Pressburg (ROAN) 10-Q 28 Oct 13 2013 Q3 Quarterly report Financial data

Document_And_Entity_Informatio

Document And Entity Information	9 Months Ended
	Sep. 30, 2013
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	30-Sep-13
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	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	235,178,498
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets
Cash and cash equivalents	$27,480	$1,243
Accounts receivable - trade, net	349,426	371,333
Derivative instruments	217,853	350,695
Other current assets	54,547	88,157
Total current assets	649,306	811,428
Noncurrent assets
Oil and natural gas properties (successful efforts method)	12,211,608	11,611,330
Less accumulated depletion and amortization	-2,545,182	-2,025,656
Oil and natural gas properties, successful efforts method, net	9,666,426	9,585,674
Other property and equipment	548,725	469,188
Less accumulated depreciation	-100,812	-73,721
Other property and equipment, net	447,913	395,467
Derivative instruments	635,446	530,216
Other noncurrent assets	173,667	128,453
Noncurrent assets, excluding property, total	809,113	658,669
Total noncurrent assets	10,923,452	10,639,810
Total assets	11,572,758	11,451,238
Current liabilities
Accounts payable and accrued expenses	659,170	707,861
Derivative instruments	12,464	26
Other accrued liabilities	156,138	115,245
Total current liabilities	827,772	823,132
Noncurrent liabilities
Credit facility	1,705,000	1,180,000
Senior notes, net	4,807,873	4,857,817
Derivative instruments	0	4,114
Other noncurrent liabilities	191,955	158,995
Total noncurrent liabilities	6,704,828	6,200,926
Commitments and contingencies (Note 10)
Unitholders' capital
235,178,498 units and 234,513,243 units issued and outstanding at September 30, 2013, and December 31, 2012, respectively	3,656,006	4,136,240
Accumulated income	384,152	290,940
Total unitholders' capital	4,040,158	4,427,180
Total liabilities and unitholders' capital	$11,572,758	$11,451,238

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical)	Sep. 30, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Unitholder's capital: Units issued	235,178,498	234,513,243
Unitholders' capital: Units outstanding	235,178,498	234,513,243

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues and other:
Oil, natural gas and natural gas liquids sales	$537,671	$444,082	$1,488,610	$1,140,204
Gains (losses) on oil and natural gas derivatives	-63,931	-411,405	154,432	30,273
Marketing revenues	13,484	12,323	40,558	24,454
Other revenues	7,338	3,328	18,847	8,084
Total revenues	494,562	48,328	1,702,447	1,203,015
Expenses:
Lease operating expenses	87,076	91,990	259,381	233,755
Transportation expenses	35,637	18,274	92,118	50,651
Marketing expenses	9,962	14,923	26,696	22,073
General and administrative expenses	45,431	45,166	150,302	129,672
Exploration costs	1,588	390	4,632	1,207
Depreciation, depletion and amortization	208,892	167,695	604,962	428,477
Impairment of long-lived assets	-4,240	0	37,962	146,499
Taxes, other than income taxes	36,457	37,885	108,525	93,736
Losses on sale of assets and other, net	827	16	3,040	1,508
Total expenses	421,630	376,339	1,287,618	1,107,578
Other income and (expenses):
Interest expense, net of amounts capitalized	-103,806	-105,697	-308,012	-277,606
Loss on extinguishment of debt	-1,117	0	-5,304	0
Other, net	-2,475	-1,247	-6,300	-12,472
Total other income and (expenses)	-107,398	-106,944	-319,616	-290,078
Income (loss) before income taxes	-34,466	-434,955	95,213	-194,641
Income tax expense (benefit)	-4,406	-4,950	2,001	4,480
Net income (loss)	($30,060)	($430,005)	$93,212	($199,121)
Net income (loss) per unit:
Basic (in usd per unit)	($0.13)	($2.18)	$0.38	($1.04)
Diluted (in usd per unit)	($0.13)	($2.18)	$0.38	($1.04)
Weighted average units outstanding:
Basic (in units)	233,552	197,675	233,393	196,152
Diluted (in units)	233,552	197,675	233,765	196,152
Distributions declared per unit (in usd per unit)	$0.73	$0.73	$2.17	$2.14

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (Unaudited) (USD $)	3 Months Ended	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance Beginning		$4,427,180
Issuance of units		2,031
Distributions to unitholders		-511,686
Unit-based compensation expenses		29,261
Excess tax benefit from unit-based compensation		160
Net income	-30,060	93,212
Balance Ending	4,040,158	4,040,158
Units [Member]
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance Beginning (in units)		234,513
Issuance of units (in units)		665
Balance Ending (in units)	235,178	235,178
Unitholders' Capital [Member]
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance Beginning		4,136,240
Issuance of units		2,031
Distributions to unitholders		-511,686
Unit-based compensation expenses		29,261
Excess tax benefit from unit-based compensation		160
Balance Ending	3,656,006	3,656,006
Accumulated Income [Member]
Increase (Decrease) in Partners' Capital [Roll Forward]
Balance Beginning		290,940
Net income		93,212
Balance Ending	$384,152	$384,152

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Cash flow from operating activities:
Net income (loss)	$93,212	($199,121)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	604,962	428,477
Impairment of long-lived assets	37,962	146,499
Unit-based compensation expenses	29,261	21,735
Loss on extinguishment of debt	5,304	0
Amortization and write-off of deferred financing fees	16,392	20,265
Losses on sale of assets and other, net	18,744	703
Deferred income tax	731	965
Derivatives activities:
Total gains	-154,432	-30,273
Cash settlements	190,368	294,446
Premiums paid for derivatives	0	-583,434
Changes in assets and liabilities:
(Increase) decrease in accounts receivable - trade, net	22,877	-138,171
(Increase) decrease in other assets	9,177	-2,242
Increase in accounts payable and accrued expenses	29,445	94,762
Increase in other liabilities	36,508	89,820
Net cash provided by operating activities	940,511	144,431
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	-192,871	-2,487,767
Development of oil and natural gas properties	-767,604	-710,360
Purchases of other property and equipment	-76,987	-38,090
Proceeds from sale of properties and equipment and other	210,297	1,438
Net cash used in investing activities	-827,165	-3,234,779
Cash flow from financing activities:
Proceeds from sale of units	0	761,362
Proceeds from borrowings	1,260,000	4,929,802
Repayments of debt	-789,898	-2,085,000
Distributions to unitholders	-511,686	-426,918
Financing fees, offering expenses and other, net	-45,685	-92,184
Excess tax benefit from unit-based compensation	160	3,326
Net cash provided by (used in) financing activities	-87,109	3,090,388
Net increase in cash and cash equivalents	26,237	40
Cash and cash equivalents:
Beginning	1,243	1,114
Ending	$27,480	$1,154

Basis_of_Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation
	Nature of Business
	Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company. LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. The Company’s properties are located in the United States (“U.S.”), in the Mid-Continent, the Hugoton Basin, the Green River Basin, the Permian Basin, the Williston/Powder River Basin, Michigan, Illinois, California and east Texas.
	Principles of Consolidation and Reporting
	The condensed consolidated financial statements at September 30, 2013, and for the three months and nine months ended September 30, 2013, and September 30, 2012, are unaudited, but in the opinion of management include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.
	The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. The Company’s other investment is accounted for at cost.
	The condensed 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 condensed consolidated financial statements in conformity with GAAP requires Company management 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 December 2011, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The ASU requires disclosure of both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The ASU is to be applied retrospectively and is effective for periods beginning on or after January 1, 2013. The Company adopted the ASU effective January 1, 2013. The adoption of the requirements of the ASU, which expanded disclosures, had no effect on the Company’s financial position.

