeals deadline has now passed. The plaintiffs in the Derivative Actions subsequently have dismissed their claims without prejudice.
	During the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
	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. In 2014 and 2013, the Company received approximately $7 million and $11 million, respectively, of the Company Claim of which both amounts are included in “gains on oil and natural gas derivatives” on the consolidated statements of operations. In 2012, the Company received approximately $28 million of the Company Claim resulting in a gain of approximately $22 million included in “gains on oil and natural gas derivatives” on the consolidated statements of operations. In the aggregate, the Company has received approximately $46 million of the Company Claim.

Earnings_Per_Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2014
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 loss:
		Year Ended December 31,
		2014			2013			2012
		(in thousands, except per unit data)
	Net loss	$	(451,809	)	$	(691,337	)	$	(386,616	)
	Allocated to participating securities	(7,117		)	(5,935		)	(4,575		)
		$	(458,926	)	$	(697,272	)	$	(391,191	)
	Basic net loss per unit	$	(1.40	)	$	(2.94	)	$	(1.92	)
	Diluted net loss per unit	$	(1.40	)	$	(2.94	)	$	(1.92	)
	Basic weighted average units outstanding	328,918			237,544			203,775
	Dilutive effect of unit equivalents	—			—			—
	Diluted weighted average units outstanding	328,918			237,544			203,775
	Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 6 million, 4 million and 2 million unit options and warrants for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. All equivalent units were anti-dilutive for the years ended December 31, 2014, December 31, 2013, and December 31, 2012.

Operating_Leases

Operating Leases	12 Months Ended
	Dec. 31, 2014
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 2034. The Company recognized expense under operating leases of approximately $14 million, $7 million and $7 million, for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively.
	As of December 31, 2014, future minimum lease payments were as follows (in thousands):
	2015	$	13,265
	2016	10,288
	2017	8,215
	2018	7,130
	2019	6,492
	Thereafter	1,046
		$	46,436

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
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. 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,
		2014				2013				2012
		(in thousands)
	Current taxes:
	Federal	$	473			$	144			$	2,711
	State	21				198				439
	Deferred taxes:
	Federal	(104		)		(2,805		)		323
	State	4,047				264				(683		)
		$	4,437			$	(2,199	)		$	2,790
	As of December 31, 2014, the Company’s taxable entities had approximately $11 million of net operating loss carryforwards for federal income tax purposes which will begin expiring in 2031.
	A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
		Year Ended December 31,
		2014			2013			2012
	Federal statutory rate	35	%		35	%		35	%
	State, net of federal tax benefit	(0.9	)		(0.1	)		0.1
	Loss excluded from nontaxable entities	(34.6	)		(34.6	)		(35.6	)
	Other items	(0.5	)		—			(0.2	)
	Effective rate	(1.0	)%		0.3	%		(0.7	)%
	Significant components of the deferred tax assets and liabilities were as follows:
		December 31,
		2014				2013
		(in thousands)
	Deferred tax assets:
	Net operating loss carryforwards	$	—			$	1,129
	Unit-based compensation	22,105				21,965
	Other	6,857				7,759
	Total deferred tax assets	28,962				30,853
	Deferred tax liabilities:
	Property and equipment principally due to differences in depreciation	(10,991		)		(12,525		)
	Other	(6,370		)		(1,509		)
	Total deferred tax liabilities	(17,361		)		(14,034		)
	Net deferred tax assets	$	11,601			$	16,819
	Net deferred tax assets and liabilities were classified on the consolidated balance sheets as follows:
		December 31,
		2014				2013
		(in thousands)
	Deferred tax assets	$	28,442			$	29,204
	Deferred tax liabilities	(2,964		)		(10		)
	Other current assets	$	25,478			$	29,194
	Deferred tax assets	$	520			$	1,649
	Deferred tax liabilities	(14,397		)		(14,024		)
	Other noncurrent liabilities	$	(13,877	)		$	(12,375	)
	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, 2014, based on 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, 2014, and December 31, 2013. The tax years 2011 – 2013 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, 2014
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Supplemental Disclosures to the Consolidated Balance Sheets and 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,
		2014			2013
		(in thousands)
	Accrued interest	$	105,310		$	93,998
	Accrued compensation	44,875			55,257
	Asset retirement obligations	16,187			12,616
	Other	1,364			1,504
		$	167,736		$	163,375
	Supplemental disclosures to the consolidated statements of cash flows are presented below:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Cash payments for interest, net of amounts capitalized	$	542,775		$	392,607		$	343,331
	Cash payments for income taxes	$	—		$	14		$	366
	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	$	2,679,547		$	5,726,681		$	2,923,990
	Cash paid, net of cash acquired	(2,395,339		)	(109,350		)	(2,640,475		)
	Units issued in connection with the Berry acquisition	—			(2,781,888		)	—
	Noncash gains on exchanges of properties	(85,493		)	—			—
	Receivables from sellers	16,213			(93		)	2,132
	Payables to sellers	(3,515		)	(6,854		)	443
	Liabilities assumed	$	211,413		$	2,828,496		$	286,090
	Accrued capital expenditures	$	240,331		$	334,542		$	203,229
	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 years ended December 31, 2014, December 31, 2013, and December 31, 2012, is approximately $25 million, $170 million and $197 million, respectively, paid by the Company towards the future funding commitment related to the joint-venture agreement entered into with Anadarko (see Note 2).
	On November 21, 2014, the Company, through two of its wholly owned subsidiaries, completed a noncash exchange of a portion of its Permian Basin properties to Exxon Mobil Corporation in exchange for properties in California’s South Belridge Field. On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed a noncash exchange of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., for properties in the Hugoton Basin.
	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 is included in “other noncurrent assets” on the consolidated balance sheets at both December 31, 2014, and December 31, 2013, and primarily represents cash the Company has deposited 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, 2014, and December 31, 2013, net outstanding checks of approximately $95 million and $48 million, respectively, were reclassified and included in “accounts payable and accrued expenses” on the consolidated balance sheets. Net outstanding checks are presented as cash flows from financing activities and included in “other” on the consolidated statements of cash flows.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
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. As of December 31, 2014, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy and owned approximately 39% of LINN Energy’s outstanding units.
	On December 16, 2013, LinnCo and LINN Energy completed the 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.
	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.
	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. All expenses and costs paid by LINN Energy on LinnCo’s behalf are expensed by LINN Energy.
	For the year ended December 31, 2014, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $3 million, all of which had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2014. The expenses for the year ended December 31, 2014, 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. In addition, during the year ended December 31, 2014, LINN Energy paid approximately $11 million on LinnCo’s behalf for general and administrative expenses incurred by LinnCo in 2013.
	For the year ended December 31, 2013, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $42 million. 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.
	During the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company paid approximately $373 million, $101 million and $25 million, respectively, 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, 2014, December 31, 2013, and December 31, 2012, the Company paid approximately $21 million, $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, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Subsidiary Guarantors	Subsidiary Guarantors
	LINN Energy, LLC’s May 2019 Senior Notes, November 2019 Senior Notes, September 2021 Senior Notes and 2010 Issued Senior Notes are guaranteed by all of the Company’s material subsidiaries, other than Berry Petroleum Company, LLC, which is an indirect 100% wholly owned 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 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. 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 since during that period, 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-14
		LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
								Guarantor Subsidiary
		(in thousands)
	ASSETS
	Current assets:
	Cash and cash equivalents	$	38		$	185		$	1,586		$	—		$	1,809
	Accounts receivable – trade, net	—			371,325			100,359			—			471,684
	Accounts receivable – affiliates	4,028,890			13,205			—			(4,042,095		)	—
	Derivative instruments	—			1,033,448			43,694			—			1,077,142
	Other current assets	18			96,678			59,259			—			155,955
	Total current assets	4,028,946			1,514,841			204,898			(4,042,095		)	1,706,590
	Noncurrent assets:
	Oil and natural gas properties (successful efforts method)	—			13,196,841			4,872,059			—			18,068,900
	Less accumulated depletion and amortization	—			(4,342,675		)	(525,007		)	—			(4,867,682		)
		—			8,854,166			4,347,052			—			13,201,218
	Other property and equipment	—			553,150			115,999			—			669,149
	Less accumulated depreciation	—			(135,830		)	(8,452		)	—			(144,282		)
		—			417,320			107,547			—			524,867
	Derivative instruments	—			848,097			—			—			848,097
	Notes receivable – affiliates	130,500			—			—			(130,500		)	—
	Advance to affiliate	—			—			293,627			(293,627		)	—
	Investments in consolidated subsidiaries	8,562,608			—			—			(8,562,608		)	—
	Other noncurrent assets	116,637			11,816			14,284			—			142,737
		8,809,745			859,913			307,911			(8,986,735		)	990,834
	Total noncurrent assets	8,809,745			10,131,399			4,762,510			(8,986,735		)	14,716,919
	Total assets	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509
	LIABILITIES AND UNITHOLDERS’ CAPITAL
	Current liabilities:
	Accounts payable and accrued expenses	$	3,784		$	581,880		$	229,145		$	—		$	814,809
	Accounts payable – affiliates	—			4,028,890			13,205			(4,042,095		)	—
	Advance from affiliate	—			293,627			—			(293,627		)	—
	Derivative instruments	—			—			—			—			—
	Other accrued liabilities	89,507			59,142			19,087			—			167,736
	Total current liabilities	93,291			4,963,539			261,437			(4,335,722		)	982,545
	Noncurrent liabilities:
	Credit facilities	1,795,000			—			1,173,175			—			2,968,175
	Term loan	500,000			—			—			—			500,000
	Senior notes, net	5,913,857			—			913,777			—			6,827,634
	Notes payable – affiliates	—			130,500			—			(130,500		)	—
	Derivative instruments	—			684			—			—			684
	Other noncurrent liabilities	—			400,851			200,015			—			600,866
	Total noncurrent liabilities	8,208,857			532,035			2,286,967			(130,500		)	10,897,359
	Unitholders’ capital:
	Units issued and outstanding	5,388,749			4,831,339			2,416,381			(7,240,658		)	5,395,811
	Accumulated income (deficit)	(852,206		)	1,319,327			2,623			(1,321,950		)	(852,206		)
		4,536,543			6,150,666			2,419,004			(8,562,608		)	4,543,605
	Total liabilities and unitholders’ capital	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509
	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	8,433,290			—			—			(8,433,290		)	—
Other noncurrent assets	108,785			10,968			8,051			—			127,804
	8,628,275			690,459			10,562			(8,519,490		)	809,806
Total noncurrent assets	8,628,275			10,683,519			4,896,720			(8,519,490		)	15,689,024
Total assets	$	12,841,005		$	11,305,702		$	5,107,045		$	(12,748,788	)	$	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)	(400,397		)	1,313,526			(19,973		)	(1,293,553		)	(400,397		)
	5,882,350			6,146,880			2,295,487			(8,433,290		)	5,891,427
Total liabilities and unitholders’ capital	$	12,841,005		$	11,305,702		$	5,107,045		$	(12,748,788	)	$	16,504,964
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2014
	LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
							Guarantor Subsidiary
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	2,312,137		$	1,298,402		$	—		$	3,610,539
Gains on oil and natural gas derivatives	—			1,127,395			78,784			—			1,206,179
Marketing revenues	—			84,349			50,911			—			135,260
Other revenues	—			28,133			3,192			—			31,325
	—			3,552,014			1,431,289			—			4,983,303
Expenses:
Lease operating expenses	—			440,624			364,540			—			805,164
Transportation expenses	—			165,489			41,842			—			207,331
Marketing expenses	—			81,210			36,255			—			117,465
General and administrative expenses	—			190,286			102,787			—			293,073
Exploration costs	—			125,037			—			—			125,037
Depreciation, depletion and amortization	—			771,549			302,353			—			1,073,902
Impairment of long-lived assets	—			2,050,387			253,362			—			2,303,749
Taxes, other than income taxes	40			169,655			97,708			—			267,403
(Gains) losses on sale of assets and other, net	—			(487,286		)	120,786			—			(366,500		)
	40			3,506,951			1,319,633			—			4,826,624
Other income and (expenses):
Interest expense, net of amounts capitalized	(480,259		)	(19,631		)	(87,948		)	—			(587,838		)
Interest expense – affiliates	—			(7,954		)	—			7,954			—
Interest income – affiliates	7,954			—			—			(7,954		)	—
Equity in earnings from consolidated subsidiaries	28,397			—			—			(28,397		)	—
Other, net	(7,861		)	(7,309		)	(1,043		)	—			(16,213		)
	(451,769		)	(34,894		)	(88,991		)	(28,397		)	(604,051		)
Income (loss) before income taxes	(451,809		)	10,169			22,665			(28,397		)	(447,372		)
Income tax expense	—			4,368			69			—			4,437
Net income (loss)	$	(451,809	)	$	5,801		$	22,596		$	(28,397	)	$	(451,809	)
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	—			52,328			1,843			—			54,171
Other revenues	—			26,387			—			—			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			—
Interest income – affiliates	5,543			—			—			(5,543		)	—
Loss on extinguishment of debt	(5,304		)	—			—			—			(5,304		)
Equity in losses from consolidated subsidiaries	(266,899		)	—			—			266,899			—
Other, net	(8,283		)	(166		)	(28		)	—			(8,477		)
	(690,613		)	(7,213		)	(3,991		)	266,899			(434,918		)
Loss before income taxes	(691,337		)	(249,125		)	(19,973		)	266,899			(693,536		)
Income tax benefit	—			(2,199		)	—			—			(2,199		)
Net loss	$	(691,337	)	$	(246,926	)	$	(19,973	)	$	266,899		$	(691,337	)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2014
	LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
							Guarantor Subsidiary
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(451,809	)	$	5,801		$	22,596		$	(28,397	)	$	(451,809	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			771,549			302,353			—			1,073,902
Impairment of long-lived assets	—			2,050,387			253,362			—			2,303,749
Unit-based compensation expenses	—			53,284			—			—			53,284
Amortization and write-off of deferred financing fees	38,785			17,054			(4,913		)	—			50,926
(Gains) losses on sale of assets and other, net	—			(372,945		)	111,374			—			(261,571		)
Equity in earnings from consolidated subsidiaries	(28,397		)	—			—			28,397			—
Deferred income tax	—			3,874			69			—			3,943
Derivatives activities:
Total gains	—			(1,127,395		)	(78,784		)	—			(1,206,179		)
Cash settlements	—			88,776			6,738			—			95,514
Cash settlements on canceled derivatives	—			—			12,281			—			12,281
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	—			(11,419		)	16,483			—			5,064
Decrease in accounts receivable – affiliates	257,485			16,950			—			(274,435		)	—
(Increase) decrease in other assets	312			(2,187		)	(15,949		)	—			(17,824		)
Increase in accounts payable and accrued expenses	—			99,003			26			—			99,029
Decrease in accounts payable and accrued expenses – affiliates	—			(270,690		)	(3,745		)	274,435			—
Increase (decrease) in other liabilities	14,465			(24,473		)	(38,411		)	—			(48,419		)
Net cash provided by (used in) operating activities	(169,159		)	1,297,569			583,480			—			1,711,890
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	—			(2,475,315		)	(3,937		)	—			(2,479,252		)
Development of oil and natural gas properties	—			(1,061,395		)	(508,482		)	—			(1,569,877		)
Purchases of other property and equipment	—			(63,070		)	(11,470		)	—			(74,540		)
Investment in affiliates	(100,921		)	—			—			100,921			—
Change in notes receivable with affiliate	(44,300		)	—			—			44,300			—
Proceeds from sale of properties and equipment and other	(14,117		)	2,210,015			7,667			—			2,203,565
Net cash used in investing activities	(159,338		)	(1,389,765		)	(516,222		)	145,221			(1,920,104		)
	LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
							Guarantor Subsidiary
	(in thousands)
Cash flow from financing activities:
Proceeds from borrowings	4,640,024			1,300,000			—			—			5,940,024
Repayments of debt	(3,305,000		)	(1,300,000		)	(206,124		)	—			(4,811,124		)
Distributions to unitholders	(962,048		)	—			—			—			(962,048		)
Financing fees and offering expenses	(59,048		)	—			(10,646		)	—			(69,694		)
Change in note payable with affiliate	—			44,300			—			(44,300		)	—
Capital contribution – affiliates	—			—			100,921			(100,921		)	—
Excess tax benefit from unit-based compensation	810			(44		)	—			—			766
Other	13,745			47,047			(864		)	—			59,928
Net cash provided by (used in) financing activities	328,483			91,303			(116,713		)	(145,221		)	157,852
Net decrease in cash and cash equivalents	(14		)	(893		)	(49,455		)	—			(50,362		)
Cash and cash equivalents:
Beginning	52			1,078			51,041			—			52,171
Ending	$	38		$	185		$	1,586		$	—		$	1,809
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	$	(691,337	)	$	(246,926	)	$	(19,973	)	$	266,899		$	(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
Equity in losses from consolidated subsidiaries	266,899			—			—			(266,899		)	—
Deferred income taxes	—			(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 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 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 and offering expenses	(16,033		)	—			—			—			(16,033		)
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
Other	2,895			12,422			(4,272		)	—			11,045
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, 2014
Subsequent Events [Abstract]
SEC Inquiry	SEC Inquiry
	As disclosed on July 1, 2013, the Company and its affiliate, LinnCo, were notified by the staff of the SEC that its Fort Worth Regional Office had commenced an inquiry regarding LINN Energy and LinnCo. The SEC staff was investigating whether any violations of federal securities laws had occurred. Both LINN Energy and LinnCo cooperated fully with the SEC in this matter. The Company was notified on February 4, 2015, that the SEC has closed its inquiry regarding LINN Energy and LinnCo and does not intend to recommend any enforcement action.