Acquisitions_JointVenture_Fund

Acquisitions, Joint-Venture Funding and Divestiture	9 Months Ended
	Sep. 30, 2013
Business Combinations [Abstract]
Acquisitions, Joint-Venture Funding and Divestiture	Acquisitions, Joint-Venture Funding and Divestiture
	For the nine months ended September 30, 2013, the Company paid approximately $114 million, including interest, towards the future funding commitment related to the joint-venture agreement it entered into with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) in April 2012. From inception of the agreement through September 30, 2013, the Company has funded approximately $315 million towards the total commitment of $400 million.
	During the nine months ended September 30, 2013, the Company completed small acquisitions of oil and natural gas properties located in its various operating regions. The Company, in the aggregate, paid approximately $32 million in total consideration for these properties.
	Acquisitions – Pending
	On September 11, 2013, the Company entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the Permian Basin for a contract price of approximately $525 million. The Company paid a deposit of approximately $53 million in September 2013, which is reported in “other noncurrent assets” on the condensed consolidated balance sheet at September 30, 2013. The Company anticipates the acquisition will close on or before October 31, 2013, subject to closing conditions, and will be financed with proceeds from a committed term loan to be entered into at closing and borrowings under the Company’s Credit Facility, as defined in Note 6.
	On February 20, 2013, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry Petroleum Company (“Berry”) entered into a definitive merger agreement under which LinnCo would acquire all of the outstanding common shares of Berry. Under the terms of the agreement, Berry’s shareholders will receive 1.25 LinnCo common shares for each Berry common share they own. This transaction, which is expected to be a tax-free exchange to Berry’s shareholders, represents value of $46.2375 per common share, based on the closing price of LinnCo common shares on February 20, 2013, the last trading day before the public announcement.
	In connection with the proposed transaction described above, LinnCo will contribute Berry to LINN Energy in exchange for newly issued LINN Energy units, after which Berry will be an indirect wholly owned subsidiary of LINN Energy. At February 21, 2013, the date of the public announcement, the transaction had a preliminary value of approximately $4.4 billion, including the assumption of approximately $1.7 billion of Berry’s debt. The transaction is subject to approvals by Berry and LinnCo shareholders, LINN Energy unitholders and regulatory agencies. Due to the pending SEC inquiry (see Note 16), the timing of closing this proposed transaction is uncertain.
	Acquisitions – 2012
	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 America Production Company (“BP”). The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid approximately $990 million in total consideration for these properties. The transaction was financed with borrowings under the Company’s Credit Facility.
	On May 1, 2012, the Company completed the acquisition of certain oil and natural gas properties located in east Texas. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid approximately $168 million in total consideration for these properties. The transaction was financed primarily with borrowings under the Company’s Credit Facility.
	On April 3, 2012, the Company entered into a joint-venture agreement (“Agreement”) with Anadarko whereby the Company will participate 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 results of operations of these properties have been included in the condensed consolidated financial statements since the Agreement date.
	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. The results of operations of these properties have been included in the condensed consolidated financial statements since the acquisition date. The Company paid approximately $1.16 billion in total consideration for these properties. The transaction was financed primarily with proceeds from the March 2012 debt offering (see Note 6).
	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 Properties”) to Midstates Petroleum Company, Inc. At March 31, 2013, the carrying value of the Panther Properties was reduced to fair value less costs to sell resulting in an impairment charge of approximately $57 million and the properties were classified as “assets held for sale.” During the three months ended June 30, 2013, and September 30, 2013, the Company recorded adjustments of approximately $15 million and $4 million, respectively, to reduce the initial impairment charge recorded in March 2013 resulting in a total impairment charge of approximately $38 million for the nine months ended September 30, 2013. Proceeds received for the Company’s portion of its interests in the properties were approximately $219 million, net of costs to sell of approximately $2 million. The Company used the net proceeds from the sale to repay borrowings under its Credit Facility.

Unitholders_Capital

Unitholders' Capital	9 Months Ended
	Sep. 30, 2013
Equity [Abstract]
Unitholders' Capital	Unitholders’ Capital
	Public Offering of Units
	In January 2012, the Company sold 19,550,000 units representing limited liability company interests at $35.95 per unit ($34.512 per unit, net of underwriting discount) for net proceeds of approximately $674 million (after underwriting discount and offering expenses of approximately $28 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under its Credit Facility.
	Equity Distribution Agreement
	The Company has an equity distribution agreement pursuant to which it may from time to time issue and sell units representing limited liability company interests having an aggregate offering price of up to $500 million. Sales of units, if any, will be made through a sales agent by means of ordinary brokers’ transactions, in block transactions, or as otherwise agreed with the agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.
	In January 2012, the Company, under its equity distribution agreement, issued and sold 1,539,651 units representing limited liability company interests at an average unit price of $38.02 for proceeds of approximately $57 million (net of approximately $2 million in commissions and professional service expenses). The Company used the net proceeds for general corporate purposes, including the repayment of a portion of the indebtedness outstanding under its Credit Facility. At September 30, 2013, units equaling approximately $411 million in aggregate offering price remained available to be issued and sold under the agreement.
	Distributions
	Under the Company’s limited liability company 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 condensed consolidated statement of unitholders’ capital and the condensed 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 October 1, 2013, the Company’s Board of Directors declared a cash distribution of $0.725 per unit with respect to the third quarter of 2013, to be paid in three equal monthly installments of $0.2416 per unit. The first monthly distribution with respect to the third quarter of 2013, totaling approximately $57 million, was paid on October 17, 2013, to unitholders of record as of the close of business on October 11, 2013.

Oil_and_Natural_Gas_Properties

Oil and Natural Gas Properties	9 Months Ended
	Sep. 30, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Natural Gas Properties	Oil and Natural Gas Properties
	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:
		September 30,			December 31,
		2013			2012
		(in thousands)
	Proved properties:
	Leasehold acquisition	$	8,505,622		$	8,603,888
	Development	3,316,007			2,553,127
	Unproved properties	389,979			454,315
		12,211,608			11,611,330
	Less accumulated depletion and amortization	(2,545,182		)	(2,025,656		)
		$	9,666,426		$	9,585,674

UnitBased_Compensation

Unit-Based Compensation	9 Months Ended
	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Unit-Based Compensation	Unit-Based Compensation
	During the nine months ended September 30, 2013, the Company granted 659,590 restricted units and 105,530 phantom units to employees, primarily as part of its annual review of its nonexecutive employees’ compensation, with an aggregate fair value of approximately $29 million. The restricted units and phantom units vest over three years. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
		(in thousands)
	General and administrative expenses	$	8,407	$	6,505	$	25,408	$	20,416
	Lease operating expenses	1,279		396		3,853		1,319
	Total unit-based compensation expenses	$	9,686	$	6,901	$	29,261	$	21,735
	Income tax benefit	$	3,579	$	2,550	$	10,812	$	8,031