Supplemental_Oil_and_Natural_G

Supplemental Oil and Natural Gas Data (Unaudited)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Natural Gas Data (Unaudited)	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,
			2014				2013				2012
			(in thousands)
	Property acquisition costs: (1)
	Proved		$	2,784,852			$	3,740,379			$	2,531,419
	Unproved		788,682				1,638,302				181,124
	Exploration costs		792				13,096				452
	Development costs		1,487,204				1,153,770				1,062,043
	Asset retirement costs		20,919				7,351				4,675
	Total costs incurred		$	5,082,449			$	6,552,898			$	3,779,713
	(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,
			2014				2013
			(in thousands)
	Proved properties:
	Leasehold acquisition		$	13,362,642			$	12,277,089
	Development		2,830,841				3,660,277
	Unproved properties		1,875,417				1,951,193
			18,068,900				17,888,559
	Less accumulated depletion and amortization		(4,867,682		)		(3,546,284		)
			$	13,201,218			$	14,342,275
	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,
			2014				2013				2012
			(in thousands)
	Revenues and other:
	Oil, natural gas and natural gas liquid sales		$	3,610,539			$	2,073,240			$	1,601,180
	Gains on oil and natural gas derivatives		1,206,179				177,857				124,762
			4,816,718				2,251,097				1,725,942
	Production costs:
	Lease operating expenses		805,164				372,523				317,699
	Transportation expenses		207,331				128,440				77,322
	Severance taxes, ad valorem taxes and California carbon allowances		267,100				139,202				130,805
			1,279,595				640,165				525,826
	Other costs:
	Exploration costs		125,037				5,251				1,915
	Depletion and amortization		1,020,674				790,320				579,382
	Impairment of long-lived assets		2,303,749				828,317				422,499
	Gains on sale of assets and other, net		(388,733		)		(138		)		(1,369		)
	Texas margin tax expense (benefit)		4,053				458				(787		)
			3,064,780				1,624,208				1,001,640
	Results of operations		$	472,343			$	(13,276	)		$	198,476
	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. 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, 2014, December 31, 2013, and December 31, 2012, 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, 2014
			Natural Gas			Oil			NGL			Total
			(Bcf)			(MMBbls)			(MMBbls)			(Bcfe)
	Proved developed and undeveloped reserves:
	Beginning of year		3,010			365.6			200			6,403
	Revisions of previous estimates		96			(22.3	)		(46.8	)		(318	)
	Purchases of minerals in place		1,763			50			71.9			2,495
	Sales of minerals in place		(477	)		(51.7	)		(49.5	)		(1,084	)
	Extensions, discoveries and other additions		72			26.8			2.9			250
	Production		(209	)		(26.6	)		(12.2	)		(442	)
	End of year		4,255			341.8			166.3			7,304
	Proved developed reserves:
	Beginning of year		2,027			252.4			133.2			4,340
End of year		3,549			246			132.2			5,818
Proved undeveloped reserves:
Beginning of year		983			113.2			66.8			2,063
End of year		706			95.8			34.1			1,486
		Year Ended December 31, 2013
		Natural Gas (Bcf)			Oil			NGL (MMBbls)			Total
					(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	)
Purchases 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	)
Purchases 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
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.
Since the reserves were estimated in accordance with SEC regulations, 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, the Company had positive price revisions for the year ended December 31, 2014, even though there was a steep decline in commodity prices during the fourth quarter of 2014. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas prices decreased approximately 42% and 30%, respectively, to $53.27 per Bbl for oil and $2.89 per MMBtu for natural gas at December 31, 2014. For information about potential risks that could affect the Company if lower commodity prices were to continue, see Item 1A. “Risk Factors.”
Proved reserves increased by approximately 901 Bcfe to approximately 7,304 Bcfe for the year ended December 31, 2014, from 6,403 Bcfe for the year ended December 31, 2013. The year ended December 31, 2014, includes approximately 318 Bcfe of negative revisions of previous estimates, due primarily to 174 Bcfe of negative revisions due to ethane rejection in the Hugoton and Green River basins, 146 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs and 43 Bcfe of negative revisions due to asset performance, partially offset by 45 Bcfe of positive revisions primarily due to higher natural gas prices. During the year ended December 31, 2014, acquisitions and properties acquired in the two exchanges with Exxon Mobil Corporation increased proved reserves by approximately 2,495 Bcfe and the 2014 divestitures and properties relinquished in the two exchanges with Exxon Mobil Corporation decreased proved reserves by approximately 1,084 Bcfe. In addition, extensions and discoveries, primarily from 917 productive wells drilled during the year, contributed approximately 250 Bcfe to the increase in proved reserves.
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, 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 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.
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; however, these amounts are not material. See Note 14 for additional information about income taxes.
		December 31,
		2014				2013				2012
		(in thousands)
Future estimated revenues		$	55,195,268			$	51,112,346			$	30,374,380
Future estimated production costs		(24,100,468		)		(19,306,728		)		(11,460,854		)
Future estimated development costs		(4,032,588		)		(5,110,896		)		(3,574,058		)
Future net cash flows		27,062,212				26,694,722				15,339,468
10% annual discount for estimated timing of cash flows		(14,549,921		)		(14,795,393		)		(9,266,487		)
Standardized measure of discounted future net cash flows		$	12,512,291			$	11,899,329			$	6,072,981
Representative NYMEX prices: (1)
Natural gas (MMBtu)		$	4.35			$	3.67			$	2.76
Oil (Bbl)		$	95.27			$	96.89			$	94.64
(1)	In accordance with SEC regulations, reserves at December 31, 2014, December 31, 2013, and December 31, 2012, 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,
		2014				2013				2012
		(in thousands)
Sales and transfers of oil, natural gas and NGL produced during the period		$	(2,330,944	)		$	(1,433,075	)		$	(1,075,354	)
Changes in estimated future development costs		156,614				317,064				289,762
Net change in sales and transfer prices and production costs related to future production		(599,121		)		203,370				(1,463,820		)
Purchases of minerals in place		3,021,768				5,113,335				2,153,651
Sales of minerals in place		(1,681,504		)		(139,384		)		—
Extensions, discoveries and improved recovery		910,787				801,254				413,702
Previously estimated development costs incurred during the period		819,987				444,861				442,322
Net change due to revisions in quantity estimates		(672,800		)		(220,224		)		(1,595,302		)
Accretion of discount		1,189,933				607,298				661,486
Changes in production rates and other		(201,758		)		131,849				(368,326		)
		$	612,962			$	5,826,348			$	(541,879	)
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 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.

Supplemental_Quarterly_Data_Un

Supplemental Quarterly Data (Unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Supplemental Quarterly Data (Unaudited)	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
			(in thousands, except per unit amounts)
	2014:00:00
	Oil, natural gas and natural gas liquid sales		$	938,877		$	967,850		$	937,458		$	766,354
	Gains (losses) on oil and natural gas derivatives		(241,493		)	(408,788		)	451,702			1,404,758
	Total revenues and other		733,587			596,951			1,435,115			2,217,650
	Total expenses (1)		674,568			664,452			1,320,157			2,533,947
	(Gains) losses on sale of assets and other, net		2,586			5,467			(35,803		)	(338,750		)
	Net loss		(85,337		)	(207,870		)	(4,100		)	(154,502		)
	Net loss per unit:
	Basic		$	(0.27	)	$	(0.64	)	$	(0.02	)	$	(0.47	)
	Diluted		$	(0.27	)	$	(0.64	)	$	(0.02	)	$	(0.47	)
			Quarters Ended
			31-Mar			30-Jun			30-Sep			December 31
			(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
	(Gains) 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.

Basis_of_Presentation_and_Sign1

Basis of Presentation and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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 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. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing 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 both December 31, 2014, and December 31, 2013.
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 of proved and risk-adjusted probable and possible reserves 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 $9 million for the year ended December 31, 2014, and $2 million for each of the years ended December 31, 2013, and December 31, 2012.
	Impairment of Proved Properties
	Based on the analysis described above, for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company recorded noncash impairment charges, before and after tax, of approximately $2.3 billion, $791 million and $422 million, respectively, associated with proved oil and natural gas properties. 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 impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
	During the fourth quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $1.7 billion associated with proved oil and natural gas properties throughout its various operating regions. The impairment was due to a steep decline in commodity prices. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas forward price curves decreased approximately 24% and 12%, respectively. Following are the impairment charges recorded by operating region:
	•	Permian Basin – $735 million;
	•	Rockies – $586 million (in the Powder River Basin and Uinta Basin);
	•	Mid-Continent – $244 million;
	•	South Texas – $131 million; and
	•	TexLa – $5 million.
	In addition, during the third quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $603 million associated with proved oil and natural gas properties in the Permian Basin region. The impairment was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for the proved oil and natural gas properties.
	During 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. During the year ended December 31, 2012, the Company recorded noncash impairment charges, 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.
	Subsequent to December 31, 2014, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results 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. 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 $125 million, $5 million and $2 million for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively, 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 years ended December 31, 2014, December 31, 2013, and December 31, 2012, the Company recorded noncash impairment charges, before and after tax, of approximately $2.3 billion, $791 million and $422 million, respectively, associated with proved oil and natural gas properties. 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 impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
	During the fourth quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $1.7 billion associated with proved oil and natural gas properties throughout its various operating regions. The impairment was due to a steep decline in commodity prices. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas forward price curves decreased approximately 24% and 12%, respectively. Following are the impairment charges recorded by operating region:
	•	Permian Basin – $735 million;
	•	Rockies – $586 million (in the Powder River Basin and Uinta Basin);
	•	Mid-Continent – $244 million;
	•	South Texas – $131 million; and
	•	TexLa – $5 million.
	In addition, during the third quarter of 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $603 million associated with proved oil and natural gas properties in the Permian Basin region. The impairment was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for the proved oil and natural gas properties.
	During 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. During the year ended December 31, 2012, the Company recorded noncash impairment charges, 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.
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 two 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. Imbalance receivables and payables are valued at the lower of the price in effect at the time of production, the current market value or, if a contract is in hand, the contract price. At December 31, 2014, and December 31, 2013, the Company had natural gas production imbalance receivables of approximately $17 million and $27 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets and natural gas production imbalance payables of approximately $13 million and $16 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 revenues 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. The revenue from this activity is included in “other revenues” on the consolidated statements of operations.
Restricted Cash	Restricted Cash
	Restricted cash of approximately $6 million is included in “other noncurrent assets” on the consolidated balance sheets at both December 31, 2014, and December 31, 2013, 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 net cash provided by operating activities due to fluctuations in commodity prices.
	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. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date. Also, 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, 2014, the Company had no outstanding derivative contracts in the form of interest rate swaps.
	In addition, as part of the 2013 acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”) (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 and other” 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, 2014, and December 31, 2013, net deferred financing fees of approximately $129 million and $114 million, respectively, 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, 2014, December 31, 2013, and December 31, 2012, amortization expense of approximately $46 million, $18 million and $13 million, respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations. For the year ended December 31, 2014, approximately $8 million were written off to expense and included in “other, net” on the consolidated statement of operations related to the VIE Term Loan (as defined in Note 6) and amendments to the Credit Facilities (as defined in Note 6). For the year ended December 31, 2012, approximately $8 million were written off to expense and included in “other, net” on the consolidated statement of operations related to amendments of the LINN Credit Facility (as defined in Note 6). No fees related to amendments of the Credit Facilities were written off 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, 2014, and December 31, 2013. 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. 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.

Exchanges_of_Properties_Acquis1

Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):
	Assets:
	Current	$	26,007
	Oil and natural gas properties	2,532,439
	Other property and equipment	121,101
	Total assets acquired	2,679,547
	Liabilities:
	Current	21,976
	Asset retirement obligations, current and noncurrent	171,057
	Noncurrent	18,380
	Total liabilities assumed	211,413
	Net assets acquired	$	2,468,134
Schedule of Pro Forma 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,
			2014			2013
			(in thousands, except
			per unit amounts)
	Total revenues and other		$	5,335,442		$	3,973,605
	Total operating expenses		$	5,039,311		$	3,711,868
	Net loss		$	(403,447	)	$	(397,070	)
	Net loss per unit:
	Basic		$	(1.25	)	$	(1.22	)
	Diluted		$	(1.25	)	$	(1.22	)
	The pro forma condensed combined statements of operations include adjustments to:
	•	Reflect the results of the Devon Assets Acquisition and the Berry acquisition for all periods presented.
	•	Reflect incremental depreciation, depletion and amortization expense, using the unit-of-production method related to oil and natural gas properties acquired and an estimated useful life of 10 years and 20 years for other property and equipment acquired in the Devon Assets Acquisition and the Berry acquisition, respectively.
	•	Reflect incremental accretion expense related to asset retirement obligations on oil and natural gas properties acquired in the Devon Assets Acquisition.
	•	Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price of the Devon Assets Acquisition and a reduction in interest expense related to the amortization of the adjustment to fair value of Berry’s debt using the effective interest method.
	•	Reflect incremental amortization of deferred financing fees associated with debt incurred to fund the purchase price of the Devon Assets Acquisition.
	•	Exclude transaction costs related to the Devon Assets Acquisition and the Berry acquisition included in the historical statements of operations as they reflect nonrecurring charges not expected to have a continuing impact on the combined results.
	•	Reflect approximately 93.8 million LINN Energy units assumed to be issued on January 1, 2013, in conjunction with the Berry acquisition.

UnitBased_Compensation_and_Oth1

Unit-Based Compensation and Other Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2014
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,
			2014			2013			2012
			(in thousands)
	General and administrative expenses		$	45,195		$	37,375		$	27,641
	Lease operating expenses		8,089			5,328			1,892
	Total unit-based compensation expenses		$	53,284		$	42,703		$	29,533
	Income tax benefit		$	19,688		$	15,779		$	10,912
Nonvested Units	A summary of the status of the nonvested units as of December 31, 2014, is presented below:
			Number of		Weighted Average
			Nonvested		Grant-Date
			Units		Fair Value
	Nonvested units at December 31, 2013		2,571,410		$	33.14
	Granted		1,789,038		$	33.1
	Vested		(1,282,509	)	$	32.77
	Forfeited		(238,966	)	$	32.25
	Nonvested units at December 31, 2014		2,838,973		$	32.7
Unit Options Activity	The following provides information related to unit option activity for the year ended December 31, 2014:
			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, 2013		6,433,223		$	30.22		6.66		$	33
	Exercised		(813,806	)	$	16.56
	Forfeited or expired		(175,000	)	$	40.01
	Outstanding at December 31, 2014		5,444,417		$	31.95		5.12		$	—
	Exercisable at December 31, 2014		2,510,457		$	22.57		5.5		$	—
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
	(1)	All unit options granted in 2013 were replacement awards issued in exchange for options assumed in the Berry acquisition.

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Summary of Outstanding Debt	The following summarizes the Company’s outstanding debt:
			December 31,
			2014			2013
			(in thousands, except percentages)
	LINN credit facility (1)		$	1,795,000		$	1,560,000
	Berry credit facility (2)		1,173,175			1,173,175
	Term loan (3)		500,000			500,000
	10.25% Berry senior notes due June 2014		—			205,257
	6.50% senior notes due May 2019 (4)		1,200,000			750,000
	6.25% senior notes due November 2019		1,800,000			1,800,000
	8.625% senior notes due April 2020		1,300,000			1,300,000
	6.75% Berry senior notes due November 2020		299,970			300,000
	7.75% senior notes due February 2021		1,000,000			1,000,000
	6.50% senior notes due September 2021 (4)		650,000			—
	6.375% Berry senior notes due September 2022		599,163			600,000
	Net unamortized discounts and premiums		(21,499		)	(18,216		)
	Total debt, net		10,295,809			9,170,216
	Less current maturities		—			(211,558		)
	Total long-term debt, net		$	10,295,809		$	8,958,658
	(1)	Variable interest rate of 1.92% at both December 31, 2014, and December 31, 2013.
	(2)	Variable interest rate of 2.67% at both December 31, 2014, and December 31, 2013.
	(3)	Variable interest rates of 2.66% and 2.67% at December 31, 2014 and December 31, 2013, respectively.
	(4)	$450 million of senior notes due May 2019 and $650 million of senior notes due September 2021 were issued on September 9, 2014.
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]
			December 31, 2014						December 31, 2013
			Carrying			Fair Value			Carrying		Fair Value
			Value						Value
			(in thousands)
	Credit facilities		$	2,968,175		$	2,968,175		$	2,733,175	$	2,733,175
	Term loan		500,000			500,000			500,000		500,000
	Senior notes, net		6,827,634			5,703,649			5,937,041		6,162,402
	Total debt, net		$	10,295,809		$	9,171,824		$	9,170,216	$	9,395,577

Derivatives_Tables

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014:
		2015			2016			2017			2018
	Natural gas positions:
	Fixed price swaps (NYMEX Henry Hub):
	Hedged volume (MMMBtu)	118,041			121,841			120,122			36,500
	Average price ($/MMBtu)	$	5.19		$	4.2		$	4.26		$	5
	Put options (NYMEX Henry Hub):
	Hedged volume (MMMBtu)	71,854			76,269			66,886			—
	Average price ($/MMBtu)	$	5		$	5		$	4.88		$	—
	Oil positions:
	Fixed price swaps (NYMEX WTI): (1)
	Hedged volume (MBbls)	11,599			11,465			4,755			—
	Average price ($/Bbl)	$	96.23		$	90.56		$	89.02		$	—
	Three-way collars (NYMEX WTI):
	Hedged volume (MBbls)	1,095			—			—			—
	Short put ($/Bbl)	$	70		$	—		$	—		$	—
	Long put ($/Bbl)	$	90		$	—		$	—		$	—
	Short call ($/Bbl)	$	101.62		$	—		$	—		$	—
	Put options (NYMEX WTI):
	Hedged volume (MBbls)	3,426			3,271			384			—
	Average price ($/Bbl)	$	90		$	90		$	90		$	—
	Natural gas basis differential positions: (2)
	Panhandle basis swaps:
	Hedged volume (MMMBtu)	87,162			59,954			59,138			16,425
	Hedged differential ($/MMBtu)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)
	NWPL Rockies basis swaps:
	Hedged volume (MMMBtu)	43,292			46,294			38,880			10,804
	Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.19	)	$	(0.19	)
	MichCon basis swaps:
	Hedged volume (MMMBtu)	9,344			7,768			7,437			2,044
	Hedged differential ($/MMBtu)	$	0.06		$	0.05		$	0.05		$	0.05
	Houston Ship Channel basis swaps:
	Hedged volume (MMMBtu)	4,891			4,575			3,604			986
	Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.08	)	$	(0.08	)
	Permian basis swaps:
	Hedged volume (MMMBtu)	5,074			4,219			4,819			1,314
	Hedged differential ($/MMBtu)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)
	Oil timing differential positions:
	Trade month roll swaps (NYMEX WTI): (3)
	Hedged volume (MBbls)	7,251			7,446			6,486			—
	Hedged differential ($/Bbl)	$	0.24		$	0.25		$	0.25		$	—
	(1)	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.
	(2)	Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.
	(3)	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,
			2014			2013
			(in thousands)
	Assets:
	Commodity derivatives		$	2,014,815		$	1,048,212
	Liabilities:
	Commodity derivatives		$	90,260		$	222,905

Fair_Value_Measurements_on_a_R1

Fair Value Measurements on a Recurring Basis (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014
			Level 2		Netting (1)			Total
			(in thousands)
	Assets:
	Commodity derivatives		$	2,014,815	$	(89,576	)	$	1,925,239
	Liabilities:
	Commodity derivatives		$	90,260	$	(89,576	)	$	684
			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
	(1)	Represents counterparty netting under agreements governing such derivatives.

Other_Property_and_Equipment_T

Other Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Other Property and Equipment	Other property and equipment consists of the following:
		December 31,
		2014			2013
		(in thousands)
	Natural gas plant and pipeline	$	479,754		$	507,342
	Buildings and leasehold improvements	49,046			32,658
	Vehicles	36,534			27,964
	Drilling and other equipment	6,994			8,618
	Furniture and office equipment	88,893			65,909
	Land	7,928			5,391
		669,149			647,882
	Less accumulated depreciation	(144,282		)	(110,939		)
		$	524,867		$	536,943

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations Reconciliation	The following presents a reconciliation of the Company’s asset retirement obligations:
		December 31,
		2014			2013
		(in thousands)
	Asset retirement obligations at beginning of year	$	289,321		$	151,974
	Liabilities added from acquisitions	176,538			98,343
	Liabilities added from drilling	10,476			4,048
	Liabilities associated with assets divested	(25,656		)	(1,092		)
	Current year accretion expense	22,164			11,938
	Settlements	(12,620		)	(5,136		)
	Revision of estimates	37,347			29,246
	Asset retirement obligations at end of year	$	497,570		$	289,321

Earnings_Per_Unit_Tables

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2014
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 loss:
		Year Ended December 31,
		2014			2013			2012
		(in thousands, except per unit data)
	Net loss	$	(451,809	)	$	(691,337	)	$	(386,616	)
	Allocated to participating securities	(7,117		)	(5,935		)	(4,575		)
		$	(458,926	)	$	(697,272	)	$	(391,191	)
	Basic net loss per unit	$	(1.40	)	$	(2.94	)	$	(1.92	)
	Diluted net loss per unit	$	(1.40	)	$	(2.94	)	$	(1.92	)
	Basic weighted average units outstanding	328,918			237,544			203,775
	Dilutive effect of unit equivalents	—			—			—
	Diluted weighted average units outstanding	328,918			237,544			203,775

Operating_Leases_Tables

Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2014
Leases, Operating [Abstract]
Future Minimum Lease Payments	As of December 31, 2014, future minimum lease payments were as follows (in thousands):
	2015	$	13,265
	2016	10,288
	2017	8,215
	2018	7,130
	2019	6,492
	Thereafter	1,046
		$	46,436

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014				2013				2012
		(in thousands)
	Current taxes:
	Federal	$	473			$	144			$	2,711
	State	21				198				439
	Deferred taxes:
	Federal	(104		)		(2,805		)		323
	State	4,047				264				(683		)
		$	4,437			$	(2,199	)		$	2,790
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,
		2014			2013			2012
	Federal statutory rate	35	%		35	%		35	%
	State, net of federal tax benefit	(0.9	)		(0.1	)		0.1
	Loss excluded from nontaxable entities	(34.6	)		(34.6	)		(35.6	)
	Other items	(0.5	)		—			(0.2	)
	Effective rate	(1.0	)%		0.3	%		(0.7	)%
Significant components of the deferred tax assets and liabilities	Significant components of the deferred tax assets and liabilities were as follows:
		December 31,
		2014				2013
		(in thousands)
	Deferred tax assets:
	Net operating loss carryforwards	$	—			$	1,129
	Unit-based compensation	22,105				21,965
	Other	6,857				7,759
	Total deferred tax assets	28,962				30,853
	Deferred tax liabilities:
	Property and equipment principally due to differences in depreciation	(10,991		)		(12,525		)
	Other	(6,370		)		(1,509		)
	Total deferred tax liabilities	(17,361		)		(14,034		)
	Net deferred tax assets	$	11,601			$	16,819
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,
		2014				2013
		(in thousands)
	Deferred tax assets	$	28,442			$	29,204
	Deferred tax liabilities	(2,964		)		(10		)
	Other current assets	$	25,478			$	29,194
	Deferred tax assets	$	520			$	1,649
	Deferred tax liabilities	(14,397		)		(14,024		)
	Other noncurrent liabilities	$	(13,877	)		$	(12,375	)

Supplemental_Disclosures_to_th1

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013
		(in thousands)
	Accrued interest	$	105,310		$	93,998
	Accrued compensation	44,875			55,257
	Asset retirement obligations	16,187			12,616
	Other	1,364			1,504
		$	167,736		$	163,375
Supplemental Cash Flow Disclosures	Supplemental disclosures to the consolidated statements of cash flows are presented below:
		Year Ended December 31,
		2014			2013			2012
		(in thousands)
	Cash payments for interest, net of amounts capitalized	$	542,775		$	392,607		$	343,331
	Cash payments for income taxes	$	—		$	14		$	366
	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	$	2,679,547		$	5,726,681		$	2,923,990
	Cash paid, net of cash acquired	(2,395,339		)	(109,350		)	(2,640,475		)
	Units issued in connection with the Berry acquisition	—			(2,781,888		)	—
	Noncash gains on exchanges of properties	(85,493		)	—			—
	Receivables from sellers	16,213			(93		)	2,132
	Payables to sellers	(3,515		)	(6,854		)	443
	Liabilities assumed	$	211,413		$	2,828,496		$	286,090
	Accrued capital expenditures	$	240,331		$	334,542		$	203,229

Subsidiary_Guarantors_Tables

Subsidiary Guarantors (Tables)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	CONDENSED CONSOLIDATING BALANCE SHEETS
	31-Dec-14
		LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
								Guarantor Subsidiary
		(in thousands)
	ASSETS
	Current assets:
	Cash and cash equivalents	$	38		$	185		$	1,586		$	—		$	1,809
	Accounts receivable – trade, net	—			371,325			100,359			—			471,684
	Accounts receivable – affiliates	4,028,890			13,205			—			(4,042,095		)	—
	Derivative instruments	—			1,033,448			43,694			—			1,077,142
	Other current assets	18			96,678			59,259			—			155,955
	Total current assets	4,028,946			1,514,841			204,898			(4,042,095		)	1,706,590
	Noncurrent assets:
	Oil and natural gas properties (successful efforts method)	—			13,196,841			4,872,059			—			18,068,900
	Less accumulated depletion and amortization	—			(4,342,675		)	(525,007		)	—			(4,867,682		)
		—			8,854,166			4,347,052			—			13,201,218
	Other property and equipment	—			553,150			115,999			—			669,149
	Less accumulated depreciation	—			(135,830		)	(8,452		)	—			(144,282		)
		—			417,320			107,547			—			524,867
	Derivative instruments	—			848,097			—			—			848,097
	Notes receivable – affiliates	130,500			—			—			(130,500		)	—
	Advance to affiliate	—			—			293,627			(293,627		)	—
	Investments in consolidated subsidiaries	8,562,608			—			—			(8,562,608		)	—
	Other noncurrent assets	116,637			11,816			14,284			—			142,737
		8,809,745			859,913			307,911			(8,986,735		)	990,834
	Total noncurrent assets	8,809,745			10,131,399			4,762,510			(8,986,735		)	14,716,919
	Total assets	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509
	LIABILITIES AND UNITHOLDERS’ CAPITAL
	Current liabilities:
	Accounts payable and accrued expenses	$	3,784		$	581,880		$	229,145		$	—		$	814,809
	Accounts payable – affiliates	—			4,028,890			13,205			(4,042,095		)	—
	Advance from affiliate	—			293,627			—			(293,627		)	—
	Derivative instruments	—			—			—			—			—
	Other accrued liabilities	89,507			59,142			19,087			—			167,736
	Total current liabilities	93,291			4,963,539			261,437			(4,335,722		)	982,545
	Noncurrent liabilities:
	Credit facilities	1,795,000			—			1,173,175			—			2,968,175
	Term loan	500,000			—			—			—			500,000
	Senior notes, net	5,913,857			—			913,777			—			6,827,634
	Notes payable – affiliates	—			130,500			—			(130,500		)	—
	Derivative instruments	—			684			—			—			684
	Other noncurrent liabilities	—			400,851			200,015			—			600,866
	Total noncurrent liabilities	8,208,857			532,035			2,286,967			(130,500		)	10,897,359
	Unitholders’ capital:
	Units issued and outstanding	5,388,749			4,831,339			2,416,381			(7,240,658		)	5,395,811
	Accumulated income (deficit)	(852,206		)	1,319,327			2,623			(1,321,950		)	(852,206		)
		4,536,543			6,150,666			2,419,004			(8,562,608		)	4,543,605
	Total liabilities and unitholders’ capital	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509
	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	8,433,290			—			—			(8,433,290		)	—
Other noncurrent assets	108,785			10,968			8,051			—			127,804
	8,628,275			690,459			10,562			(8,519,490		)	809,806
Total noncurrent assets	8,628,275			10,683,519			4,896,720			(8,519,490		)	15,689,024
Total assets	$	12,841,005		$	11,305,702		$	5,107,045		$	(12,748,788	)	$	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)	(400,397		)	1,313,526			(19,973		)	(1,293,553		)	(400,397		)
	5,882,350			6,146,880			2,295,487			(8,433,290		)	5,891,427
Total liabilities and unitholders’ capital	$	12,841,005		$	11,305,702		$	5,107,045		$	(12,748,788	)	$	16,504,964
Condensed Consolidating Statements of Operations	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
	For the Year Ended December 31, 2014
		LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
								Guarantor Subsidiary
		(in thousands)
	Revenues and other:
	Oil, natural gas and natural gas liquids sales	$	—		$	2,312,137		$	1,298,402		$	—		$	3,610,539
	Gains on oil and natural gas derivatives	—			1,127,395			78,784			—			1,206,179
	Marketing revenues	—			84,349			50,911			—			135,260
	Other revenues	—			28,133			3,192			—			31,325
		—			3,552,014			1,431,289			—			4,983,303
	Expenses:
	Lease operating expenses	—			440,624			364,540			—			805,164
	Transportation expenses	—			165,489			41,842			—			207,331
	Marketing expenses	—			81,210			36,255			—			117,465
	General and administrative expenses	—			190,286			102,787			—			293,073
	Exploration costs	—			125,037			—			—			125,037
	Depreciation, depletion and amortization	—			771,549			302,353			—			1,073,902
	Impairment of long-lived assets	—			2,050,387			253,362			—			2,303,749
	Taxes, other than income taxes	40			169,655			97,708			—			267,403
	(Gains) losses on sale of assets and other, net	—			(487,286		)	120,786			—			(366,500		)
		40			3,506,951			1,319,633			—			4,826,624
	Other income and (expenses):
	Interest expense, net of amounts capitalized	(480,259		)	(19,631		)	(87,948		)	—			(587,838		)
	Interest expense – affiliates	—			(7,954		)	—			7,954			—
	Interest income – affiliates	7,954			—			—			(7,954		)	—
	Equity in earnings from consolidated subsidiaries	28,397			—			—			(28,397		)	—
	Other, net	(7,861		)	(7,309		)	(1,043		)	—			(16,213		)
		(451,769		)	(34,894		)	(88,991		)	(28,397		)	(604,051		)
	Income (loss) before income taxes	(451,809		)	10,169			22,665			(28,397		)	(447,372		)
	Income tax expense	—			4,368			69			—			4,437
	Net income (loss)	$	(451,809	)	$	5,801		$	22,596		$	(28,397	)	$	(451,809	)
	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	—			52,328			1,843			—			54,171
	Other revenues	—			26,387			—			—			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			—
	Interest income – affiliates	5,543			—			—			(5,543		)	—
	Loss on extinguishment of debt	(5,304		)	—			—			—			(5,304		)
	Equity in losses from consolidated subsidiaries	(266,899		)	—			—			266,899			—
	Other, net	(8,283		)	(166		)	(28		)	—			(8,477		)
		(690,613		)	(7,213		)	(3,991		)	266,899			(434,918		)
	Loss before income taxes	(691,337		)	(249,125		)	(19,973		)	266,899			(693,536		)
	Income tax benefit	—			(2,199		)	—			—			(2,199		)
Net loss	$	(691,337	)	$	(246,926	)	$	(19,973	)	$	266,899		$	(691,337	)
Condensed Consolidating Statements of Cash Flow	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
	For the Year Ended December 31, 2014
		LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
								Guarantor Subsidiary
		(in thousands)
	Cash flow from operating activities:
	Net income (loss)	$	(451,809	)	$	5,801		$	22,596		$	(28,397	)	$	(451,809	)
	Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
	Depreciation, depletion and amortization	—			771,549			302,353			—			1,073,902
	Impairment of long-lived assets	—			2,050,387			253,362			—			2,303,749
	Unit-based compensation expenses	—			53,284			—			—			53,284
	Amortization and write-off of deferred financing fees	38,785			17,054			(4,913		)	—			50,926
	(Gains) losses on sale of assets and other, net	—			(372,945		)	111,374			—			(261,571		)
	Equity in earnings from consolidated subsidiaries	(28,397		)	—			—			28,397			—
	Deferred income tax	—			3,874			69			—			3,943
	Derivatives activities:
	Total gains	—			(1,127,395		)	(78,784		)	—			(1,206,179		)
	Cash settlements	—			88,776			6,738			—			95,514
	Cash settlements on canceled derivatives	—			—			12,281			—			12,281
	Changes in assets and liabilities:
	(Increase) decrease in accounts receivable – trade, net	—			(11,419		)	16,483			—			5,064
	Decrease in accounts receivable – affiliates	257,485			16,950			—			(274,435		)	—
	(Increase) decrease in other assets	312			(2,187		)	(15,949		)	—			(17,824		)
	Increase in accounts payable and accrued expenses	—			99,003			26			—			99,029
	Decrease in accounts payable and accrued expenses – affiliates	—			(270,690		)	(3,745		)	274,435			—
	Increase (decrease) in other liabilities	14,465			(24,473		)	(38,411		)	—			(48,419		)
	Net cash provided by (used in) operating activities	(169,159		)	1,297,569			583,480			—			1,711,890
	Cash flow from investing activities:
	Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	—			(2,475,315		)	(3,937		)	—			(2,479,252		)
	Development of oil and natural gas properties	—			(1,061,395		)	(508,482		)	—			(1,569,877		)
	Purchases of other property and equipment	—			(63,070		)	(11,470		)	—			(74,540		)
	Investment in affiliates	(100,921		)	—			—			100,921			—
	Change in notes receivable with affiliate	(44,300		)	—			—			44,300			—
	Proceeds from sale of properties and equipment and other	(14,117		)	2,210,015			7,667			—			2,203,565
	Net cash used in investing activities	(159,338		)	(1,389,765		)	(516,222		)	145,221			(1,920,104		)
		LINN Energy, LLC			Guarantor Subsidiaries			Non-			Eliminations			Consolidated
								Guarantor Subsidiary
		(in thousands)
	Cash flow from financing activities:
	Proceeds from borrowings	4,640,024			1,300,000			—			—			5,940,024
	Repayments of debt	(3,305,000		)	(1,300,000		)	(206,124		)	—			(4,811,124		)
	Distributions to unitholders	(962,048		)	—			—			—			(962,048		)
	Financing fees and offering expenses	(59,048		)	—			(10,646		)	—			(69,694		)
	Change in note payable with affiliate	—			44,300			—			(44,300		)	—
	Capital contribution – affiliates	—			—			100,921			(100,921		)	—
	Excess tax benefit from unit-based compensation	810			(44		)	—			—			766
	Other	13,745			47,047			(864		)	—			59,928
	Net cash provided by (used in) financing activities	328,483			91,303			(116,713		)	(145,221		)	157,852
	Net decrease in cash and cash equivalents	(14		)	(893		)	(49,455		)	—			(50,362		)
	Cash and cash equivalents:
	Beginning	52			1,078			51,041			—			52,171
	Ending	$	38		$	185		$	1,586		$	—		$	1,809
	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	$	(691,337	)	$	(246,926	)	$	(19,973	)	$	266,899		$	(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
Equity in losses from consolidated subsidiaries	266,899			—			—			(266,899		)	—
Deferred income taxes	—			(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 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 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 and offering expenses	(16,033		)	—			—			—			(16,033		)
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
Other	2,895			12,422			(4,272		)	—			11,045
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, 2014
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,
			2014				2013				2012
			(in thousands)
	Property acquisition costs: (1)
	Proved		$	2,784,852			$	3,740,379			$	2,531,419
	Unproved		788,682				1,638,302				181,124
	Exploration costs		792				13,096				452
	Development costs		1,487,204				1,153,770				1,062,043
	Asset retirement costs		20,919				7,351				4,675
	Total costs incurred		$	5,082,449			$	6,552,898			$	3,779,713
	(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,
			2014				2013
			(in thousands)
	Proved properties:
	Leasehold acquisition		$	13,362,642			$	12,277,089
	Development		2,830,841				3,660,277
	Unproved properties		1,875,417				1,951,193
			18,068,900				17,888,559
	Less accumulated depletion and amortization		(4,867,682		)		(3,546,284		)
			$	13,201,218			$	14,342,275
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,
			2014				2013				2012
			(in thousands)
	Revenues and other:
	Oil, natural gas and natural gas liquid sales		$	3,610,539			$	2,073,240			$	1,601,180
	Gains on oil and natural gas derivatives		1,206,179				177,857				124,762
			4,816,718				2,251,097				1,725,942
	Production costs:
	Lease operating expenses		805,164				372,523				317,699
	Transportation expenses		207,331				128,440				77,322
	Severance taxes, ad valorem taxes and California carbon allowances		267,100				139,202				130,805
			1,279,595				640,165				525,826
	Other costs:
	Exploration costs		125,037				5,251				1,915
	Depletion and amortization		1,020,674				790,320				579,382
	Impairment of long-lived assets		2,303,749				828,317				422,499
	Gains on sale of assets and other, net		(388,733		)		(138		)		(1,369		)
	Texas margin tax expense (benefit)		4,053				458				(787		)
			3,064,780				1,624,208				1,001,640
	Results of operations		$	472,343			$	(13,276	)		$	198,476
	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. See Note 14 for additional information about income taxes.
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, 2014
			Natural Gas			Oil			NGL			Total
			(Bcf)			(MMBbls)			(MMBbls)			(Bcfe)
	Proved developed and undeveloped reserves:
	Beginning of year		3,010			365.6			200			6,403
	Revisions of previous estimates		96			(22.3	)		(46.8	)		(318	)
	Purchases of minerals in place		1,763			50			71.9			2,495
	Sales of minerals in place		(477	)		(51.7	)		(49.5	)		(1,084	)
	Extensions, discoveries and other additions		72			26.8			2.9			250
	Production		(209	)		(26.6	)		(12.2	)		(442	)
	End of year		4,255			341.8			166.3			7,304
	Proved developed reserves:
	Beginning of year		2,027			252.4			133.2			4,340
	End of year		3,549			246			132.2			5,818
	Proved undeveloped reserves:
	Beginning of year		983			113.2			66.8			2,063
	End of year		706			95.8			34.1			1,486
			Year Ended December 31, 2013
			Natural Gas (Bcf)			Oil			NGL (MMBbls)			Total
						(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	)
	Purchases 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	)
	Purchases 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
	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; however, these amounts are not material. See Note 14 for additional information about income taxes.
			December 31,
			2014				2013				2012
			(in thousands)
	Future estimated revenues		$	55,195,268			$	51,112,346			$	30,374,380
	Future estimated production costs		(24,100,468		)		(19,306,728		)		(11,460,854		)
	Future estimated development costs		(4,032,588		)		(5,110,896		)		(3,574,058		)
	Future net cash flows		27,062,212				26,694,722				15,339,468
	10% annual discount for estimated timing of cash flows		(14,549,921		)		(14,795,393		)		(9,266,487		)
	Standardized measure of discounted future net cash flows		$	12,512,291			$	11,899,329			$	6,072,981
	Representative NYMEX prices: (1)
	Natural gas (MMBtu)		$	4.35			$	3.67			$	2.76
	Oil (Bbl)		$	95.27			$	96.89			$	94.64
	(1)	In accordance with SEC regulations, reserves at December 31, 2014, December 31, 2013, and December 31, 2012, 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,
			2014				2013				2012
			(in thousands)
	Sales and transfers of oil, natural gas and NGL produced during the period		$	(2,330,944	)		$	(1,433,075	)		$	(1,075,354	)
	Changes in estimated future development costs		156,614				317,064				289,762
	Net change in sales and transfer prices and production costs related to future production		(599,121		)		203,370				(1,463,820		)
	Purchases of minerals in place		3,021,768				5,113,335				2,153,651
	Sales of minerals in place		(1,681,504		)		(139,384		)		—
	Extensions, discoveries and improved recovery		910,787				801,254				413,702
	Previously estimated development costs incurred during the period		819,987				444,861				442,322
	Net change due to revisions in quantity estimates		(672,800		)		(220,224		)		(1,595,302		)
	Accretion of discount		1,189,933				607,298				661,486
	Changes in production rates and other		(201,758		)		131,849				(368,326		)
			$	612,962			$	5,826,348			$	(541,879	)