Debt

Debt	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]
Debt	Debt
	The following summarizes debt outstanding:
		30-Sep-13					December 31, 2012
		Carrying Value			Fair Value (1)		Carrying Value			Fair Value (1)
		(in millions, except percentages)
	Credit facility (2)	$	1,705		$	1,705	$	1,180		$	1,180
	11.75% senior notes due 2017	—			—		41			44
	9.875% senior notes due 2018	—			—		14			15
	6.50% senior notes due May 2019	750			717		750			755
	6.25% senior notes due November 2019	1,800			1,692		1,800			1,802
	8.625% senior notes due 2020	1,300			1,347		1,300			1,414
	7.75% senior notes due 2021	1,000			1,001		1,000			1,061
	Less current maturities	—			—		—			—
		6,555			$	6,462	6,085			$	6,271
	Unamortized discount	(42		)			(47		)
	Total debt, net of discount	$	6,513				$	6,038
	(1)	The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions.
	(2)	Variable interest rates of 1.93% and 1.97% at September 30, 2013, and December 31, 2012, respectively.
	Credit Facility
	In April 2013, the Company entered into a Sixth Amended and Restated Credit Agreement (“Credit Facility”), which provides for a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount of $4.0 billion. The borrowing base remained unchanged at $4.5 billion and does not include any assets to be acquired in the pending transaction with Berry (see Note 2). The maturity date is April 2018. The amended and restated agreement is substantially similar to the previous Credit Facility with revisions to permit the transactions related to the acquisition of Berry and to designate Berry as an unrestricted subsidiary under the agreement. At September 30, 2013, the borrowing capacity under the Credit Facility was approximately $2.3 billion, which includes a $5 million reduction in availability for outstanding letters of credit.
	Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October, as well as once annually upon requested interim redetermination by the lenders at their sole discretion. The Company also has the right to request one additional borrowing base redetermination per year at its discretion, as well as the right to an additional 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 Credit Facility are secured by mortgages on its and certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in its direct and indirect material subsidiaries. The Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on the most recent reserve report, or 2) a Collateral Coverage Ratio of at least 2.5 to 1. Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. Additionally, the obligations under the Credit Facility are guaranteed by all of the Company’s material subsidiaries and are required to be guaranteed by any future material subsidiaries.
	At the Company’s election, interest on borrowings under the 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 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 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 Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% on the average daily unused amount of the lesser of: (i) the maximum commitment amount of the lenders and (ii) the then-effective borrowing base. The Company is in compliance with all financial and other covenants of the Credit Facility.
	Senior Notes Due November 2019
	On March 2, 2012, the Company issued $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (“November 2019 Senior Notes”) at a price of 99.989%. The November 2019 Senior Notes were sold to a group of initial purchasers and then resold to qualified institutional buyers, each in transactions exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Company received net proceeds of approximately $1.77 billion (after deducting the initial purchasers’ discount of $198,000 and offering expenses of approximately $29 million). The Company used the net proceeds to fund the BP acquisition (see Note 2). The remaining proceeds were used to repay indebtedness under the Company’s Credit Facility and for general corporate purposes. The financing fees and expenses of approximately $29 million incurred in connection with the November 2019 Senior Notes will be amortized over the life of the notes. Such amortized financing fees and expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.
	The November 2019 Senior Notes were issued under an indenture dated March 2, 2012 (“November 2019 Indenture”), mature November 1, 2019, and bear interest at 6.25%. Interest is payable semi-annually on May 1 and November 1, beginning November 1, 2012. The November 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 has guaranteed the November 2019 Senior Notes on a senior unsecured basis. The November 2019 Indenture provides that the Company may redeem: (i) on or prior to November 1, 2015, up to 35% of the aggregate principal amount of the November 2019 Senior Notes at a redemption price of 106.25% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the November 2019 Indenture) and accrued and unpaid interest; and (iii) on or after November 1, 2015, all or part of the November 2019 Senior Notes at a redemption price equal to 103.125%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The November 2019 Indenture also provides that, if a change of control (as defined in the November 2019 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the November 2019 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.
	The November 2019 Indenture contains covenants substantially similar to those under the Company’s May 2019 Senior Notes, 2010 Issued Senior Notes and 2018 Senior Notes, as defined below, that, among other things, limit the Company’s 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 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 identical to the November 2019 Senior Notes in exchange for outstanding November 2019 Senior Notes within 400 days after the notes were issued. On March 22, 2013, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the November 2019 Senior Notes. As of October 28, 2013, the registration statement has not been declared effective and due to the pending SEC inquiry (see Note 16), the timing for the registration statement to be declared effective is uncertain. Accordingly, beginning on April 8, 2013, interest accruing on the November 2019 Senior Notes increased by 0.25%, and will increase by an additional 0.25% on the 90th, 180th and 270th day after such date until such registration statement is declared effective and the Company completes an offer to exchange the November 2019 Senior Notes for registered notes. Such additional interest is expected to be approximately $7 million through December 2013 and will continue to increase until the registration statement is declared effective.
	Senior Notes Due May 2019
	The Company has $750 million in aggregate principal amount of 6.50% senior notes due 2019 (the “May 2019 Senior Notes”). The indentures related to the May 2019 Senior Notes contain redemption provisions and covenants that are substantially similar to those of the November 2019 Senior Notes. In an exchange offer that expired in October 2012, the Company exchanged all of its $750 million outstanding principal amount of May 2019 Senior Notes for an equal amount of new May 2019 Senior Notes. The terms of the new May 2019 Senior Notes are identical in all material respects to those of the outstanding May 2019 Senior Notes, except that the transfer restrictions, registration rights and additional interest provisions relating to the outstanding May 2019 Senior Notes do not apply to the new May 2019 Senior Notes.
	Senior Notes Due 2020 and Senior Notes Due 2021
	The Company has $1.3 billion in aggregate principal amount of 8.625% senior notes due 2020 (the “2020 Senior Notes”) and $1.0 billion in aggregate principal amount of 7.75% senior notes due 2021 (the “2021 Senior Notes,” and together with the 2020 Senior Notes, the “2010 Issued Senior Notes”). The indentures related to the 2010 Issued Senior Notes contain redemption provisions and covenants that are substantially similar to those of the November 2019 Senior Notes. However, 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.
	Redemptions of Senior Notes Due 2017 and Senior Notes Due 2018
	In accordance with the provisions of the indentures related to the Company’s 11.75% senior notes due 2017 (the “2017 Senior Notes”) and 9.875% senior notes due 2018 (the “2018 Senior Notes” and together with the 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 nine months ended September 30, 2013.

Derivatives

Derivatives	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives
	Commodity Derivatives
	The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company has historically entered into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.
	The following table summarizes derivative positions for the periods indicated as of September 30, 2013:
		October 1 - December 31, 2013			2014			2015			2016			2017			2018
	Natural gas positions:
	Fixed price swaps:
	Hedged volume (MMMBtu)	22,002			97,401			118,041			121,841			120,122			36,500
	Average price ($/MMBtu)	$	5.22		$	5.25		$	5.19		$	4.2		$	4.26		$	5
	Put options: (1)
	Hedged volume (MMMBtu)	21,727			79,628			71,854			76,269			66,886			—
	Average price ($/MMBtu)	$	5.37		$	5		$	5		$	5		$	4.88		$	—
	Total:
	Hedged volume (MMMBtu)	43,729			177,029			189,895			198,110			187,008			36,500
	Average price ($/MMBtu)	$	5.29		$	5.14		$	5.12		$	4.51		$	4.48		$	5
	Oil positions:
	Fixed price swaps: (2)
	Hedged volume (MBbls)	2,992			11,903			11,599			11,464			4,755			—
	Average price ($/Bbl)	$	94.97		$	92.92		$	96.23		$	90.56		$	89.02		$	—
	Put options:
	Hedged volume (MBbls)	783			3,960			3,426			3,271			384			—
	Average price ($/Bbl)	$	97.86		$	91.3		$	90		$	90		$	90		$	—
	Total:
	Hedged volume (MBbls)	3,775			15,863			15,025			14,735			5,139			—
	Average price ($/Bbl)	$	95.57		$	92.52		$	94.81		$	90.44		$	89.1		$	—
	Natural gas basis differential positions: (3)
	Panhandle basis swaps:
	Hedged volume (MMMBtu)	19,545			79,388			87,162			59,954			59,138			16,425
	Hedged differential ($/MMBtu)	$	(0.56	)	$	(0.33	)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)
	NWPL Rockies basis swaps:
	Hedged volume (MMMBtu)	9,010			39,718			43,292			46,294			38,880			10,804
	Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	0.2		$	(0.19	)	$	(0.19	)
	MichCon basis swaps:
	Hedged volume (MMMBtu)	2,420			9,490			9,344			7,768			7,437			2,044
	Hedged differential ($/MMBtu)	$	0.1		$	0.08		$	0.06		$	0.05		$	0.05		$	0.05
	Houston Ship Channel basis swaps:
	Hedged volume (MMMBtu)	1,444			5,256			4,891			4,575			3,604			986
	Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.08	)	$	(0.08	)
	Permian basis swaps:
	Hedged volume (MMMBtu)	1,168			4,891			5,074			4,219			4,819			1,314
	Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.21	)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)
	Oil basis differential positions: (3)
	Midland - Cushing basis swaps:
	Hedged volume (MBbls)	506			—			—			—			—			—
	Hedged differential ($/Bbl)	$	(0.95	)	$	—		$	—		$	—		$	—		$	—
	Oil timing differential positions:
	Trade month roll swaps: (4)
	Hedged volume (MBbls)	1,750			7,254			7,251			7,446			6,486			—
	Hedged differential ($/Bbl)	$	0.22		$	0.22		$	0.24		$	0.25		$	0.25		$	—
	(1)	Includes certain outstanding natural gas put options of approximately 2,664 MMMBtu for the period October 1, 2013, through December 31, 2013, 10,570 MMMBtu for each of the years ending December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to indirectly hedge revenues associated with NGL production.
	(2)	Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.
	(3)	Settle on the respective pricing index to hedge basis differential associated with natural gas and oil production.
	(4)	The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil 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 nine months ended September 30, 2013, the Company entered into commodity derivative contracts consisting of oil basis swaps for April 2013 through December 2013 and natural gas basis swaps for October 2013 through 2018.
	Settled derivatives on natural gas production for the three months and nine months ended September 30, 2013, included volumes of 43,729 MMMBtu and 129,760 MMMBtu, respectively, at an average contract price of $5.29 per MMBtu. Settled derivatives on oil production for the three months and nine months ended September 30, 2013, included volumes of 3,775 MBbls and 11,201 MBbls, respectively, at an average contract price of $95.57 per Bbl. Settled derivatives on natural gas production for the three months and nine months ended September 30, 2012, included volumes of 40,202 MMMBtu and 98,282 MMMBtu, respectively, at average contract prices of $5.31 per MMBtu and $5.49 per MMBtu. Settled derivatives on oil production for the three months and nine months ended September 30, 2012, included volumes of 2,951 MBbls and 8,259 MBbls, respectively, at average contract prices of $97.44 per Bbl and $97.80 per Bbl. The natural gas derivatives are settled based on the closing price of NYMEX natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX light crude oil for each day of the delivery month.
	Balance Sheet Presentation
	The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:
		September 30,			December 31,
		2013			2012
		(in thousands)
	Assets:
	Commodity derivatives	$	1,073,942		$	1,282,390
	Liabilities:
	Commodity derivatives	$	233,107		$	405,619
By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $1.1 billion at September 30, 2013. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.
Gains (Losses) on Derivatives
Gains and losses on derivatives were net losses of approximately $64 million for the three months ended September 30, 2013, and net gains of approximately $154 million for the nine months ended September 30, 2013. Gains and losses on derivatives were net losses of approximately $411 million for the three months ended September 30, 2012, and net gains of approximately $30 million for the nine months ended September 30, 2012. Gains and losses are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.”