Supplemental_Quarterly_Data_Un1

Supplemental Quarterly Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Quarterly financial data	Quarterly Financial Data
			Quarters Ended
			31-Mar			30-Jun			30-Sep			December 31
			(in thousands, except per unit amounts)
	2014:00:00
	Oil, natural gas and natural gas liquid sales		$	938,877		$	967,850		$	937,458		$	766,354
	Gains (losses) on oil and natural gas derivatives		(241,493		)	(408,788		)	451,702			1,404,758
	Total revenues and other		733,587			596,951			1,435,115			2,217,650
	Total expenses (1)		674,568			664,452			1,320,157			2,533,947
	(Gains) losses on sale of assets and other, net		2,586			5,467			(35,803		)	(338,750		)
	Net loss		(85,337		)	(207,870		)	(4,100		)	(154,502		)
	Net loss per unit:
	Basic		$	(0.27	)	$	(0.64	)	$	(0.02	)	$	(0.47	)
	Diluted		$	(0.27	)	$	(0.64	)	$	(0.02	)	$	(0.47	)
			Quarters Ended
			31-Mar			30-Jun			30-Sep			December 31
			(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
	(Gains) 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.

Basis_of_Presentation_and_Sign2

Basis of Presentation and Significant Accounting Policies (Details) (USD $)	3 Months Ended		12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Allowance for doubtful accounts				$1,000,000
Capitalized interest costs			9,000,000	2,000,000	2,000,000
Natural gas production imbalance payables	13,000,000		13,000,000	16,000,000
Restricted cash	6,000,000		6,000,000	6,000,000
Net deferred financing fees	129,000,000		129,000,000	114,000,000
Debt issuance fees amortization expense			46,000,000	18,000,000	13,000,000
Write-off of deferred financing fees			8,000,000	0	8,000,000
Statement [Line Items]
Gas Balancing Asset (Liability)	17,000,000		17,000,000	27,000,000
Impairment of long-lived assets	1,700,000,000	603,000,000	2,303,749,000	828,317,000	422,499,000
Decline in oil prices	24.00%
Decline in gas prices	12.00%
Impairment Of Unproved Oil And Gas Properties			125,000,000	5,000,000	2,000,000
Minimum [Member]
Statement [Line Items]
Useful lives of other property and equipment (in years)			2 years
Maximum [Member]
Statement [Line Items]
Useful lives of other property and equipment (in years)			39 years
Permian Basin [Member]
Statement [Line Items]
Impairment of long-lived assets	735,000,000
Rockies [Member]
Statement [Line Items]
Impairment of long-lived assets	586,000,000
Mid-Continent [Member]
Statement [Line Items]
Impairment of long-lived assets	244,000,000			791,000,000
South Texas [Member]
Statement [Line Items]
Impairment of long-lived assets	131,000,000
TexLa [Member]
Statement [Line Items]
Impairment of long-lived assets	$5,000,000

Exchanges_of_Properties_Acquis2

Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding (Acquisitions, Joint-Venture Funding) (Details) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2014	Jul. 31, 2012	1-May-12	Apr. 03, 2012	Mar. 30, 2012	Dec. 31, 2013	Oct. 31, 2013
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$2,468,134,000
Term loan	500,000,000					500,000,000
Pioneer Assets Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	328,000,000
Devon Assets Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	2,100,000,000
Business Acquisition, Permian, BC Operating
Business Acquisition [Line Items]
Term loan							528,000,000
Business Acquisition Various
Business Acquisition [Line Items]
Business Combination, Consideration Transferred	5,000,000
Business Acquisition BP Green River
Business Acquisition [Line Items]
Business Combination, Consideration Transferred		988,000,000
Business Acquisition East Texas
Business Acquisition [Line Items]
Business Combination, Consideration Transferred			164,000,000
Business Acquisition Anadarko
Business Acquisition [Line Items]
Joint Venture Interest Acquired				23.00%
Imputed discount on future funding of joint venture				8,000,000
Future funding commitment of joint venture consideration transferred	25,000,000
Future Funding Of Joint Venture Agreement				400,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net				392,000,000
Business Acquisition BP
Business Acquisition [Line Items]
Business Combination, Consideration Transferred					$1,170,000,000

Exchanges_of_Properties_Acquis3

Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding Purchase Price (Details) (Business Acquisition, Berry, USD $)	0 Months Ended
	Dec. 17, 2013	Dec. 16, 2013
Business Acquisition [Line Items]
Cash acquired		$451,000,000
Exchange ratio	168.00%
Preliminary value of acquisition	4,600,000,000
Long-term debt assumed		$2,300,000,000
Linn Energy, LLC
Business Acquisition [Line Items]
LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674
LinnCo
Business Acquisition [Line Items]
LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674

Exchanges_of_Properties_Acquis4

Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding (Purchase Price Allocation) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Assets:
Current	$26,007
Oil and natural gas properties	2,532,439
Other property and equipment	121,101
Total assets acquired	2,679,547
Liabilities:
Current	21,976
Asset retirement obligations, current and noncurrent	171,057
Noncurrent	18,380
Total liabilities assumed	211,413
Net assets acquired	$2,468,134

Exchanges_of_Properties_Acquis5

Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding (Pro Forma Financial Information) (Details) (USD $)	12 Months Ended		0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 17, 2013
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Debt Instrument, Face Amount	$2,300,000,000
Business Acquisition Pro Forma Results of Operations
Total revenues and other	5,335,442,000	3,973,605,000
Total operating expenses	5,039,311,000	3,711,868,000
Net loss	($403,447,000)	($397,070,000)
Net loss per unit:
Basic	($1.25)	($1.22)
Diluted	($1.25)	($1.22)
Devon Assets Acquisition [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Useful lives of other property and equipment (in years)	10 years
Business Acquisition, Berry
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Useful lives of other property and equipment (in years)	20 years
Linn Energy, LLC | Business Acquisition, Berry
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
LINN Energy units issued to LinnCo for LinnCo common shares issued			93,756,674

Exchanges_of_Properties_Acquis6

Exchanges of Properties, Acquisitions, Divestitures and Joint-Venture Funding (Divestiture) (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Assets	($338,750,000)	($35,803,000)	$5,467,000	$2,586,000	$10,597,000	$827,000	($959,000)	$3,172,000	$366,500,000	($13,637,000)	($1,539,000)
Gain (Loss) on Disposition of Oil and Gas Property									85,493,000	0	0
XOM II Exchange [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Assets									20,000,000
Costs Associated With Sale of Oil and Gas Property and Equipment									3,000,000
XOM I Exchange [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Assets									65,000,000
Costs Associated With Sale of Oil and Gas Property and Equipment									3,000,000
Granite Wash Assets Sale [Member]
Business Acquisition [Line Items]
Costs Associated With Sale of Oil and Gas Property and Equipment									10,000,000
Gain (Loss) on Disposition of Oil and Gas Property									294,000,000
Proceeds from sale of oil and natural gas property									1,800,000,000
Permian Basin Assets Sale [Member]
Business Acquisition [Line Items]
Costs Associated With Sale of Oil and Gas Property and Equipment									2,000,000
Gain (Loss) on Disposition of Oil and Gas Property									-28,000,000
Proceeds from sale of oil and natural gas property									351,000,000
STACK acreage divestiture [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Oil and Gas Property									36,000,000
Proceeds from sale of oil and natural gas property									44,000,000
Panther Properties Sale [Member]
Business Acquisition [Line Items]
Costs Associated With Sale of Oil and Gas Property and Equipment										2,000,000
Proceeds from sale of oil and natural gas property										218,000,000
Impairment of Long-Lived Assets to be Disposed of										$37,000,000

Unitholders_Capital_Details

Unitholders' Capital (Details) (USD $)	1 Months Ended	3 Months Ended	12 Months Ended	0 Months Ended		1 Months Ended		3 Months Ended	6 Months Ended
	Jan. 31, 2012	Dec. 31, 2014	Dec. 31, 2014	Oct. 17, 2012	Dec. 17, 2013	Feb. 28, 2015	Jan. 31, 2015	Mar. 31, 2015	Mar. 31, 2015	Dec. 16, 2013
Subsequent Event [Line Items]
Per unit cash dividend paid (in dollars per unit)		$0.73
Related Party Transaction [Line Items]
Public offering underwriting discount and offering expenses	$28,000,000
Public Offering of Units [Abstract]
Public offering units sold	19,550,000
Public offering price per unit	$35.95
Public offering price per unit, net of underwriting discount	$34.51
Public offering net proceeds	674,000,000
Public offering underwriting discount and offering expenses	28,000,000
Equity Distribution Agreement [Abstract]
Equity distribution agreement maximum value			500,000,000
Equity distribution agreement professional service expenses	700,000
Equity distribution agreement units sold	1,539,651
Equity distribution agreement price per unit sold	$38.02
Equity distribution agreement net proceeds	57,000,000
Equity Distribution Agreement Commissions And Professional Service Expenses	1,000,000
Unit Repurchase Plan [Abstract]
Authorized repurchase value of units		250,000,000	250,000,000
LinnCo
Related Party Transaction [Line Items]
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				57,000,000
Units of LINN Energy acquired				34,787,500
Public Offering of Units [Abstract]
Public offering underwriting discount and offering expenses				57,000,000
Berry
Related Party Transaction [Line Items]
Exchange ratio					168.00%
Berry | Linn Energy, LLC
Related Party Transaction [Line Items]
LinnCo common shares issued to acquire Berry					93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued					93,756,674
Value of units issued to acquire Berry										2,800,000,000
Berry | LinnCo
Related Party Transaction [Line Items]
LinnCo common shares issued to acquire Berry					93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued					93,756,674
Subsequent Event [Member]
Subsequent Event [Line Items]
Per unit cash dividend paid (in dollars per unit)								$0.31
Common Stock, Dividends, Per Share, Declared, Monthly (in dollars per unit)							$0.10
Change in distributions declared									57.00%
Distribution paid during period						$35,000,000	$35,000,000