Fair_Value_Measurements_on_a_R

Fair Value Measurements on a Recurring Basis	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]
Fair Value Measurements on a Recurring Basis	Fair Value Measurements on a Recurring Basis
	The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities 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.
	The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
		30-Sep-13
		Level 2		Netting (1)			Total
		(in thousands)
	Assets:
	Commodity derivatives	$	1,073,942	$	(220,643	)	$	853,299
	Liabilities:
	Commodity derivatives	$	233,107	$	(220,643	)	$	12,464
		31-Dec-12
		Level 2		Netting (1)			Total
		(in thousands)
	Assets:
	Commodity derivatives	$	1,282,390	$	(401,479	)	$	880,911
	Liabilities:
	Commodity derivatives	$	405,619	$	(401,479	)	$	4,140
	(1)	Represents counterparty netting under agreements governing such derivatives.

Asset_Retirement_Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2013
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations
	Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other accrued liabilities” and “other noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for the nine months ended September 30, 2013); and (iv) a credit-adjusted risk-free interest rate (average of 6.4% for the nine months ended September 30, 2013). 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 asset retirement obligations (in thousands):
	Asset retirement obligations at December 31, 2012	$	151,974
	Liabilities added from acquisitions	639
	Liabilities added from drilling	2,803
	Liabilities associated with assets sold	(1,092		)
	Current year accretion expense	8,463
	Settlements	(3,758		)
	Revision of estimates	20,287
	Asset retirement obligations at September 30, 2013	$	179,316

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies
	The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. The Company has established reserves that management currently believes are adequate to provide for potential liabilities based upon its evaluation of these matters. With respect to a certain statewide class action royalty payment dispute, the parties in this case are currently engaged in settlement negotiations and based on the current status of those negotiations, the Company estimates a range of possible loss of $1 million to $4.5 million, for which an appropriate reserve has been established. For a certain statewide class action royalty payment dispute where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to the Company. Discovery related to class certification has concluded. Briefing and the hearing on class certification have been deferred by court order pending the Tenth Circuit Court of Appeals’ resolution of interlocutory appeals of two unrelated class certification orders. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any. In addition, the Company is involved in various other disputes arising in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
	On March 21, 2013, a purported stockholder class action captioned Nancy P. Assad Trust v. Berry Petroleum Co., et al. was filed in the District Court for the City and County of Denver, Colorado, No. 13-CV-31365. The action names as defendants Berry, the members of its board of directors, Bacchus HoldCo, Inc., a direct wholly owned subsidiary of Berry (“HoldCo”), Bacchus Merger Sub, Inc., a direct wholly owned subsidiary of HoldCo (“Bacchus Merger Sub”), LinnCo, LINN Energy and Linn Acquisition Company, LLC, a direct wholly owned subsidiary of LinnCo (“LinnCo Merger Sub”). On April 5, 2013, an amended complaint was filed, which alleges that the individual defendants breached their fiduciary duties in connection with the transactions by engaging in an unfair sales process that resulted in an unfair price for Berry, by failing to disclose all material information regarding the transactions, and that the entity defendants aided and abetted those breaches of fiduciary duty. The amended complaint seeks a declaration that the transactions are unlawful and unenforceable, an order directing the individual defendants to comply with their fiduciary duties, an injunction against consummation of the transactions, or, in the event they are completed, rescission of the transactions, an award of fees and costs, including attorneys’ and experts’ fees and expenses, and other relief. On May 21, 2013, the Colorado District Court stayed and administratively closed the Nancy P. Assad Trust action in favor of the Hall action described below that is pending in the Delaware Court of Chancery.
	On April 12, 2013, a purported stockholder class action captioned David Hall v. Berry Petroleum Co., et al. was filed in the Delaware Court of Chancery, C.A. No. 8476-VCG. The complaint names as defendants Berry, the members of its board of directors, HoldCo, Bacchus Merger Sub, LinnCo, LINN Energy and LinnCo Merger Sub. The complaint alleges that the individual defendants breached their fiduciary duties in connection with the transactions by engaging in an unfair sales process that resulted in an unfair price for Berry, by failing to disclose all material information regarding the transactions, and that the entity defendants aided and abetted those breaches of fiduciary duty. The complaint seeks a declaration that the transactions are unlawful and unenforceable, an order directing the individual defendants to comply with their fiduciary duties, an injunction against consummation of the transactions, or, in the event they are completed, rescission of the transactions, an award of fees and costs, including attorneys’ and experts’ fees and expenses, and other relief. The Company is unable to estimate a possible loss, or range of possible loss, if any, at this time.
	On July 9, 2013, Anthony Booth, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of Texas, against LINN Energy, Mark E. Ellis, Kolja Rockov, and David B. Rottino (the “Booth Action”). On July 18, 2013, the Catherine A. Fisher Trust, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of Texas, against the same defendants (the “Fisher Action”). On July 17, 2013, Don Gentry, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of Texas, against LINN Energy, LinnCo, Mark E. Ellis, Kolja Rockov, David B. Rottino, George A. Alcorn, David D. Dunlap, Terrence S. Jacobs, Michael C. Linn, Joseph P. McCoy, Jeffrey C. Swoveland, and the various underwriters for LinnCo’s initial public offering (the “Gentry Action”) (the Booth Action, Fisher Action, and Gentry Action together, the “Texas Federal Actions”). The Texas Federal Actions each assert claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the “Exchange Act”) based on allegations that LINN Energy made false or misleading statements relating to its hedging strategy, the cash flow available for distribution to unitholders, and LINN Energy’s energy production. The Gentry Action asserts additional claims under Sections 11 and 15 of the Securities Act of 1933 based on alleged misstatements relating to these issues in the prospectus and registration statement for LinnCo’s initial public offering. On September 23, 2013, the Southern District of Texas entered an order transferring the Texas Federal Actions to the Southern District of New York so that they could be consolidated with the New York Federal Actions, which are described below.
	On July 10, 2013, David Adrian Luciano, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of New York, against LINN Energy, LinnCo, Mark E. Ellis, Kolja Rockov, David B. Rottino, George A. Alcorn, David D. Dunlap, Terrence S. Jacobs, Michael C. Linn, Joseph P. McCoy, Jeffrey C. Swoveland, and the various underwriters for LinnCo’s initial public offering (the “Luciano Action”). The Luciano Action asserts claims under Sections 11 and 15 of the Securities Act of 1933 based on alleged misstatements relating to LINN Energy’s hedging strategy, the cash flow available for distribution to unitholders, and LINN Energy’s energy production in the prospectus and registration statement for LinnCo’s initial public offering. On July 12, 2013, Frank Donio, individually and on behalf of all other persons similarly situated, filed a class action complaint in the United States District Court, Southern District of New York, against LINN Energy, Mark E. Ellis, Kolja Rockov, and David B. Rottino (the “Donio Action”). The Donio Action asserts claims under Sections 10(b) and 20(a) of the Exchange Act based on allegations that LINN Energy made false or misleading statements relating to its hedging strategy, the cash flow available for distribution to unitholders, and LINN Energy’s energy production. Several additional class action cases substantially similar to the Luciano Action and the Donio Action were subsequently filed in the Southern District of New York and assigned to the same judge (the Luciano Action, Donio Action, and all similar subsequently filed New York federal class actions together, the “New York Federal Actions”). The Texas Federal Actions and the New York Federal Actions have now been consolidated in the United States District Court for the Southern District of New York. The cases are in their preliminary stages and it is possible that additional similar actions could be filed. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any.
	On July 10, 2013, Judy Mesirov, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against Mark E. Ellis, Kolja Rockov, David B. Rottino, Arden L. Walker, Jr., Charlene A. Ripley, Michael C. Linn, Joseph P. McCoy, George A. Alcorn, Terrence S. Jacobs, David D. Dunlap, Jeffrey C. Swoveland, and Linda M. Stephens in the District Court of Harris County, Texas (the “Mesirov Action”). On July 12, 2013, John Peters, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants in the District Court of Harris County, Texas (the “Peters Action”). On August 26, 2013, Joseph Abdalla, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants in the District Court of Harris County, Texas (the “Abdalla Action”) (the Mesirov Action, Peters Action, and Abdalla Actions together, the “Texas State Court Derivative Actions”). On August 19, 2013, the Charlote J. Lombardo Trust of 2004, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants in the United States District Court for the Southern District of Texas (the “Lombardo Action”). On September 30, 2013, the Thelma Feldman Rev. Trust, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants (the “Feldman Rev. Trust Action”). On October 21, 2013, the Parker Family Trust of 2012, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants (the “Parker Family Trust Action”) (the Lombardo Action, Feldman Rev. Trust Action, and Parker Family Trust Action together, the “Texas Federal Court Derivative Actions”) (the Texas State Court Derivative Action and Texas Federal Court Derivative Actions together, the “Texas Derivative Actions”). The Texas Derivative Actions assert derivative claims on behalf of LINN Energy against the individual defendants for alleged breaches of fiduciary duty, waste of corporate assets, mismanagement, abuse of control, and unjust enrichment based on factual allegations similar to those in the Texas Federal Actions and the New York Federal Actions. The cases are in their preliminary stages and it is possible that additional similar actions could be filed in the District Court of Harris County, Texas, or in other jurisdictions. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any.
	In 2008, Lehman Brothers Holdings Inc. and Lehman Brothers Commodity Services Inc. (together “Lehman”), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. In March 2011, the Company and Lehman entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman in the amount of $51 million (the “Company Claim”). In December 2011, a Chapter 11 Plan (“Lehman Plan”) was approved by the Bankruptcy Court. Based on the recovery estimates described in the approved disclosure statement relating to the Lehman Plan, the Company expects to ultimately receive a substantial portion of the Company Claim. In April 2012, an initial distribution under the Lehman Plan of approximately $25 million was received by the Company resulting in a gain of approximately $18 million, and in April 2013, the Company received approximately $5 million of the Company Claim, both of which are included in “gains (losses) on oil and natural gas derivatives” on the condensed consolidated statements of operations. In the aggregate, the Company has received approximately $33 million, including approximately $3 million received in October 2012, of the Company Claim and additional distributions are expected to occur in the future.