Business_and_Credit_Concentrat1

Business and Credit Concentrations (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Sales [Member] | Customer Concentration Risk [Member]
Concentration Risk [Line Items]
Total number of largest customers represented in sales			2
Customer 1 [Member] | Sales [Member] | Customer Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)	14.00%	12.00%	12.00%
Customer 2 [Member] | Sales [Member] | Customer Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)			11.00%
Credit Risk [Member] | Accounts Receivable [Member]
Concentration Risk [Line Items]
Total number of largest customers represented in sales	1	2
Credit Risk [Member] | Customer 1 [Member] | Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)	11.00%	19.00%
Credit Risk [Member] | Customer 2 [Member] | Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)		14.00%

UnitBased_Compensation_and_Oth2

Unit-Based Compensation and Other Benefit Plans (Details) (USD $)	12 Months Ended			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 2014	Dec. 16, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Berry employee unit-based awards					$19,000,000
Number of shares available for grant (in units)	4,700,000
Units authorized for issuance (in units)	8,300,000
Units reserved for future issuance (in units)	4,700,000
Share-based Compensation [Abstract]
Allocated Share Based Compensation	53,284,000	42,703,000	29,533,000
Income tax benefit	19,688,000	15,779,000	10,912,000
Weighted Average Exercise Price Per Unit [Abstract]
Forfeited or expired (in dollars per unit)	$40.01
Change in Unit Options and Unit Options Outstanding [Abstract]
Expected volatility			34.10%
Expected volatility		29.65%
Expected volatility		50.88%
Expected distributions		9.84%	7.25%
Risk-free rate			0.67%
Risk-free rate		0.13%
Risk-free rate		1.55%
Expected term			5 years
Defined Contribution Plan [Abstract]
Entity's matching contribution (in hundredths)	100.00%
Participant's eligible contribution, (in hundredths)	6.00%
Defined Contribution Plan, Cost Recognized	10,000,000	7,000,000	5,000,000
General and Administrative Expense [Member]
Share-based Compensation [Abstract]
Allocated Share Based Compensation	45,195,000	37,375,000	27,641,000
Lease Operating Expense [Member]
Share-based Compensation [Abstract]
Allocated Share Based Compensation	8,089,000	5,328,000	1,892,000
Unit Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vesting period (in years)	3 years
Contractual life of unit options (in years)	10 years
Restricted/Unrestricted Units [Abstract]
Unrecognized compensation cost	4,000,000
Unrecognized compensation cost recognition period (in years)	1 year 1 month 1 day
Unit Options Activity [Roll Forward]
Outstanding, beginning (in units)	5,444,417	6,433,223
Exercised (in units)	-813,806
Forfeited or expired (in units)	-175,000
Outstanding, ending (in units)	5,444,417	6,433,223
Exercisable (in units)	2,510,457
Weighted Average Exercise Price Per Unit [Abstract]
Outstanding, beginning (in dollars per unit)	$31.95	$30.22
Exercised (in dollars per unit)	$16.56
Outstanding, ending (in dollars per unit)	$31.95	$30.22
Exercisable (in dollars per unit)	$22.57
Weighted Average Remaining Contractual Life in Years [Abstract]
Outstanding, beginning (in years)	5 years 1 month 12 days	6 years 7 months 28 days
Outstanding, ending (in years)	5 years 1 month 12 days	6 years 7 months 28 days
Exercisable (in years)	5 years 6 months 0 days
Weighted Average Grant Date Fair Value Per Unit [Abstract]
Weighted average grant date fair value of options granted (in dollars per unit)		$7.52
Change in Unit Options and Unit Options Outstanding [Abstract]
Weighted average grant date fair value of options granted (in dollars per unit)		$7.52
Intrinsic value of options exercised	11,000,000	2,000,000	3,000,000
Proceeds from exercise of unit warrants	13,000,000
Unrecognized compensation cost	4,000,000
Unrecognized compensation cost recognition period (in years)	1 year 1 month 1 day
Intrinsic value of outstanding unit options	0	33
Intrinsic value of exercisable unit options	0
Unit Options [Member] | Nonemployee [Member]
Nonemployee Grants [Abstract]
Unit warrants oustanding (in units)	15,000
Exercise price of unit warrants (in dollars per unit)	$25.50
Restricted Unrestricted Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant (in units)	21,000,000
Units reserved for future issuance (in units)	21,000,000
Restricted/Unrestricted Nonvested Units [Roll Forward]
Granted (in dollars per unit)		$30.71	$37.42
Performance Units [Member]
Restricted/Unrestricted Nonvested Units [Roll Forward]
Granted (in units)				283,660
Restricted/Unrestricted Units [Abstract]
Granted (in units)				283,660
Restricted Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vesting period (in years)		3 years
Restricted/Unrestricted Nonvested Units [Roll Forward]
Nonvested units, beginning (in units)	2,838,973	2,571,410
Granted (in units)	1,789,038			3,468,245
Vested (in units)	-1,282,509
Forfeited (in units)	-238,966
Nonvested units, ending (in units)	2,838,973	2,571,410
Outstanding, beginning (in dollars per unit)	$32.70	$33.14
Granted (in dollars per unit)	$33.10
Vested (in dollars per unit)	$32.77
Forfeited (in dollars per unit)	$32.25
Outstanding, ending (in dollars per unit)	$32.70	$33.14
Restricted/Unrestricted Units [Abstract]
Fair value of units vested	42,000,000	31,000,000	24,000,000
Unrecognized compensation cost	40,000,000
Unrecognized compensation cost recognition period (in years)	1 year 7 months 6 days
Granted (in units)	1,789,038			3,468,245
Change in Unit Options and Unit Options Outstanding [Abstract]
Unrecognized compensation cost	$40,000,000
Unrecognized compensation cost recognition period (in years)	1 year 7 months 6 days
Phantom Share Units (PSUs) [Member]
Restricted/Unrestricted Nonvested Units [Roll Forward]
Granted (in units)				697,120
Restricted/Unrestricted Units [Abstract]
Granted (in units)				697,120
Minimum [Member]
Change in Unit Options and Unit Options Outstanding [Abstract]
Expected term		0 years 8 months 5 days
Maximum [Member]
Change in Unit Options and Unit Options Outstanding [Abstract]
Expected term		5 years
Tranche One | Unit Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vesting period (in years)	2 years
Award vesting rights	50.00%
Tranche Two | Unit Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vesting period (in years)	3 years
Award vesting rights	50.00%

Debt_Details

Debt (Details) (USD $)	12 Months Ended					3 Months Ended		0 Months Ended	4 Months Ended		3 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Mar. 31, 2013	Mar. 31, 2014	Sep. 08, 2014	Dec. 31, 2014		Dec. 15, 2014	Sep. 09, 2014	Aug. 29, 2014	Jun. 30, 2014	Oct. 30, 2013
Debt Instrument [Line Items]
Term loan	$500,000,000		$500,000,000						$500,000,000
Debt Instrument, Face Amount	2,300,000,000								2,300,000,000
Additional Interest Due To Late Registration	15,000,000								15,000,000
Long-term Debt, Fair Value	9,171,824,000		9,395,577,000						9,171,824,000
Loss on extinguishment of debt	0		5,304,000		0
Percent of future net income allowable to increase Berry's restricted payments basket	0.5								0.5
Line of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	4,500,000,000								4,500,000,000
Line of Credit Facility, Current Borrowing Capacity	4,000,000,000								4,000,000,000
Percent Reduction of Borrowing Base Under Credit Facility													25.00%
Reduction of Borrowing Base Under Line of Credit												25,000,000	250,000,000
Redetermined Borrowing Base Under Line Of Credit												4,225,000,000	4,250,000,000	4,500,000,000
Reduction of Maximum Borrowing Capacity Under Line of Credit												25,000,000	250,000,000
Senior Notes [Member] | Senior Notes Due November 2019
Debt Instrument [Line Items]
Number of days for effective registration statement						400 days
Berry | Line of Credit | Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End			2.67%
Line of Credit Facility, Maximum Borrowing Capacity	1,400,000,000								1,400,000,000
Line of Credit Facility, Current Borrowing Capacity	1,200,000,000								1,200,000,000
Line of Credit Facility, Remaining Borrowing Capacity	1,000,000								1,000,000
The percentage of properties that the company is required to maintain mortgages on (in hundredths)	80.00%
Berry | Line of Credit | Credit Facility | Minimum [Member]
Debt Instrument [Line Items]
Line of credit facility unused capacity commitment fee percentage (in hundredths)			0.38%
Berry | Line of Credit | Credit Facility | Maximum [Member]
Debt Instrument [Line Items]
Line of credit facility unused capacity commitment fee percentage (in hundredths)			0.50%
Berry | Senior Notes [Member] | Senior Notes Due 2014
Debt Instrument [Line Items]
Debt Instrument, Face Amount	205,000,000								205,000,000
Extinguishment of Debt, Amount							321,000
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)							10.25%
Berry | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Debt Instrument, Face Amount	300,000,000								300,000,000
Extinguishment of Debt, Amount							30,000
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	6.75%								6.75%
Long-term Debt, Fair Value	310,000,000								310,000,000
Debt Instrument, Unamortized Premium	10,000,000								10,000,000
Berry | Senior Notes [Member] | Senior Notes Due 2022
Debt Instrument [Line Items]
Debt Instrument, Face Amount	599,000,000								599,000,000
Extinguishment of Debt, Amount							837,000
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	6.38%								6.38%
Long-term Debt, Fair Value	607,000,000								607,000,000
Debt Instrument, Unamortized Premium	7,000,000								7,000,000
Linn Energy, LLC | Line of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	4,500,000,000								4,500,000,000
Line of Credit Facility, Current Borrowing Capacity	4,000,000,000								4,000,000,000
Line of Credit Facility, Remaining Borrowing Capacity	2,200,000,000								2,200,000,000
Outstanding letters of credit that reduce the credit facility availability	5,000,000								5,000,000
Linn Energy, LLC | Line of Credit | Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End			1.92%
The percentage of properties that the company is required to maintain mortgages on (in hundredths)	80.00%
Line Of Credit Facility Collateral Coverage Ratio	2.5								2.5
Linn Energy, LLC | Line of Credit | Credit Facility | Minimum [Member]
Debt Instrument [Line Items]
Line of credit facility unused capacity commitment fee percentage (in hundredths)			0.38%
Linn Energy, LLC | Line of Credit | Credit Facility | Maximum [Member]
Debt Instrument [Line Items]
Line of credit facility unused capacity commitment fee percentage (in hundredths)			0.50%
Linn Energy, LLC | Loans Payable
Debt Instrument [Line Items]
Term loan	500,000,000	[1]	500,000,000	[1]					500,000,000	[1]
Linn Energy, LLC | Loans Payable | Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End	2.66%		2.67%						2.66%
The percentage of properties that the company is required to maintain mortgages on (in hundredths)	80.00%
Line Of Credit Facility Collateral Coverage Ratio	2.5								2.5
Debt Instrument, Basis Spread on Variable Rate								0.00%
Debt Instrument, Increase in Basis Spread on Variable Rate								0.50%
Long-term Debt, Gross															500,000,000
Bridge Loan													1,000,000,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021 and May 2019
Debt Instrument [Line Items]
Debt Instrument, Face Amount												1,100,000,000
Debt Issuance Cost									22,000,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2017
Debt Instrument [Line Items]
Debt Instrument, Face Amount	41,000,000								41,000,000
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	11.75%								11.75%
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2018
Debt Instrument [Line Items]
Debt Instrument, Face Amount	14,000,000								14,000,000
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	9.88%								9.88%
Linn Energy, LLC | Senior Notes [Member] | Original Senior Notes
Debt Instrument [Line Items]
Loss on extinguishment of debt	-5,000,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due May 2019
Debt Instrument [Line Items]
Debt Instrument, Face Amount	750,000,000								750,000,000
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	6.50%								6.50%			6.50%
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due November 2019
Debt Instrument [Line Items]
Debt Instrument, Face Amount	1,800,000,000								1,800,000,000
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	6.25%								6.25%
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Debt Instrument, Face Amount	1,300,000,000								1,300,000,000
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	8.63%								8.63%
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2021
Debt Instrument [Line Items]
Debt Instrument, Face Amount	1,000,000,000								1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)	7.75%								7.75%
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021
Debt Instrument [Line Items]
Debt Instrument, Face Amount	650,000,000								650,000,000			650,000,000
Debt Instrument, Interest Rate, Stated Percentage (in hundredths)												6.50%
Maximum Percentage of September 2021 Senior Notes Redeemable On or Before 2017									35.00%
Issue Price of Debt Instruments as a Percentage of Face Amount												98.62%
Proceeds from Debt, Net of Issuance Costs									628,000,000
Debt Instrument, Unamortized Discount												9,000,000
Debt Issuance Cost									13,000,000
Variable Interest Entity, Primary Beneficiary [Member] | Loans Payable
Debt Instrument [Line Items]
Equity in Subsidiaries Pledged to Secure Debt											100.00%
The percentage of properties that the company is required to maintain mortgages on (in hundredths)											80.00%
Term loan													1,300,000,000
2014 [Member] | Senior Notes [Member] | Senior Notes Due September 2021 and May 2019
Debt Instrument [Line Items]
Debt Instrument, Face Amount												1,100,000,000
2014 [Member] | Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due May 2019
Debt Instrument [Line Items]
Debt Instrument, Face Amount	450,000,000								450,000,000			450,000,000
Issue Price of Debt Instruments as a Percentage of Face Amount												102.00%
Proceeds from Debt, Net of Issuance Costs									450,000,000
Debt Instrument, Unamortized Premium												9,000,000
Debt Issuance Cost									$9,000,000
London Interbank Offered Rate (LIBOR) [Member] | Berry | Line of Credit | Credit Facility | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
London Interbank Offered Rate (LIBOR) [Member] | Berry | Line of Credit | Credit Facility | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
London Interbank Offered Rate (LIBOR) [Member] | Linn Energy, LLC | Line of Credit | Credit Facility | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
London Interbank Offered Rate (LIBOR) [Member] | Linn Energy, LLC | Line of Credit | Credit Facility | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
London Interbank Offered Rate (LIBOR) [Member] | Linn Energy, LLC | Loans Payable | Credit Facility
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate								5.00%
London Interbank Offered Rate (LIBOR) [Member] | Linn Energy, LLC | Loans Payable | Credit Facility | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
ABR [Member] | Berry | Line of Credit | Credit Facility | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
ABR [Member] | Berry | Line of Credit | Credit Facility | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
ABR [Member] | Linn Energy, LLC | Line of Credit | Credit Facility | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
ABR [Member] | Linn Energy, LLC | Line of Credit | Credit Facility | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
ABR [Member] | Linn Energy, LLC | Loans Payable | Credit Facility
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate								4.00%
ABR [Member] | Linn Energy, LLC | Loans Payable | Credit Facility | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Debt Instrument, Redemption, Period One [Member] | Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due May 2019
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	103.25%
Redemption Price of Senior Notes for Change of Control	101.00%
Debt Instrument, Redemption, Period One [Member] | Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage									106.50%
Redemption Price of Senior Notes for Change of Control	101.00%
Debt Instrument, Redemption, Period Two [Member] | Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage									103.25%
[1]	Variable interest rates of 2.66% and 2.67% at December 31, 2014 and December 31, 2013, respectively.

Debt_Schedule_of_LongTerm_Debt

Debt Schedule of Long-Term Debt (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Instrument [Line Items]
Credit facilities	$2,968,175		$2,733,175
Term loan	500,000		500,000
Senior notes, net	6,827,634		5,937,041
Total debt, net	10,295,809		9,170,216
Less current maturities	0		-211,558
Total long-term debt, net	10,295,809		8,958,658
Senior Notes [Member]
Debt Instrument [Line Items]
Net unamortized discounts and premiums	21,499		18,216
Linn Energy, LLC | Line of Credit
Debt Instrument [Line Items]
Credit facilities	1,795,000	[1]	1,560,000	[1]
Linn Energy, LLC | Loans Payable
Debt Instrument [Line Items]
Term loan	500,000	[2]	500,000	[2]
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due May 2019
Debt Instrument [Line Items]
Senior notes, net	1,200,000	[3]	750,000	[3]
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due November 2019
Debt Instrument [Line Items]
Senior notes, net	1,800,000		1,800,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Senior notes, net	1,300,000		1,300,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2021
Debt Instrument [Line Items]
Senior notes, net	1,000,000		1,000,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021
Debt Instrument [Line Items]
Senior notes, net	650,000	[3]	0	[3]
Berry | Line of Credit
Debt Instrument [Line Items]
Credit facilities	1,173,175	[4]	1,173,175	[4]
Berry | Senior Notes [Member] | Senior Notes Due 2014
Debt Instrument [Line Items]
Senior notes, net	0		205,257
Berry | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Senior notes, net	299,970		300,000
Berry | Senior Notes [Member] | Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes, net	$599,163		$600,000
[1]	Variable interest rate of 1.92% at both December 31, 2014, and December 31, 2013.
[2]	Variable interest rates of 2.66% and 2.67% at December 31, 2014 and December 31, 2013, respectively.
[3]	of senior notes due May 2019 and $650 million of senior notes due September 2021 were issued on September 9, 2014.
[4]	Variable interest rate of 2.67% at both December 31, 2014, and December 31, 2013.