Earnings_Per_Unit

Earnings Per Unit	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]
Earnings Per Unit	Earnings Per Unit
	Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect.
	The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net income:
		Net Income (Loss)			Units	Per Unit
		(Numerator)			(Denominator)	Amount
		(in thousands)
	Three months ended September 30, 2013:
	Net loss:
	Allocated to units	$	(30,060	)
	Allocated to participating securities	(1,266		)
		$	(31,326	)
	Net loss per unit:
	Basic net loss per unit				233,552	$	(0.13	)
	Dilutive effect of unit equivalents				—	—
	Diluted net loss per unit				233,552	$	(0.13	)
	Three months ended September 30, 2012:
	Net loss:
	Allocated to units	$	(430,005	)
	Allocated to participating securities	(1,398		)
		$	(431,403	)
	Net loss per unit:
	Basic net loss per unit				197,675	$	(2.18	)
	Dilutive effect of unit equivalents				—	—
	Diluted net loss per unit				197,675	$	(2.18	)
	Nine months ended September 30, 2013:
	Net income:
	Allocated to units	$	93,212
	Allocated to participating securities	(3,796		)
		$	89,416
	Net income per unit:
	Basic net income per unit				233,393	$	0.38
	Dilutive effect of unit equivalents				372	—
	Diluted net income per unit				233,765	$	0.38
	Nine months ended September 30, 2012:
	Net loss:
	Allocated to units	$	(199,121	)
	Allocated to participating securities	(4,165		)
		$	(203,286	)
	Net loss per unit:
	Basic net loss per unit				196,152	$	(1.04	)
	Dilutive effect of unit equivalents				—	—
	Diluted net loss per unit				196,152	$	(1.04	)
	Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 4 million and 3 million unit options and warrants for the three months and nine months ended September 30, 2013, respectively. Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 1 million unit options and warrants for the three months and nine months ended September 30, 2012. All equivalent units were antidilutive for the three months ended September 30, 2013, and for the three months and nine months ended September 30, 2012.

Income_Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2013
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes
	The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. 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. Amounts recognized for income taxes are reported in “income tax expense (benefit)” on the condensed consolidated statements of operations.

Supplemental_Disclosures_to_th

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows	9 Months Ended
	Sep. 30, 2013
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows	Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows
	“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:
		September 30,			December 31,
		2013			2012
		(in thousands)
	Accrued compensation	$	24,931		$	35,431
	Accrued interest	124,029			72,668
	Other	7,178			7,146
		$	156,138		$	115,245
	Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
		Nine Months Ended
		September 30,
		2013			2012
		(in thousands)
	Cash payments for interest, net of amounts capitalized	$	240,261		$	178,194
	Cash payments for income taxes	$	14		$	306
	Noncash investing activities:
	In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follows:
	Fair value of assets acquired	$	47,901		$	2,854,410
	Cash paid	(28,524		)	(2,487,767		)
	Receivables from sellers	3,654			772
	Payables to sellers	(6,854		)	(422		)
	Liabilities assumed	$	16,177		$	366,993
	Included in “acquisition of oil and natural gas properties and joint-venture funding” on the condensed consolidated statements of cash flows for the nine months ended September 30, 2013, is approximately $112 million paid by the Company towards the future funding commitment related to the joint-venture agreement entered into with Anadarko and a deposit of approximately $53 million paid by the Company for the acquisition in the Permian Basin region that is pending at September 30, 2013 (see Note 2).
	For purposes of the condensed 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 $5 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at September 30, 2013, and December 31, 2012, and represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.
	The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facility. At December 31, 2012, net outstanding checks of approximately $35 million were reclassified and included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet. There was no such balance at September 30, 2013. The Company presents net outstanding checks as cash flows from financing activities on the condensed consolidated statements of cash flows.

Related_Party_Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2013
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions
	LinnCo
	LinnCo, an affiliate of LINN Energy, was formed on April 30, 2012, for the sole purpose of owning units in LINN Energy. 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 which represent approximately 15% of LINN Energy’s outstanding units at September 30, 2013. All of LinnCo’s common shares are held by the public. As of September 30, 2013, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy. In connection with the pending acquisition of Berry (see Note 2), LinnCo intends to amend its limited liability company agreement to permit the acquisition and subsequent contribution of assets to LINN Energy.
	LINN Energy has agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any legal, accounting, tax advisory, financial advisory and engineering fees, printing costs or other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity. These expenses include costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees. In addition, the Company has agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities.
	For the three months and nine months ended September 30, 2013, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $1 million and $15 million, respectively, of which approximately $9 million had been paid by LINN Energy on LinnCo’s behalf as of September 30, 2013. The expenses for the three months and nine months ended September 30, 2013, include approximately $125,000 and $13 million, respectively, of transaction costs related to professional services rendered by third parties in connection with the pending acquisition of Berry (see Note 2). The expenses for the three months and nine months ended September 30, 2013, also include approximately $403,000 and $1 million, respectively, 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 $361,000 were incurred in connection with LinnCo’s registration statement on Form S-4 also related to the pending acquisition of Berry. All expenses and costs paid by LINN Energy on LinnCo’s behalf are accounted for as investment at cost.
	During the nine months ended September 30, 2013, the Company paid approximately $76 million in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy.
	Other
	One of the Company’s directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the three months and nine months ended September 30, 2013, the Company paid approximately $7 million and $20 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	9 Months Ended
	Sep. 30, 2013
Guarantees [Abstract]
Subsidiary Guarantors	Subsidiary Guarantors
	The November 2019 Senior Notes, the May 2019 Senior Notes and the 2010 Issued Notes are guaranteed by all of the Company’s material subsidiaries. The Company is a holding company and has no independent assets or operations of its own, the guarantees under each series of notes are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.

SEC_Inquiry

SEC Inquiry	9 Months Ended
	Sep. 30, 2013
SEC Inquiry [Abstract]
SEC Inquiry	SEC Inquiry
	As disclosed on July 1, 2013, the Company and its affiliate, LinnCo, have been notified by the staff of the SEC that its Fort Worth Regional Office has commenced an inquiry regarding LINN Energy and LinnCo (the “SEC inquiry”). The SEC staff is investigating whether any violations of federal securities laws have occurred. The SEC staff has requested the production of documents and communications that are potentially relevant to, among other things, LINN Energy and LinnCo’s use of non-GAAP financial measures and disclosures related to LINN Energy’s hedging strategy. The SEC staff has stated that the fact of the inquiry should not be construed as an indication that the SEC or its staff has a negative view of any entity, individual or security. Both LINN Energy and LinnCo are cooperating fully with the SEC in this matter. Due to the pending SEC inquiry, the timing of closing of the merger with Berry is uncertain. LINN Energy and LinnCo are unable to predict the timing or outcome of the SEC inquiry or estimate the nature or amount of any possible sanction the SEC could seek to impose, which could include a fine, penalty, or court or administrative order prohibiting specific conduct, or a potential restatement of LINN Energy’s or LinnCo’s financial statements, any of which could be material. No provision for losses has been recorded for this exposure.

Basis_of_Presentation_Policies

Basis of Presentation (Policies)	9 Months Ended
	Sep. 30, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Principles of Consolidation and Reporting	Principles of Consolidation and Reporting
	The condensed consolidated financial statements at September 30, 2013, and for the three months and nine months ended September 30, 2013, and September 30, 2012, are unaudited, but in the opinion of management include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.
	The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. The Company’s other investment is accounted for at cost.
	The condensed 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 condensed consolidated financial statements in conformity with GAAP requires Company management 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.

Oil_and_Natural_Gas_Properties1

Oil and Natural Gas Properties (Tables)	9 Months Ended
	Sep. 30, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized Costs Related to Oil, Natural Gas and NGL Production Activities	Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:
		September 30,			December 31,
		2013			2012
		(in thousands)
	Proved properties:
	Leasehold acquisition	$	8,505,622		$	8,603,888
	Development	3,316,007			2,553,127
	Unproved properties	389,979			454,315
		12,211,608			11,611,330
	Less accumulated depletion and amortization	(2,545,182		)	(2,025,656		)
		$	9,666,426		$	9,585,674

UnitBased_Compensation_Tables

Unit-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Employee Service Share-Based Compensation Expense	A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
		(in thousands)
	General and administrative expenses	$	8,407	$	6,505	$	25,408	$	20,416
	Lease operating expenses	1,279		396		3,853		1,319
	Total unit-based compensation expenses	$	9,686	$	6,901	$	29,261	$	21,735
	Income tax benefit	$	3,579	$	2,550	$	10,812	$	8,031

Debt_Tables

Debt (Tables)	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]
Summary of Outstanding Debt	The following summarizes debt outstanding:
		30-Sep-13					December 31, 2012
		Carrying Value			Fair Value (1)		Carrying Value			Fair Value (1)
		(in millions, except percentages)
	Credit facility (2)	$	1,705		$	1,705	$	1,180		$	1,180
	11.75% senior notes due 2017	—			—		41			44
	9.875% senior notes due 2018	—			—		14			15
	6.50% senior notes due May 2019	750			717		750			755
	6.25% senior notes due November 2019	1,800			1,692		1,800			1,802
	8.625% senior notes due 2020	1,300			1,347		1,300			1,414
	7.75% senior notes due 2021	1,000			1,001		1,000			1,061
	Less current maturities	—			—		—			—
		6,555			$	6,462	6,085			$	6,271
	Unamortized discount	(42		)			(47		)
	Total debt, net of discount	$	6,513				$	6,038
	(1)	The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions.
	(2)	Variable interest rates of 1.93% and 1.97% at September 30, 2013, and December 31, 2012, respectively.

Derivatives_Tables

Derivatives (Tables)	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	The following table summarizes derivative positions for the periods indicated as of September 30, 2013:
		October 1 - December 31, 2013			2014			2015			2016			2017			2018
	Natural gas positions:
	Fixed price swaps:
	Hedged volume (MMMBtu)	22,002			97,401			118,041			121,841			120,122			36,500
	Average price ($/MMBtu)	$	5.22		$	5.25		$	5.19		$	4.2		$	4.26		$	5
	Put options: (1)
	Hedged volume (MMMBtu)	21,727			79,628			71,854			76,269			66,886			—
	Average price ($/MMBtu)	$	5.37		$	5		$	5		$	5		$	4.88		$	—
	Total:
	Hedged volume (MMMBtu)	43,729			177,029			189,895			198,110			187,008			36,500
	Average price ($/MMBtu)	$	5.29		$	5.14		$	5.12		$	4.51		$	4.48		$	5
	Oil positions:
	Fixed price swaps: (2)
	Hedged volume (MBbls)	2,992			11,903			11,599			11,464			4,755			—
	Average price ($/Bbl)	$	94.97		$	92.92		$	96.23		$	90.56		$	89.02		$	—
	Put options:
	Hedged volume (MBbls)	783			3,960			3,426			3,271			384			—
	Average price ($/Bbl)	$	97.86		$	91.3		$	90		$	90		$	90		$	—
	Total:
	Hedged volume (MBbls)	3,775			15,863			15,025			14,735			5,139			—
	Average price ($/Bbl)	$	95.57		$	92.52		$	94.81		$	90.44		$	89.1		$	—
	Natural gas basis differential positions: (3)
	Panhandle basis swaps:
	Hedged volume (MMMBtu)	19,545			79,388			87,162			59,954			59,138			16,425
	Hedged differential ($/MMBtu)	$	(0.56	)	$	(0.33	)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)
	NWPL Rockies basis swaps:
	Hedged volume (MMMBtu)	9,010			39,718			43,292			46,294			38,880			10,804
	Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	0.2		$	(0.19	)	$	(0.19	)
	MichCon basis swaps:
	Hedged volume (MMMBtu)	2,420			9,490			9,344			7,768			7,437			2,044
	Hedged differential ($/MMBtu)	$	0.1		$	0.08		$	0.06		$	0.05		$	0.05		$	0.05
	Houston Ship Channel basis swaps:
	Hedged volume (MMMBtu)	1,444			5,256			4,891			4,575			3,604			986
	Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.08	)	$	(0.08	)
	Permian basis swaps:
	Hedged volume (MMMBtu)	1,168			4,891			5,074			4,219			4,819			1,314
	Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.21	)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)
	Oil basis differential positions: (3)
	Midland - Cushing basis swaps:
	Hedged volume (MBbls)	506			—			—			—			—			—
	Hedged differential ($/Bbl)	$	(0.95	)	$	—		$	—		$	—		$	—		$	—
	Oil timing differential positions:
	Trade month roll swaps: (4)
	Hedged volume (MBbls)	1,750			7,254			7,251			7,446			6,486			—
	Hedged differential ($/Bbl)	$	0.22		$	0.22		$	0.24		$	0.25		$	0.25		$	—
	(1)	Includes certain outstanding natural gas put options of approximately 2,664 MMMBtu for the period October 1, 2013, through December 31, 2013, 10,570 MMMBtu for each of the years ending December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to indirectly hedge revenues associated with NGL production.
	(2)	Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.
	(3)	Settle on the respective pricing index to hedge basis differential associated with natural gas and oil production.
	(4)	The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil 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:
		September 30,			December 31,
		2013			2012
		(in thousands)
	Assets:
	Commodity derivatives	$	1,073,942		$	1,282,390
	Liabilities:
	Commodity derivatives	$	233,107		$	405,619

Fair_Value_Measurements_on_a_R1

Fair Value Measurements on a Recurring Basis (Tables)	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]
Fair Value Measurements, Recurring Basis	The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
		30-Sep-13
		Level 2		Netting (1)			Total
		(in thousands)
	Assets:
	Commodity derivatives	$	1,073,942	$	(220,643	)	$	853,299
	Liabilities:
	Commodity derivatives	$	233,107	$	(220,643	)	$	12,464
		31-Dec-12
		Level 2		Netting (1)			Total
		(in thousands)
	Assets:
	Commodity derivatives	$	1,282,390	$	(401,479	)	$	880,911
	Liabilities:
	Commodity derivatives	$	405,619	$	(401,479	)	$	4,140
	(1)	Represents counterparty netting under agreements governing such derivatives.

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2013
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations Reconciliation	The following presents a reconciliation of the asset retirement obligations (in thousands):
	Asset retirement obligations at December 31, 2012	$	151,974
	Liabilities added from acquisitions	639
	Liabilities added from drilling	2,803
	Liabilities associated with assets sold	(1,092		)
	Current year accretion expense	8,463
	Settlements	(3,758		)
	Revision of estimates	20,287
	Asset retirement obligations at September 30, 2013	$	179,316

Earnings_Per_Unit_Tables

Earnings Per Unit (Tables)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]
Reconciliation of numerators and denominators of the basic and diluted per unit computations for net income (loss)	The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net income:
		Net Income (Loss)			Units	Per Unit
		(Numerator)			(Denominator)	Amount
		(in thousands)
	Three months ended September 30, 2013:
	Net loss:
	Allocated to units	$	(30,060	)
	Allocated to participating securities	(1,266		)
		$	(31,326	)
	Net loss per unit:
	Basic net loss per unit				233,552	$	(0.13	)
	Dilutive effect of unit equivalents				—	—
	Diluted net loss per unit				233,552	$	(0.13	)
	Three months ended September 30, 2012:
	Net loss:
	Allocated to units	$	(430,005	)
	Allocated to participating securities	(1,398		)
		$	(431,403	)
	Net loss per unit:
	Basic net loss per unit				197,675	$	(2.18	)
	Dilutive effect of unit equivalents				—	—
	Diluted net loss per unit				197,675	$	(2.18	)
	Nine months ended September 30, 2013:
	Net income:
	Allocated to units	$	93,212
	Allocated to participating securities	(3,796		)
		$	89,416
	Net income per unit:
	Basic net income per unit				233,393	$	0.38
	Dilutive effect of unit equivalents				372	—
	Diluted net income per unit				233,765	$	0.38
	Nine months ended September 30, 2012:
	Net loss:
	Allocated to units	$	(199,121	)
	Allocated to participating securities	(4,165		)
		$	(203,286	)
	Net loss per unit:
	Basic net loss per unit				196,152	$	(1.04	)
	Dilutive effect of unit equivalents				—	—
	Diluted net loss per unit				196,152	$	(1.04	)