Debt_Debt_Fair_Value_Disclosur

Debt Debt Fair Value Disclosure (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Carrying Value
Credit facilities	$2,968,175	$2,733,175
Term loan	500,000	500,000
Senior notes, net	6,827,634	5,937,041
Total debt, net	10,295,809	9,170,216
Fair Value
Credit facilities	2,968,175	2,733,175
Term loan	500,000	500,000
Senior notes, net	5,703,649	6,162,402
Total debt, net	$9,171,824	$9,395,577

Derivatives_Commodity_Derivati

Derivatives (Commodity Derivatives) (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
	MMMBTU		MBbls	MMMBTU
	MBbls		MMMBTU	MBbls
Derivative [Line Items]
Volumes of natural gas production on settled derivatives (in MMMbtu)	177,029		173,488	140,884
Average contract price per MMBtu on settled derivatives	5.14		5.29	5.41
Volumes of oil production on settled derivatives (in MBbls)	24,988		15,590	11,289
Average contract price per barrel on settled derivatives	92.39		95.35	97.61
2015 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	118,041
Average Fixed Price (in usd per energy unit)	5.19
2015 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	71,854	[1]
Average Price (in usd per energy unit)	5	[1]
2015 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	11,599	[2]
Average Fixed Price (in usd per energy unit)	96.23	[2]
2015 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	3,426
Average Price (in usd per energy unit)	90
2015 | Oil Derivative Instruments | Three-way collars (NYMEX WTI)
Derivative [Line Items]
Hedged Volume (in energy unit)	1,095
2015 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short
Derivative [Line Items]
Derivative, Floor Price (in usd per energy unit)	70
Short Call (in usd per energy unit)	101.62
2015 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long
Derivative [Line Items]
Derivative, Floor Price (in usd per energy unit)	90
2015 | Natural Gas Basis Differential Positions | Panhandle basis swaps
Derivative [Line Items]
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]
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]
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]
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]
Hedged Volume (in energy unit)	5,074	[3]
Hedged Differential (in usd per energy unit)	-0.21	[3]
2015 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	7,251
Hedged Differential (in usd per energy unit)	0.24
2016 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	121,841
Average Fixed Price (in usd per energy unit)	4.2
2016 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	76,269	[1]
Average Price (in usd per energy unit)	5	[1]
2016 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	11,465	[2]
Average Fixed Price (in usd per energy unit)	90.56	[2]
2016 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	3,271
Average Price (in usd per energy unit)	90
2016 | Oil Derivative Instruments | Three-way collars (NYMEX WTI)
Derivative [Line Items]
Hedged Volume (in energy unit)	0
2016 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short
Derivative [Line Items]
Derivative, Floor Price (in usd per energy unit)	0
Short Call (in usd per energy unit)	0
2016 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long
Derivative [Line Items]
Derivative, Floor Price (in usd per energy unit)	0
2016 | Natural Gas Basis Differential Positions | Panhandle basis swaps
Derivative [Line Items]
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]
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]
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]
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]
Hedged Volume (in energy unit)	4,219	[3]
Hedged Differential (in usd per energy unit)	-0.2	[3]
2016 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	7,446
Hedged Differential (in usd per energy unit)	0.25
2017 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	120,122
Average Fixed Price (in usd per energy unit)	4.26
2017 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	66,886	[1]
Average Price (in usd per energy unit)	4.88	[1]
2017 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	4,755	[2]
Average Fixed Price (in usd per energy unit)	89.02	[2]
2017 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	384
Average Price (in usd per energy unit)	90
2017 | Oil Derivative Instruments | Three-way collars (NYMEX WTI)
Derivative [Line Items]
Hedged Volume (in energy unit)	0
2017 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short
Derivative [Line Items]
Derivative, Floor Price (in usd per energy unit)	0
Short Call (in usd per energy unit)	0
2017 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long
Derivative [Line Items]
Derivative, Floor Price (in usd per energy unit)	0
2017 | Oil Derivative Instruments | Extendible Fixed Price Swaps
Derivative [Line Items]
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]
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]
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]
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]
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]
Hedged Volume (in energy unit)	4,819	[3]
Hedged Differential (in usd per energy unit)	-0.2	[3]
2017 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	6,486
Hedged Differential (in usd per energy unit)	0.25
2018 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	36,500
Average Fixed Price (in usd per energy unit)	5
2018 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[1]
Average Price (in usd per energy unit)	0	[1]
2018 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[2]
Average Fixed Price (in usd per energy unit)	0	[2]
2018 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	0
Average Price (in usd per energy unit)	0
2018 | Oil Derivative Instruments | Three-way collars (NYMEX WTI)
Derivative [Line Items]
Hedged Volume (in energy unit)	0
2018 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Short
Derivative [Line Items]
Derivative, Floor Price (in usd per energy unit)	0
Short Call (in usd per energy unit)	0
2018 | Oil Derivative Instruments | Three-way collars (NYMEX WTI) | Long
Derivative [Line Items]
Derivative, Floor Price (in usd per energy unit)	0
2018 | Oil Derivative Instruments | Extendible Fixed Price Swaps
Derivative [Line Items]
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]
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]
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]
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]
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]
Hedged Volume (in energy unit)	1,314	[3]
Hedged Differential (in usd per energy unit)	-0.2	[3]
2018 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	0
Hedged Differential (in usd per energy unit)	0
2019 | Oil Derivative Instruments | Extendible Fixed Price Swaps
Derivative [Line Items]
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 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.
[2]	Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.
[3]	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”).

Derivatives_Balance_Sheet_Pres

Derivatives (Balance Sheet Presentation) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Assets:
Commodity derivatives	$2,014,815,000	$1,048,212,000
Liabilities:
Commodity derivatives	90,260,000	222,905,000
Maximum Loss Upon All Counterparties Failing To Perform	$2,000,000,000

Derivatives_Gains_Losses_On_De

Derivatives (Gains (Losses) On Derivatives) (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash settlements on canceled derivatives									$12,281,000	$0	$0
Gains on oil and natural gas derivatives	1,404,758,000	451,702,000	-408,788,000	-241,493,000	23,425,000	-63,931,000	326,733,000	-108,370,000	1,206,179,000	177,857,000	124,762,000
Cash Settlements On Derivatives including canceled derivatives									108,000,000	249,000,000	391,000,000
Premiums paid for derivatives									$0	$0	$583,434,000

Fair_Value_Measurements_on_a_R2

Fair Value Measurements on a Recurring Basis (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Assets:
Commodity derivatives	$2,014,815		$1,048,212
Commodity derivatives	-89,576	[1]	-190,080	[1]
Commodity derivatives	1,925,239		858,132
Liabilities:
Commodity derivatives	90,260		222,905
Commodity derivatives	-89,576	[1]	-190,080	[1]
Commodity derivatives	$684		$32,825
[1]	Represents counterparty netting under agreements governing such derivatives.

Other_Property_and_Equipment_D

Other Property and Equipment (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]
Other property and equipment	$669,149	$647,882
Less accumulated depreciation	-144,282	-110,939
Other property and equipment, net	524,867	536,943
Gas Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	479,754	507,342
Building and Building Improvements [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	49,046	32,658
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	36,534	27,964
Upstream Equipment [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	6,994	8,618
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	88,893	65,909
Land [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	$7,928	$5,391

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	5.30%	6.20%	6.80%
Asset retirement obligations rollforward
Asset retirement obligations at beginning of year	$289,321	$151,974
Liabilities added from acquisitions	176,538	98,343
Liabilities added from drilling	10,476	4,048
Liabilities associated with assets divested	-25,656	-1,092
Current year accretion expense	22,164	11,938
Settlements	-12,620	-5,136
Revision of estimates	37,347	29,246
Asset retirement obligations at end of year	$497,570	$289,321	$151,974

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	1 Months Ended	12 Months Ended			36 Months Ended
	Mar. 31, 2011	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Loss Contingencies [Line Items]
Litigation Settlement, Amount		$2,400,000
Payments for Legal Settlements		2,400,000
Material payments for legal, environmental, or tax settlements		0
Amount of general unsecured claims from termination agreements	51,000,000
Distribution received under termination agreement		7,000,000	11,000,000	28,000,000	46,000,000
Recovery of bankruptcy claim included in gains (losses) on oil and natural gas derivatives				$22,000,000

Earnings_Per_Unit_Details

Earnings Per Unit (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]
Net loss	($451,809)	($691,337)	($386,616)
Allocated to participating securities	-7,117	-5,935	-4,575
Net loss attributable to common unitholders	($458,926)	($697,272)	($391,191)
Earnings per share reconciliation
Basic net loss per unit	($1.40)	($2.94)	($1.92)
Diluted net loss per unit	($1.40)	($2.94)	($1.92)
Weighted average units outstanding
Basic weighted average units outstanding	328,918,000	237,544,000	203,775,000
Dilutive effect of unit equivalents	0	0	0
Diluted weighted average units outstanding	328,918,000	237,544,000	203,775,000
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)	6,000,000	4,000,000	2,000,000

Operating_Leases_Details

Operating Leases (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Leases, Operating [Abstract]
Operating lease expense	$14,000,000	$7,000,000	$7,000,000
Future Minimum Lease Payments [Abstract]
2015	13,265,000
2016	10,288,000
2017	8,215,000
2018	7,130,000
2019	6,492,000
Thereafter	1,046,000
Operating Leases, Future Minimum Payments Due, Total	$46,436,000

Income_Taxes_Details

Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current taxes:
Federal	$473,000	$144,000	$2,711,000
State	21,000	198,000	439,000
Deferred taxes:
Federal	-104,000	-2,805,000	323,000
State	4,047,000	264,000	-683,000
Income tax expense (benefit)	4,437,000	-2,199,000	2,790,000
Operating Loss Carryforwards [Line Items]
Material Uncertain Tax Position	0	0
Effective income tax rate reconciliation [Abstract]
Federal statutory rate	35.00%	35.00%	35.00%
State, net of federal tax benefit	-0.90%	-0.10%	0.10%
Loss excluded from nontaxable entities	-34.60%	-34.60%	-35.60%
Other items	-0.50%	0.00%	-0.20%
Effective rate	-1.00%	0.30%	-0.70%
Deferred tax assets:
Net operating loss carryforwards	0	1,129,000
Unit-based compensation	22,105,000	21,965,000
Other	6,857,000	7,759,000
Total deferred tax assets	28,962,000	30,853,000
Deferred tax liabilities:
Property and equipment principally due to differences in depreciation	-10,991,000	-12,525,000
Other	-6,370,000	-1,509,000
Total deferred tax liabilities	-17,361,000	-14,034,000
Net deferred tax assets	11,601,000	16,819,000
Net deferred tax assets and liabilities classified in consolidated balance sheets [Abstract]
Deferred tax assets	28,442,000	29,204,000
Deferred tax liabilities	-2,964,000	-10,000
Other current assets	25,478,000	29,194,000
Deferred tax assets	520,000	1,649,000
Deferred tax liabilities	-14,397,000	-14,024,000
Other noncurrent liabilities	-13,877,000	-12,375,000
Federal [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$11,000,000
Net operating loss carryforwards, expiration dates	31-Dec-31

Supplemental_Disclosures_to_th2

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Balance Sheets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Accrued interest	$105,310,000	$93,998,000
Accrued compensation	44,875,000	55,257,000
Asset retirement obligations	16,187,000	12,616,000
Other	1,364,000	1,504,000
Other accrued liabilities	167,736,000	163,375,000
Restricted cash	6,000,000	6,000,000
Net Outstanding Checks	$95,000,000	$48,000,000

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Cash payments for interest, net of amounts capitalized	$542,775,000	$392,607,000	$343,331,000
Cash payments for income taxes	0	14,000	366,000
Noncash investing and financing activities:
Fair value of assets acquired	2,679,547,000	5,726,681,000	2,923,990,000
Cash paid, net of cash acquired	-2,395,339,000	-109,350,000	-2,640,475,000
Units issued in connection with the Berry acquisition	0	-2,781,888,000	0
Gain (Loss) on Disposition of Oil and Gas Property	-85,493,000	0	0
Receivables from sellers	16,213,000	-93,000	2,132,000
Payables to sellers	-3,515,000	-6,854,000	443,000
Liabilities assumed	211,413,000	2,828,496,000	286,090,000
Joint-venture funding	$25,000,000	$170,000,000	$197,000,000

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 17, 2012	Dec. 17, 2013	Dec. 16, 2013
Related Party Transaction [Line Items]
General and administrative expenses	$293,073,000	$236,271,000	$173,206,000
Share-based compensation expense	53,284,000	42,703,000	29,533,000
Distributions to unitholders	962,048,000	682,241,000	596,935,000
LinnCo
Related Party Transaction [Line Items]
Initial public offering, proceeds				1,200,000,000
Units of LINN Energy acquired				34,787,500
Ownership percentage	39.00%
General and administrative expenses	2,900,000	42,000,000
Third party transaction costs related to the pending acquisition of Berry		40,000,000
Share-based compensation expense		9,000,000
Distributions to unitholders	373,000,000	101,000,000	25,000,000
Related party transaction, amounts of transaction	1,900,000	2,000,000
Offering costs paid on behalf of related party		388,000
Berry
Related Party Transaction [Line Items]
Exchange ratio					168.00%
Director
Related Party Transaction [Line Items]
Related party transaction, amounts of transaction	21,000,000	26,000,000	21,000,000
Linn Energy, LLC | Berry
Related Party Transaction [Line Items]
LinnCo common shares issued to acquire Berry					93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued					93,756,674
Value of units issued to acquire Berry						2,800,000,000
LinnCo | Berry
Related Party Transaction [Line Items]
LinnCo common shares issued to acquire Berry					93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued					93,756,674
FY 2013 [Member]
Related Party Transaction [Line Items]
General and administrative expenses paid on behalf of related party	$11,000,000
Business Acquisition, Berry
Related Party Transaction [Line Items]
Exchange ratio					168.00%
Business Acquisition, Berry | Linn Energy, LLC
Related Party Transaction [Line Items]
Units of LINN Energy acquired					34,787,500
LinnCo common shares issued to acquire Berry					93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued					93,756,674
Business Acquisition, Berry | LinnCo
Related Party Transaction [Line Items]
LinnCo common shares issued to acquire Berry					93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued					93,756,674

Subsidiary_Guarantors_Condense

Subsidiary Guarantors Condensed Consolidating Balance Sheets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$1,809	$52,171	$1,243	$1,114
Accounts receivable – trade, net	471,684	488,202
Accounts receivable – affiliates	0	0
Derivative instruments	1,077,142	176,130
Other current assets	155,955	99,437
Total current assets	1,706,590	815,940
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	18,068,900	17,888,559
Less accumulated depletion and amortization	-4,867,682	-3,546,284
Oil and natural gas properties, successful efforts method, net	13,201,218	14,342,275
Other property and equipment	669,149	647,882
Less accumulated depreciation	-144,282	-110,939
Other property and equipment, net	524,867	536,943
Derivative instruments	848,097	682,002
Notes receivable – affiliates	0	0
Advance to affiliate	0
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	142,737	127,804
Noncurrent assets, excluding property, total	990,834	809,806
Total noncurrent assets	14,716,919	15,689,024
Total assets	16,423,509	16,504,964
Current liabilities:
Accounts payable and accrued expenses	814,809	849,624
Accounts payable – affiliates	0	0
Advance from affiliate	0
Derivative instruments	0	28,176
Other accrued liabilities	167,736	163,375
Current portion of long-term debt	0	211,558
Total current liabilities	982,545	1,252,733
Noncurrent liabilities:
Credit facilities	2,968,175	2,733,175
Term loan	500,000	500,000
Senior notes, net	6,827,634	5,725,483
Notes payable – affiliates	0	0
Derivative instruments	684	4,649
Other noncurrent liabilities	600,866	397,497
Total noncurrent liabilities	10,897,359	9,360,804
Unitholders’ capital:
Units issued and outstanding	5,395,811	6,291,824
Accumulated income (deficit)	-852,206	-400,397
Total unitholders' capital	4,543,605	5,891,427	4,427,180	3,428,910
Total liabilities and unitholders’ capital	16,423,509	16,504,964
Eliminations
Current assets:
Cash and cash equivalents	0	0	0
Accounts receivable – trade, net	0	0
Accounts receivable – affiliates	-4,042,095	-4,229,298
Derivative instruments	0	0
Other current assets	0	0
Total current assets	-4,042,095	-4,229,298
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	0	0
Less accumulated depletion and amortization	0	0
Oil and natural gas properties, successful efforts method, net	0	0
Other property and equipment	0	0
Less accumulated depreciation	0	0
Other property and equipment, net	0	0
Derivative instruments	0	0
Notes receivable – affiliates	-130,500	-86,200
Advance to affiliate	-293,627
Investments in consolidated subsidiaries	-8,562,608	-8,433,290
Other noncurrent assets	0	0
Noncurrent assets, excluding property, total	-8,986,735	-8,519,490
Total noncurrent assets	-8,986,735	-8,519,490
Total assets	-13,028,830	-12,748,788
Current liabilities:
Accounts payable and accrued expenses	0	0
Accounts payable – affiliates	-4,042,095	-4,229,298
Advance from affiliate	-293,627
Derivative instruments	0	0
Other accrued liabilities	0	0
Current portion of long-term debt		0
Total current liabilities	-4,335,722	-4,229,298
Noncurrent liabilities:
Credit facilities	0	0
Term loan	0	0
Senior notes, net	0	0
Notes payable – affiliates	-130,500	-86,200
Derivative instruments	0	0
Other noncurrent liabilities	0	0
Total noncurrent liabilities	-130,500	-86,200
Unitholders’ capital:
Units issued and outstanding	-7,240,658	-7,139,737
Accumulated income (deficit)	-1,321,950	-1,293,553
Total unitholders' capital	-8,562,608	-8,433,290
Total liabilities and unitholders’ capital	-13,028,830	-12,748,788
Linn Energy, LLC | Reportable Legal Entities
Current assets:
Cash and cash equivalents	38	52	107
Accounts receivable – trade, net	0	0
Accounts receivable – affiliates	4,028,890	4,212,348
Derivative instruments	0	0
Other current assets	18	330
Total current assets	4,028,946	4,212,730
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	0	0
Less accumulated depletion and amortization	0	0
Oil and natural gas properties, successful efforts method, net	0	0
Other property and equipment	0	0
Less accumulated depreciation	0	0
Other property and equipment, net	0	0
Derivative instruments	0	0
Notes receivable – affiliates	130,500	86,200
Advance to affiliate	0
Investments in consolidated subsidiaries	8,562,608	8,433,290
Other noncurrent assets	116,637	108,785
Noncurrent assets, excluding property, total	8,809,745	8,628,275
Total noncurrent assets	8,809,745	8,628,275
Total assets	12,838,691	12,841,005
Current liabilities:
Accounts payable and accrued expenses	3,784	14,529
Accounts payable – affiliates	0	0
Advance from affiliate	0
Derivative instruments	0	0
Other accrued liabilities	89,507	75,071
Current portion of long-term debt		0
Total current liabilities	93,291	89,600
Noncurrent liabilities:
Credit facilities	1,795,000	1,560,000
Term loan	500,000	500,000
Senior notes, net	5,913,857	4,809,055
Notes payable – affiliates	0	0
Derivative instruments	0	0
Other noncurrent liabilities	0	0
Total noncurrent liabilities	8,208,857	6,869,055
Unitholders’ capital:
Units issued and outstanding	5,388,749	6,282,747
Accumulated income (deficit)	-852,206	-400,397
Total unitholders' capital	4,536,543	5,882,350
Total liabilities and unitholders’ capital	12,838,691	12,841,005
Guarantor Subsidiaries | Reportable Legal Entities
Current assets:
Cash and cash equivalents	185	1,078	1,136
Accounts receivable – trade, net	371,325	365,347
Accounts receivable – affiliates	13,205	16,950
Derivative instruments	1,033,448	170,534
Other current assets	96,678	68,274
Total current assets	1,514,841	622,183
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	13,196,841	13,074,900
Less accumulated depletion and amortization	-4,342,675	-3,535,890
Oil and natural gas properties, successful efforts method, net	8,854,166	9,539,010
Other property and equipment	553,150	564,756
Less accumulated depreciation	-135,830	-110,706
Other property and equipment, net	417,320	454,050
Derivative instruments	848,097	679,491
Notes receivable – affiliates	0	0
Advance to affiliate	0
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	11,816	10,968
Noncurrent assets, excluding property, total	859,913	690,459
Total noncurrent assets	10,131,399	10,683,519
Total assets	11,646,240	11,305,702
Current liabilities:
Accounts payable and accrued expenses	581,880	587,774
Accounts payable – affiliates	4,028,890	4,212,348
Advance from affiliate	293,627
Derivative instruments	0	7,783
Other accrued liabilities	59,142	59,311
Current portion of long-term debt		0
Total current liabilities	4,963,539	4,867,216
Noncurrent liabilities:
Credit facilities	0	0
Term loan	0	0
Senior notes, net	0	0
Notes payable – affiliates	130,500	86,200
Derivative instruments	684	0
Other noncurrent liabilities	400,851	205,406
Total noncurrent liabilities	532,035	291,606
Unitholders’ capital:
Units issued and outstanding	4,831,339	4,833,354
Accumulated income (deficit)	1,319,327	1,313,526
Total unitholders' capital	6,150,666	6,146,880
Total liabilities and unitholders’ capital	11,646,240	11,305,702
Non-Guarantor Subsidiary | Reportable Legal Entities
Current assets:
Cash and cash equivalents	1,586	51,041	0
Accounts receivable – trade, net	100,359	122,855
Accounts receivable – affiliates	0	0
Derivative instruments	43,694	5,596
Other current assets	59,259	30,833
Total current assets	204,898	210,325
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	4,872,059	4,813,659
Less accumulated depletion and amortization	-525,007	-10,394
Oil and natural gas properties, successful efforts method, net	4,347,052	4,803,265
Other property and equipment	115,999	83,126
Less accumulated depreciation	-8,452	-233
Other property and equipment, net	107,547	82,893
Derivative instruments	0	2,511
Notes receivable – affiliates	0	0
Advance to affiliate	293,627
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	14,284	8,051
Noncurrent assets, excluding property, total	307,911	10,562
Total noncurrent assets	4,762,510	4,896,720
Total assets	4,967,408	5,107,045
Current liabilities:
Accounts payable and accrued expenses	229,145	247,321
Accounts payable – affiliates	13,205	16,950
Advance from affiliate	0
Derivative instruments	0	20,393
Other accrued liabilities	19,087	28,993
Current portion of long-term debt		211,558
Total current liabilities	261,437	525,215
Noncurrent liabilities:
Credit facilities	1,173,175	1,173,175
Term loan	0	0
Senior notes, net	913,777	916,428
Notes payable – affiliates	0	0
Derivative instruments	0	4,649
Other noncurrent liabilities	200,015	192,091
Total noncurrent liabilities	2,286,967	2,286,343
Unitholders’ capital:
Units issued and outstanding	2,416,381	2,315,460
Accumulated income (deficit)	2,623	-19,973
Total unitholders' capital	2,419,004	2,295,487
Total liabilities and unitholders’ capital	$4,967,408	$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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues and other:
Oil, natural gas and natural gas liquids sales	$766,354	$937,458	$967,850	$938,877	$584,630	$537,671	$488,207	$462,732	$3,610,539	$2,073,240	$1,601,180
Gains on oil and natural gas derivatives	1,404,758	451,702	-408,788	-241,493	23,425	-63,931	326,733	-108,370	1,206,179	177,857	124,762
Marketing revenues									135,260	54,171	37,393
Other revenues									31,325	26,387	10,905
Total revenues	2,217,650	1,435,115	596,951	733,587	629,208	494,562	838,825	369,060	4,983,303	2,331,655	1,774,240
Expenses:
Lease operating expenses									805,164	372,523	317,699
Transportation expenses									207,331	128,440	77,322
Marketing expenses									117,465	37,892	31,821
General and administrative expenses									293,073	236,271	173,206
Exploration costs									125,037	5,251	1,915
Depreciation, depletion and amortization									1,073,902	829,311	606,150
Impairment of long-lived assets	1,700,000	603,000							2,303,749	828,317	422,499
Taxes, other than income taxes									267,403	138,631	131,679
(Gains) losses on sale of assets and other, net	338,750	35,803	-5,467	-2,586	-10,597	-827	959	-3,172	-366,500	13,637	1,539
Total expenses									4,826,624	2,590,273	1,763,830
Other income and (expenses):
Interest expense, net of amounts capitalized									-587,838	-421,137	-379,937
Interest expense – affiliates									0	0
Interest income – affiliates									0	0
Loss on extinguishment of debt									0	-5,304	0
Equity in earnings from consolidated subsidiaries									0	0
Other, net									-16,213	-8,477	-14,299
Total other income and (expenses)									-604,051	-434,918	-394,236
Loss before income taxes									-447,372	-693,536	-383,826
Income tax expense (benefit)									4,437	-2,199	2,790
Net loss	-154,502	-4,100	-207,870	-85,337	-784,549	-30,060	345,157	-221,885	-451,809	-691,337	-386,616
Eliminations
Revenues and other:
Oil, natural gas and natural gas liquids sales									0	0
Gains on oil and natural gas derivatives									0	0
Marketing revenues									0	0
Other revenues									0	0
Total revenues									0	0
Expenses:
Lease operating expenses									0	0
Transportation expenses									0	0
Marketing expenses									0	0
General and administrative expenses									0	0
Exploration costs									0	0
Depreciation, depletion and amortization									0	0
Impairment of long-lived assets									0	0
Taxes, other than income taxes									0	0
(Gains) losses on sale of assets and other, net									0	0
Total expenses									0	0
Other income and (expenses):
Interest expense, net of amounts capitalized									0	0
Interest expense – affiliates									7,954	5,543
Interest income – affiliates									-7,954	-5,543
Loss on extinguishment of debt										0
Equity in earnings from consolidated subsidiaries									-28,397	266,899
Other, net									0	0
Total other income and (expenses)									-28,397	266,899
Loss before income taxes									-28,397	266,899
Income tax expense (benefit)									0	0
Net loss									-28,397	266,899
Linn Energy, LLC | Reportable Legal Entities
Revenues and other:
Oil, natural gas and natural gas liquids sales									0	0
Gains on oil and natural gas derivatives									0	0
Marketing revenues									0	0
Other revenues									0	0
Total revenues									0	0
Expenses:
Lease operating expenses									0	0
Transportation expenses									0	0
Marketing expenses									0	0
General and administrative expenses									0	0
Exploration costs									0	0
Depreciation, depletion and amortization									0	0
Impairment of long-lived assets									0	0
Taxes, other than income taxes									40	0
(Gains) losses on sale of assets and other, net									0	724
Total expenses									40	724
Other income and (expenses):
Interest expense, net of amounts capitalized									-480,259	-415,670
Interest expense – affiliates									0	0
Interest income – affiliates									7,954	5,543
Loss on extinguishment of debt										-5,304
Equity in earnings from consolidated subsidiaries									28,397	-266,899
Other, net									-7,861	-8,283
Total other income and (expenses)									-451,769	-690,613
Loss before income taxes									-451,809	-691,337
Income tax expense (benefit)									0	0
Net loss									-451,809	-691,337
Guarantor Subsidiaries | Reportable Legal Entities
Revenues and other:
Oil, natural gas and natural gas liquids sales									2,312,137	2,022,916
Gains on oil and natural gas derivatives									1,127,395	182,906
Marketing revenues									84,349	52,328
Other revenues									28,133	26,387
Total revenues									3,552,014	2,284,537
Expenses:
Lease operating expenses									440,624	357,113
Transportation expenses									165,489	125,864
Marketing expenses									81,210	36,259
General and administrative expenses									190,286	215,973
Exploration costs									125,037	5,251
Depreciation, depletion and amortization									771,549	818,466
Impairment of long-lived assets									2,050,387	828,317
Taxes, other than income taxes									169,655	136,501
(Gains) losses on sale of assets and other, net									-487,286	2,705
Total expenses									3,506,951	2,526,449
Other income and (expenses):
Interest expense, net of amounts capitalized									-19,631	-1,504
Interest expense – affiliates									-7,954	-5,543
Interest income – affiliates									0	0
Loss on extinguishment of debt										0
Equity in earnings from consolidated subsidiaries									0	0
Other, net									-7,309	-166
Total other income and (expenses)									-34,894	-7,213
Loss before income taxes									10,169	-249,125
Income tax expense (benefit)									4,368	-2,199
Net loss									5,801	-246,926
Non-Guarantor Subsidiary | Reportable Legal Entities
Revenues and other:
Oil, natural gas and natural gas liquids sales									1,298,402	50,324
Gains on oil and natural gas derivatives									78,784	-5,049
Marketing revenues									50,911	1,843
Other revenues									3,192	0
Total revenues									1,431,289	47,118
Expenses:
Lease operating expenses									364,540	15,410
Transportation expenses									41,842	2,576
Marketing expenses									36,255	1,633
General and administrative expenses									102,787	20,298
Exploration costs									0	0
Depreciation, depletion and amortization									302,353	10,845
Impairment of long-lived assets									253,362	0
Taxes, other than income taxes									97,708	2,130
(Gains) losses on sale of assets and other, net									120,786	10,208
Total expenses									1,319,633	63,100
Other income and (expenses):
Interest expense, net of amounts capitalized									-87,948	-3,963
Interest expense – affiliates									0	0
Interest income – affiliates									0	0
Loss on extinguishment of debt										0
Equity in earnings from consolidated subsidiaries									0	0
Other, net									-1,043	-28
Total other income and (expenses)									-88,991	-3,991
Loss before income taxes									22,665	-19,973
Income tax expense (benefit)									69	0
Net loss									$22,596	($19,973)