Supplemental_Disclosures_to_th1

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Tables)	9 Months Ended
	Sep. 30, 2013
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Other Accrued Liabilities	“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:
		September 30,			December 31,
		2013			2012
		(in thousands)
	Accrued compensation	$	24,931		$	35,431
	Accrued interest	124,029			72,668
	Other	7,178			7,146
		$	156,138		$	115,245
Supplemental Cash Flow Disclosures	Supplemental disclosures to the condensed consolidated statements of cash flows are presented below:
		Nine Months Ended
		September 30,
		2013			2012
		(in thousands)
	Cash payments for interest, net of amounts capitalized	$	240,261		$	178,194
	Cash payments for income taxes	$	14		$	306
	Noncash investing activities:
	In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follows:
	Fair value of assets acquired	$	47,901		$	2,854,410
	Cash paid	(28,524		)	(2,487,767		)
	Receivables from sellers	3,654			772
	Payables to sellers	(6,854		)	(422		)
	Liabilities assumed	$	16,177		$	366,993

Acquisitions_JointVenture_Fund1

Acquisitions, Joint-Venture Funding and Divestiture (Acquisitions, Joint-Venture Funding) (Details) (USD $)	9 Months Ended	18 Months Ended	0 Months Ended			0 Months Ended			9 Months Ended	0 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Apr. 03, 2012	Feb. 20, 2013	Feb. 21, 2013	Jul. 31, 2012	1-May-12	Mar. 30, 2012	Sep. 30, 2013	Oct. 31, 2013	Sep. 30, 2013
			Business Acquisition, Anadarko	Business Acquisition, Berry	Business Acquisition, Berry	Business Acquisition, BP Green River	Business Acquisition, East Texas	Business Acquisition, BP	Business Acquisition, Various	Business Acquisition, Permian Basin [Member]	Business Acquisition, Permian Basin [Member]
Business Acquisition [Line Items]
Future funding commitment of joint venture consideration transferred	$114,000,000	$315,000,000
Future funding of joint venture agreement			400,000,000
Total consideration transferred						990,000,000	168,000,000	1,160,000,000	32,000,000
Contract price of acquisition										525,000,000
Number of LinnCo common shares for each Berry common share				125.00%
Business acquisition, price per common share				$46.24
Business acqusition, preliminary value				4,400,000,000
Debt assumed					1,700,000,000
Joint venture interest acquired			23.00%
Cash deposit	$53,000,000	$53,000,000									$53,000,000

Acquisitions_JointVenture_Fund2

Acquisitions, Joint-Venture Funding and Divestiture (Divestiture) (Details) (USD $)	0 Months Ended	3 Months Ended				9 Months Ended
	31-May-13	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Gain (Loss) on Disposition of Oil and Gas and Timber Property [Abstract]
Impairment of long-lived assets		($4,240,000)			$0	$37,962,000	$146,499,000
Impairment on assets held for sale				57,053,000
Adjustment to impairment of long-lived assets		4,000,000	15,000,000
Proceeds from sale of Panther properties	219,000,000
Costs to sell Panther properties	$2,000,000

Unitholders_Capital_Details

Unitholders' Capital (Details) (USD $)	1 Months Ended		3 Months Ended		9 Months Ended		0 Months Ended
	Jan. 31, 2012	Aug. 31, 2011	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Oct. 14, 2013	Oct. 02, 2013
							Dividend Declared [Member]	Dividend Declared [Member]
Equity [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 maximum value		500,000,000
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	2,000,000
Equity distribution agreement remaining balance			411,000,000		411,000,000
Subsequent Event [Line Items]
Per unit cash dividend declared (in usd per unit)			$0.73	$0.73	$2.17	$2.14		$0.73
Common Stock, Dividends, Per Share, Declared, Monthly								$0.24
Distributions to unitholders					$511,686,000	$426,918,000	$57,000,000

Oil_and_Natural_Gas_Properties2

Oil and Natural Gas Properties (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Proved properties:
Leasehold acquisition	$8,505,622	$8,603,888
Development	3,316,007	2,553,127
Unproved properties	389,979	454,315
Oil and natural gas properties (successful efforts method)	12,211,608	11,611,330
Less accumulated depletion and amortization	-2,545,182	-2,025,656
Oil and natural gas properties, successful efforts method, net	$9,666,426	$9,585,674

UnitBased_Compensation_Narrati

Unit-Based Compensation (Narrative) (Details) (USD $)	9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2013
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted to employees	659,590
Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted to employees	105,530
Share Based Compensation Arrangement Award [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate fair value of grants issued to employees	29
Vesting period of grants issued to employees	3 years

UnitBased_Compensation_Compens

Unit-Based Compensation (Compensation Expenses) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Allocated Share Based Compensation Expense	$9,686	$6,901	$29,261	$21,735
Income tax benefit	3,579	2,550	10,812	8,031
Share-based Compensation Expense Recorded in General and Administrative Expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Allocated Share Based Compensation Expense	8,407	6,505	25,408	20,416
Share-based Compensation Expense Recorded in Lease Operating Expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Allocated Share Based Compensation Expense	$1,279	$396	$3,853	$1,319

Debt_Details

Debt (Details) (USD $)

3 Months Ended

9 Months Ended

9 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

3 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Apr. 24, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Jun. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2009

Jul. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2008

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2010

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2010

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Credit Facility

Credit Facility

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Line of Credit

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Subordinated Debt

Less Current Maturities

Less Current Maturities

Total Debt Less Current Maturities

Total Debt Less Current Maturities

Minimum

Maximum

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Credit Facility

Senior Notes Due 2017

Senior Notes Due 2017

Senior Notes Due 2017

Senior Notes Due 2017

Senior Notes Due 2018

Senior Notes Due 2018

Senior Notes Due 2018

Senior Notes Due 2018

Senior Notes Due May 2019

Senior Notes Due May 2019

Senior Notes Due May 2019

Senior Notes Due November 2019

Senior Notes Due November 2019

Senior Notes Due November 2019

Senior Notes Due 2020

Senior Notes Due 2020

Senior Notes Due 2020

Senior Notes Due 2021

Senior Notes Due 2021

Senior Notes Due 2021

LIBOR

LIBOR

ABR

ABR

Minimum

Maximum

Minimum

Maximum

Debt Instrument [Line Items]

Long-term Debt, Gross

$1,705,000,000

[1]

$1,180,000,000

[1]

$0

$41,000,000

$0

$14,000,000

$750,000,000

$750,000,000

$1,800,000,000

$1,800,000,000

$1,300,000,000

$1,300,000,000

$1,000,000,000

$1,000,000,000

Long-term Debt, Current Maturities

0

0

Long-term Debt

6,555,000,000

6,085,000,000

Debt Instrument, Unamortized Discount

42,000,000

47,000,000

Long-term Debt, Excluding Current Maturities

6,513,000,000

6,513,000,000

6,038,000,000

Long-term Debt, Fair Value

1,705,000,000

[1],[2]

1,180,000,000

[1],[2]

0

[2]

44,000,000

[2]

0

[2]

15,000,000

[2]

717,000,000

[2]

755,000,000

[2]

1,692,000,000

[2]

1,802,000,000

[2]

1,347,000,000

[2]

1,414,000,000

[2]

1,001,000,000

[2]

1,061,000,000

[2]

0

[2]

0

[2]

6,462,000,000

[2]

6,271,000,000

[2]

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

1.93%

1.97%

Line of Credit Facility, redetermined borrowing base

4,500,000,000

Line of Credit Facility, Maximum Borrowing Capacity

4,000,000,000

Line of Credit Facility, Remaining Borrowing Capacity

2,300,000,000

Outstanding letters of credit that reduce the credit facility availability

5,000,000

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

Debt Instrument, Basis Spread on Variable Rate

1.50%

2.50%

0.50%

1.50%

Line of Credit Facility, Unused Capacity, Commitment Fee Percentage

0.38%

0.50%

Debt Instrument, Face Amount

750,000,000

750,000,000

1,800,000,000

1,300,000,000

1,000,000,000

Additional interest payable due to late registration

7,000,000

Debt instrument, interest rate, stated percentage (in hundredths)

11.75%

9.88%

6.50%

6.25%

8.63%

7.75%

Issue price of debt instruments as percentage of face amount (in hundredths)

99.99%

Net proceeds received

1,770,000,000

Unamortized discount

-198,000

Financing fees and expenses incurred related to the issuance of long-term debt

29,000,000

Maximum Percentage Of November 2019 Senior Notes Redeemable On Before 2015

35.00%

Redemption Price Percentage For Redemption On Before 2015

106.25%

Redemption Price Percentage For Redemption After November 2015

103.13%

Redemption Price Percentage Of Senior Notes If Change Of Control

101.00%

Number Of Days For Effective Registration Statement

400 days

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

0.25%

Extinguishment of debt

41,000,000

14,000,000

Loss on extinguishment of debt

$1,117,000

$0

$5,304,000

$0

$5,000,000

[1]

Variable interest rates of 1.93% and 1.97% at SeptemberB 30, 2013, and DecemberB 31, 2012, respectively.