Subsidiary_Guarantors_Condense2

Subsidiary Guarantors Condensed Consolidating Statements of Cash Flow (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flow from operating activities:
Net loss	($451,809)	($691,337)	($386,616)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	1,073,902	829,311	606,150
Impairment of long-lived assets	2,303,749	828,317	422,499
Unit-based compensation expenses	53,284	42,703	29,533
Amortization and write-off of deferred financing fees	50,926	21,507	25,598
Loss on extinguishment of debt	0	5,304	0
(Gains) losses on sale of assets and other, net	-261,571	37,232	92
Equity in earnings from consolidated subsidiaries	0	0
Deferred income taxes	3,943	-2,541	-360
Derivatives activities:
Total (gains) losses	1,206,179	177,857	124,762
Cash settlements	95,514	248,862	390,765
Cash settlements on canceled derivatives	12,281	0	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	5,064	89,188	-77,573
Increase in accounts receivable – affiliates	0	0
(Increase) decrease in other assets	-17,824	16,179	-5,451
Increase (decrease) in accounts payable and accrued expenses	99,029	-76,993	26,372
Decrease in accounts payable and accrued expenses – affiliates	0	0
Increase in accounts payable and accrued expenses – affiliates	0	0
Increase (decrease) in other liabilities	-48,419	-3,663	28,094
Net cash provided by operating activities	1,711,890	1,166,212	350,907
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	-2,479,252	-279,213	-2,640,475
Development of oil and natural gas properties	-1,569,877	-1,078,025	-984,530
Purchases of other property and equipment	-74,540	-92,352	-60,549
Investment in affiliates	0	0
Change in notes receivable with affiliate	0	0
Proceeds from sale of properties and equipment and other	2,203,565	196,273	725
Net cash used in investing activities	-1,920,104	-1,253,317	-3,684,829
Cash flow from financing activities:
Proceeds from borrowings	5,940,024	2,230,000	5,439,802
Repayments of debt	-4,811,124	-1,404,898	-3,400,000
Distributions to unitholders	-962,048	-682,241	-596,935
Financing fees and offering expenses	69,694	16,033	73,320
Change in note payable with affiliate	0	0
Capital contribution – affiliates	0	0
Excess tax benefit from unit-based compensation	766	160	3,090
Other	59,928	11,045	-12,575
Net cash provided by financing activities	157,852	138,033	3,334,051
Net increase (decrease) in cash and cash equivalents	-50,362	50,928	129
Cash and cash equivalents:
Beginning	52,171	1,243	1,114
Ending	1,809	52,171	1,243
Eliminations
Cash flow from operating activities:
Net loss	-28,397	266,899
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	0	0
Impairment of long-lived assets	0	0
Unit-based compensation expenses	0	0
Amortization and write-off of deferred financing fees	0	0
Loss on extinguishment of debt		0
(Gains) losses on sale of assets and other, net	0	0
Equity in earnings from consolidated subsidiaries	-28,397	266,899
Deferred income taxes	0	0
Derivatives activities:
Total (gains) losses	0	0
Cash settlements	0	0
Cash settlements on canceled derivatives	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	0	0
Increase in accounts receivable – affiliates	274,435	-137,917
(Increase) decrease in other assets	0	0
Increase (decrease) in accounts payable and accrued expenses	0	0
Decrease in accounts payable and accrued expenses – affiliates	274,435	-137,917
Increase in accounts payable and accrued expenses – affiliates	274,435	-137,917
Increase (decrease) in other liabilities	0	0
Net cash provided by operating activities	0	0
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	0	0
Development of oil and natural gas properties	0	0
Purchases of other property and equipment	0	0
Investment in affiliates	100,921	-435,000
Change in notes receivable with affiliate	44,300	26,700
Proceeds from sale of properties and equipment and other	0	0
Net cash used in investing activities	145,221	-408,300
Cash flow from financing activities:
Proceeds from borrowings	0	0
Repayments of debt	0	0
Distributions to unitholders	0	0
Financing fees and offering expenses	0	0
Change in note payable with affiliate	-44,300	-26,700
Capital contribution – affiliates	-100,921	435,000
Excess tax benefit from unit-based compensation	0	0
Other	0	0
Net cash provided by financing activities	-145,221	408,300
Net increase (decrease) in cash and cash equivalents	0	0
Cash and cash equivalents:
Beginning	0	0
Ending	0	0
Linn Energy, LLC | Reportable Legal Entities
Cash flow from operating activities:
Net loss	-451,809	-691,337
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	0	0
Impairment of long-lived assets	0	0
Unit-based compensation expenses	0	0
Amortization and write-off of deferred financing fees	38,785	22,122
Loss on extinguishment of debt		5,304
(Gains) losses on sale of assets and other, net	0	0
Equity in earnings from consolidated subsidiaries	28,397	-266,899
Deferred income taxes	0	0
Derivatives activities:
Total (gains) losses	0	0
Cash settlements	0	0
Cash settlements on canceled derivatives	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	0	0
Increase in accounts receivable – affiliates	-257,485	120,967
(Increase) decrease in other assets	312	-330
Increase (decrease) in accounts payable and accrued expenses	0	178
Decrease in accounts payable and accrued expenses – affiliates	0	0
Increase in accounts payable and accrued expenses – affiliates	0	0
Increase (decrease) in other liabilities	14,465	2,092
Net cash provided by operating activities	-169,159	-516,039
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	0	0
Development of oil and natural gas properties	0	0
Purchases of other property and equipment	0	0
Investment in affiliates	-100,921	435,000
Change in notes receivable with affiliate	-44,300	-26,700
Proceeds from sale of properties and equipment and other	-14,117	-22,039
Net cash used in investing activities	-159,338	386,261
Cash flow from financing activities:
Proceeds from borrowings	4,640,024	2,230,000
Repayments of debt	-3,305,000	-1,404,898
Distributions to unitholders	-962,048	-682,241
Financing fees and offering expenses	59,048	16,033
Change in note payable with affiliate	0	0
Capital contribution – affiliates	0	0
Excess tax benefit from unit-based compensation	810	0
Other	13,745	2,895
Net cash provided by financing activities	328,483	129,723
Net increase (decrease) in cash and cash equivalents	-14	-55
Cash and cash equivalents:
Beginning	52	107
Ending	38	52
Guarantor Subsidiaries | Reportable Legal Entities
Cash flow from operating activities:
Net loss	5,801	-246,926
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	771,549	818,466
Impairment of long-lived assets	2,050,387	828,317
Unit-based compensation expenses	53,284	42,703
Amortization and write-off of deferred financing fees	17,054	0
Loss on extinguishment of debt		0
(Gains) losses on sale of assets and other, net	-372,945	37,232
Equity in earnings from consolidated subsidiaries	0	0
Deferred income taxes	3,874	-2,541
Derivatives activities:
Total (gains) losses	1,127,395	182,906
Cash settlements	88,776	248,862
Cash settlements on canceled derivatives	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	-11,419	17,754
Increase in accounts receivable – affiliates	-16,950	16,950
(Increase) decrease in other assets	-2,187	5,896
Increase (decrease) in accounts payable and accrued expenses	99,003	-52,143
Decrease in accounts payable and accrued expenses – affiliates	-270,690	120,967
Increase in accounts payable and accrued expenses – affiliates	-270,690	120,967
Increase (decrease) in other liabilities	-24,473	6,842
Net cash provided by operating activities	1,297,569	1,625,573
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	-2,475,315	-730,326
Development of oil and natural gas properties	-1,061,395	-1,060,547
Purchases of other property and equipment	-63,070	-92,352
Investment in affiliates	0	0
Change in notes receivable with affiliate	0	0
Proceeds from sale of properties and equipment and other	2,210,015	218,312
Net cash used in investing activities	-1,389,765	-1,664,913
Cash flow from financing activities:
Proceeds from borrowings	1,300,000	0
Repayments of debt	-1,300,000	0
Distributions to unitholders	0	0
Financing fees and offering expenses	0	0
Change in note payable with affiliate	44,300	26,700
Capital contribution – affiliates	0	0
Excess tax benefit from unit-based compensation	-44	160
Other	47,047	12,422
Net cash provided by financing activities	91,303	39,282
Net increase (decrease) in cash and cash equivalents	-893	-58
Cash and cash equivalents:
Beginning	1,078	1,136
Ending	185	1,078
Non-Guarantor Subsidiary | Reportable Legal Entities
Cash flow from operating activities:
Net loss	22,596	-19,973
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	302,353	10,845
Impairment of long-lived assets	253,362	0
Unit-based compensation expenses	0	0
Amortization and write-off of deferred financing fees	-4,913	-615
Loss on extinguishment of debt		0
(Gains) losses on sale of assets and other, net	111,374	0
Equity in earnings from consolidated subsidiaries	0	0
Deferred income taxes	69	0
Derivatives activities:
Total (gains) losses	78,784	-5,049
Cash settlements	6,738	0
Cash settlements on canceled derivatives	12,281
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	16,483	71,434
Increase in accounts receivable – affiliates	0	0
(Increase) decrease in other assets	-15,949	10,613
Increase (decrease) in accounts payable and accrued expenses	26	-25,028
Decrease in accounts payable and accrued expenses – affiliates	-3,745	16,950
Increase in accounts payable and accrued expenses – affiliates	-3,745	16,950
Increase (decrease) in other liabilities	-38,411	-12,597
Net cash provided by operating activities	583,480	56,678
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	-3,937	451,113
Development of oil and natural gas properties	-508,482	-17,478
Purchases of other property and equipment	-11,470	0
Investment in affiliates	0	0
Change in notes receivable with affiliate	0	0
Proceeds from sale of properties and equipment and other	7,667	0
Net cash used in investing activities	-516,222	433,635
Cash flow from financing activities:
Proceeds from borrowings	0	0
Repayments of debt	-206,124	0
Distributions to unitholders	0	0
Financing fees and offering expenses	10,646	0
Change in note payable with affiliate	0	0
Capital contribution – affiliates	100,921	-435,000
Excess tax benefit from unit-based compensation	0	0
Other	-864	-4,272
Net cash provided by financing activities	-116,713	-439,272
Net increase (decrease) in cash and cash equivalents	-49,455	51,041
Cash and cash equivalents:
Beginning	51,041	0
Ending	$1,586	$51,041

Subsidiary_Guarantors_Details_

Subsidiary Guarantors Details (Details)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions	100.00%

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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	Mcfe				Mcfe				Mcfe		Mcfe		Mcfe		Mcfe
Revenues and other:
Oil, natural gas and natural gas liquids sales	$766,354	$937,458	$967,850	$938,877	$584,630	$537,671	$488,207	$462,732	$3,610,539		$2,073,240		$1,601,180
Gains on oil and natural gas derivatives	1,404,758	451,702	-408,788	-241,493	23,425	-63,931	326,733	-108,370	1,206,179		177,857		124,762
Results of Operations, Revenue from Oil and Gas Producing Activities									4,816,718		2,251,097		1,725,942
Production costs:
Lease operating expenses									805,164		372,523		317,699
Transportation expenses									207,331		128,440		77,322
Severance taxes, ad valorem taxes and California carbon allowances									267,100		139,202		130,805
Total production costs									1,279,595		640,165		525,826
Other costs:
Exploration costs									125,037		5,251		1,915
Depletion and amortization									1,020,674		790,320		579,382
Impairment of long-lived assets	1,700,000	603,000							2,303,749		828,317		422,499
Gains on sale of assets and other, net									-388,733		-138		-1,369
Texas margin tax expense (benefit)									4,053		458		-787
Total other costs									3,064,780		1,624,208		1,001,640
Results of operations									472,343		-13,276		198,476
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy)									442,000,000		300,000,000		246,000,000
Proved Undeveloped Reserves (Energy)	1,486,000,000				2,063,000,000				1,486,000,000		2,063,000,000		1,669,000,000		1,336,000,000
Proved Developed Reserves (Energy)	5,818,000,000				4,340,000,000				5,818,000,000		4,340,000,000		3,127,000,000		2,034,000,000
Proved developed and undeveloped reserves:
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)									-318,000,000		-157,000,000		-803,000,000
Proved Developed and Undeveloped Reserve, Purchase of Mineral in Place (Energy)									2,495,000,000		1,610,000,000		1,766,000,000
Proved Developed and Undeveloped Reserve, Extension and Discovery (Energy)									250,000,000		527,000,000		709,000,000
Proved Developed and Undeveloped Reserves, Sale of Mineral in Place (Energy)									1,084,000,000		73,000,000
Proved undeveloped reserves:
Conversion rate between oil and NGL volumes to natural gas									6
Decline in NYMEX oil spot price	42.00%
Decline in NYMEX natural gas spot price.	30.00%
NYMEX oil price	53.27								53.27
NYMEX natural gas spot price	2.89								2.89
Change in proved reserves (in Mcfe)									901,000,000		1,607,000,000		1,426,000,000
Total Proved Developed and Undeveloped Reserves, Net	7,304,000,000				6,403,000,000				7,304,000,000		6,403,000,000
Total Proved Developed and Undeveloped Reserves, Net	7,304,000,000				6,403,000,000				7,304,000,000		6,403,000,000		4,796,000,000		3,370,000,000
Change in proved reserves due to asset performance (in Mcfe)									174,000,000		100,000,000		340,000,000
Change in proved reserves due to change in commodity prices (in Mcfe)									45,000,000		52,000,000		248,000,000
Change in proved reserves due to the SEC five-year development limitation on PUDs									146,000,000		109,000,000		215,000,000
Number of acquisition of oil and natural gas properties											3		7
Productive wells drilled									917		0		436
Property acquisition costs [Abstract]
Proved									2,784,852	[1]	3,740,379	[1]	2,531,419	[1]
Unproved									788,682	[1]	1,638,302	[1]	181,124	[1]
Exploration costs									792		13,096		452
Development costs									1,487,204		1,153,770		1,062,043
Costs Incurred, Asset Retirement Obligation Incurred									20,919		7,351		4,675
Total costs incurred									5,082,449		6,552,898		3,779,713
Proved properties [Abstract]
Leasehold acquisition	13,362,642				12,277,089				13,362,642		12,277,089
Development	2,830,841				3,660,277				2,830,841		3,660,277
Unproved properties	1,875,417				1,951,193				1,875,417		1,951,193
Capitalized cost, oil and gas producing activities	18,068,900				17,888,559				18,068,900		17,888,559
Less accumulated depletion and amortization	-4,867,682				-3,546,284				-4,867,682		-3,546,284
Capitalized costs, oil and gas producing activities, net	13,201,218				14,342,275				13,201,218		14,342,275
Discounted future net cash flows relating to proved oil and gas reserves, future net cash Flows [Abstract]
Future estimated revenues	55,195,268				51,112,346				55,195,268		51,112,346		30,374,380
Future estimated production costs	-24,100,468				-19,306,728				-24,100,468		-19,306,728		-11,460,854
Future estimated development costs	-4,032,588				-5,110,896				-4,032,588		-5,110,896		-3,574,058
Future net cash flows	27,062,212				26,694,722				27,062,212		26,694,722		15,339,468
10% annual discount for estimated timing of cash flows	-14,549,921				-14,795,393				-14,549,921		-14,795,393		-9,266,487
Standardized measure of discounted future net cash flows	12,512,291				11,899,329				12,512,291		11,899,329		6,072,981
Representative NYMEX prices: (1)
Natural gas (MMBtu)									4.35	[2]	3.67	[2]	2.76	[2]
Oil (Bbl)									95.27	[2]	96.89	[2]	94.64	[2]
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									-2,330,944		-1,433,075		-1,075,354
Changes in estimated future development costs									156,614		317,064		289,762
Net change in sales and transfer prices and production costs related to future production									-599,121		203,370		-1,463,820
Purchases of minerals in place									3,021,768		5,113,335		2,153,651
Sales of minerals in place									-1,681,504		-139,384		0
Extensions, discoveries and improved recovery									910,787		801,254		413,702
Previously estimated development costs incurred during the period									819,987		444,861		442,322
Net change due to revisions in quantity estimates									-672,800		-220,224		-1,595,302
Accretion of discount									1,189,933		607,298		661,486
Changes in production rates and other									-201,758		131,849		-368,326
Change in the standardized measure of discounted future net cash flows									$612,962		$5,826,348		($541,879)
Natural Gas [Member]
Proved developed and undeveloped reserves:
Beginning of year				3,010,000,000				2,571,000,000	3,010,000,000		2,571,000,000		1,675,000,000
Revisions of previous estimates									96,000,000		-17,000,000		-559,000,000
Purchases of minerals in place									1,763,000,000		356,000,000		1,176,000,000
Extensions, discoveries and other additions									72,000,000		286,000,000		407,000,000
Production									-209,000,000		-162,000,000		-128,000,000
End of year	4,255,000,000				3,010,000,000				4,255,000,000		3,010,000,000		2,571,000,000
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place									477,000,000		24,000,000
Proved developed reserves:
Beginning of year				2,027,000,000				1,661,000,000	2,027,000,000		1,661,000,000		998,000,000
End of year	3,549,000,000				2,027,000,000				3,549,000,000		2,027,000,000		1,661,000,000
Proved undeveloped reserves:
Beginning of year				983,000,000				910,000,000	983,000,000		910,000,000		677,000,000
End of year	706,000,000				983,000,000				706,000,000		983,000,000		910,000,000
Oil [Member]
Proved developed and undeveloped reserves:
Beginning of year				365.6				191.5	365.6		191.5		189
Revisions of previous estimates									-22.3		-21.3		-26.5
Purchases of minerals in place									50		191.1		23.1
Extensions, discoveries and other additions									26.8		21.7		16.6
Production									-26.6		-12.2		-10.7
End of year	341.8				365.6				341.8		365.6		191.5
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place									51.7		5.2
Proved developed reserves:
Beginning of year				252.4				131.4	252.4		131.4		124.8
End of year	246				252.4				246		252.4		131.4
Proved undeveloped reserves:
Beginning of year				113.2				60.1	113.2		60.1		64.2
End of year	95.8				113.2				95.8		113.2		60.1
NGL [Member]
Proved developed and undeveloped reserves:
Beginning of year				200				179.4	200		179.4		93.5
Revisions of previous estimates									-46.8		-2		-14.1
Purchases of minerals in place									71.9		17.8		75.3
Extensions, discoveries and other additions									2.9		18.5		33.7
Production									-12.2		-10.8		-9
End of year	166.3				200				166.3		200		179.4
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place									49.5		2.9
Proved developed reserves:
Beginning of year				133.2				113	133.2		113		47.8
End of year	132.2				133.2				132.2		133.2		113
Proved undeveloped reserves:
Beginning of year				66.8				66.4	66.8		66.4		45.7
End of year	34.1				66.8				34.1		66.8		66.4
[1]	See Note 2 for details about the Company’s acquisitions.
[2]	In accordance with SEC regulations, reserves at December 31, 2014, December 31, 2013, and December 31, 2012, 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.

Supplemental_Quarterly_Data_Un2

Supplemental Quarterly Data (Unaudited) (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Abstract]
Oil, natural gas and natural gas liquids sales	$766,354		$937,458		$967,850		$938,877		$584,630		$537,671		$488,207		$462,732		$3,610,539	$2,073,240	$1,601,180
Total (gains) losses	1,404,758		451,702		-408,788		-241,493		23,425		-63,931		326,733		-108,370		1,206,179	177,857	124,762
Total revenues and other	2,217,650		1,435,115		596,951		733,587		629,208		494,562		838,825		369,060		4,983,303	2,331,655	1,774,240
Total expenses (1)	2,533,947	[1]	1,320,157	[1]	664,452	[1]	674,568	[1]	1,292,058	[1]	420,803	[1]	385,540	[1]	478,235	[1]
(Gains) losses on sale of assets and other, net	338,750		35,803		-5,467		-2,586		-10,597		-827		959		-3,172		-366,500	13,637	1,539
Net loss	($154,502)		($4,100)		($207,870)		($85,337)		($784,549)		($30,060)		$345,157		($221,885)		($451,809)	($691,337)	($386,616)
Net loss per unit:
Basic	($0.47)		($0.02)		($0.64)		($0.27)		($3.15)		($0.13)		$1.47		($0.96)		($1.40)	($2.94)	($1.92)
Diluted	($0.47)		($0.02)		($0.64)		($0.27)		($3.15)		($0.13)		$1.46		($0.96)		($1.40)	($2.94)	($1.92)
[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.