[2]

The carrying value of the Credit Facility is estimated to be substantially the same as its fair value. Fair values of the senior notes were estimated based on prices quoted from third-party financial institutions.

Derivatives_Commodity_Derivati

Derivatives (Commodity Derivatives) (Details)

3 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Jun. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

MBbls

MBbls

MMMBTU

MBbls

2013

2013

2013

2013

2013

2013

2013

2013

2013

2013

2013

2013

2013

2013

2014

2014

2014

2014

2014

2014

2014

2014

2014

2014

2014

2014

2014

2014

2015

2015

2015

2015

2015

2015

2015

2015

2015

2015

2015

2015

2015

2015

2016

2016

2016

2016

2016

2016

2016

2016

2016

2016

2016

2016

2016

2016

2017

2017

2017

2017

2017

2017

2017

2017

2017

2017

2017

2017

2017

2017

2017

2018

2018

2018

2018

2018

2018

2018

2018

2018

2018

2018

2018

2018

2018

2019

MMMBTU

MMMBTU

MBbls

MMMBTU

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Oil Basis Differential Commodity Contract [Member]

Oil Timing Differential Positions

Natural Gas Liquid Commodity Contract

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Oil Basis Differential Commodity Contract [Member]

Oil Timing Differential Positions

Natural Gas Liquid Commodity Contract

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Oil Basis Differential Commodity Contract [Member]

Oil Timing Differential Positions

Natural Gas Liquid Commodity Contract

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Oil Basis Differential Commodity Contract [Member]

Oil Timing Differential Positions

Natural Gas Liquid Commodity Contract

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Oil Basis Differential Commodity Contract [Member]

Oil Timing Differential Positions

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Natural Gas Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Oil Derivative Instruments

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Natural Gas Basis Differential Positions

Oil Basis Differential Commodity Contract [Member]

Oil Timing Differential Positions

Oil Derivative Instruments

MMMBTU

Fixed price swaps

Puts

MBbls

Fixed price swaps

Puts

Panhandle Basis Swaps

NWPL - Rockies basis swaps

MichCon Basis Swaps

Houston Ship Channel Basis Swaps

Permian Basis Swaps

Midland-Cushing Basis Swaps [Member]

Trade month roll swaps

Puts

MMMBTU

Fixed price swaps

Puts

MBbls

Fixed price swaps

Puts

Panhandle Basis Swaps

NWPL - Rockies basis swaps

MichCon Basis Swaps

Houston Ship Channel Basis Swaps

Permian Basis Swaps

Midland-Cushing Basis Swaps [Member]

Trade month roll swaps

Puts

MMMBTU

Fixed price swaps

Puts

MBbls

Fixed price swaps

Puts

Panhandle Basis Swaps

NWPL - Rockies basis swaps

MichCon Basis Swaps

Houston Ship Channel Basis Swaps

Permian Basis Swaps

Midland-Cushing Basis Swaps [Member]

Trade month roll swaps

Puts

MMMBTU

Fixed price swaps

Puts

MBbls

Fixed price swaps

Puts

Panhandle Basis Swaps

NWPL - Rockies basis swaps

MichCon Basis Swaps

Houston Ship Channel Basis Swaps

Permian Basis Swaps

Midland-Cushing Basis Swaps [Member]

Trade month roll swaps

Puts

MMMBTU

Fixed price swaps

Puts

MBbls

Fixed price swaps

Puts

Extendible Fixed Price Swaps

Extendible Fixed Price Swaps

Panhandle Basis Swaps

NWPL - Rockies basis swaps

MichCon Basis Swaps

Houston Ship Channel Basis Swaps

Permian Basis Swaps

Midland-Cushing Basis Swaps [Member]

Trade month roll swaps

MMMBTU

Fixed price swaps

Puts

MBbls

Fixed price swaps

Puts

Extendible Fixed Price Swaps

Panhandle Basis Swaps

NWPL - Rockies basis swaps

MichCon Basis Swaps

Houston Ship Channel Basis Swaps

Permian Basis Swaps

Midland-Cushing Basis Swaps [Member]

Trade month roll swaps

Extendible Fixed Price Swaps

MMMBTU

MMMBTU

MBbls

MBbls

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MBbls

MBbls

MMMBTU

MMMBTU

MMMBTU

MBbls

MBbls

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MBbls

MBbls

MMMBTU

MMMBTU

MMMBTU

MBbls

MBbls

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MBbls

MBbls

MMMBTU

MMMBTU

MMMBTU

MBbls

MBbls

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MBbls

MBbls

MMMBTU

MMMBTU

MMMBTU

MBbls

MBbls

MBbls

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MBbls

MBbls

MMMBTU

MMMBTU

MBbls

MBbls

MBbls

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MMMBTU

MBbls

MBbls

MBbls

Derivative [Line Items]

Annual Hedged Volume (in energy unit)

43,729

22,002

21,727

[1]

3,775

2,992

[2]

783

19,545

[3]

9,010

[3]

2,420

[3]

1,444

[3]

1,168

[3]

506

[3]

1,750

[4]

2,664

177,029

97,401

79,628

[1]

15,863

11,903

[2]

3,960

79,388

[3]

39,718

[3]

9,490

[3]

5,256

[3]

4,891

[3]

0

[3]

7,254

[4]

10,570

189,895

118,041

71,854

[1]

15,025

11,599

[2]

3,426

87,162

[3]

43,292

[3]

9,344

[3]

4,891

[3]

5,074

[3]

0

[3]

7,251

[4]

10,570

198,110

121,841

76,269

[1]

14,735

11,464

[2]

3,271

59,954

[3]

46,294

[3]

7,768

[3]

4,575

[3]

4,219

[3]

0

[3]

7,446

[4]

10,599

187,008

120,122

66,886

[1]

5,139

4,755

[2]

384

59,138

[3]

38,880

[3]

7,437

[3]

3,604

[3]

4,819

[3]

0

[3]

6,486

[4]

36,500

36,500

0

[1]

0

0

[2]

0

16,425

[3]

10,804

[3]

2,044

[3]

986

[3]

1,314

[3]

0

[3]

0

[4]

Weighted Average Fixed Price (in usd per energy unit)

5.29

5.22

95.57

94.97

[2]

5.14

5.25

92.52

92.92

[2]

5.12

5.19

94.81

96.23

[2]

4.51

4.2

90.44

90.56

[2]

4.48

4.26

89.1

89.02

[2]

100

5

5

0

0

[2]

100

90

Weighted Average Short Put Price (in usd per energy unit)

5.37

[1]

97.86

5

[1]

91.3

5

[1]

90

5

[1]

90

4.88

[1]

90

0

[1]

0

Hedged Differential (in usd per energy unit)

-0.56

[3]

-0.2

[3]

0.1

[3]

-0.1

[3]

-0.2

[3]

-0.95

[3]

0.22

[4]

-0.33

[3]

-0.2

[3]

0.08

[3]

-0.1

[3]

-0.21

[3]

0

[3]

0.22

[4]

-0.33

[3]

-0.2

[3]

0.06

[3]

-0.1

[3]

-0.21

[3]

0

[3]

0.24

[4]

-0.32

[3]

0.2

[3]

0.05

[3]

-0.1

[3]

-0.2

[3]

0

[3]

0.25

[4]

-0.33

[3]

-0.19

[3]

0.05

[3]

-0.08

[3]

-0.2

[3]

0

[3]

0.25

[4]

-0.33

[3]

-0.19

[3]

0.05

[3]

-0.08

[3]

-0.2

[3]

0

[3]

0

[4]

Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)

5,384

5,384

5,384

Volumes of natural gas production on settled derivatives (in MMMbtu)

43,729

40,202

129,760

98,282

Average contract price per MMBtu on settled derivatives

5.29

5.31

5.29

5.49

Volumes of oil production on settled derivatives (in MBbls)

3,775

2,951

11,201

8,259

Average contract price per barrel on settled derivatives

95.57

97.44

95.57

97.8

[1]

Includes certain outstanding natural gas put options of approximately 2,664 MMMBtu for the period OctoberB 1, 2013, through DecemberB 31, 2013, 10,570 MMMBtu for each of the years ending DecemberB 31, 2014, and DecemberB 31, 2015, and 10,599 MMMBtu for the year ending DecemberB 31, 2016, used to indirectly hedge revenues associated with NGL production.

[2]

Includes certain outstanding fixed price oilB swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending DecemberB 31, 2017, and DecemberB 31, 2018, and $90.00 per Bbl for the year ending DecemberB 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

[3]

Settle on the respective pricing index to hedge basis differential associated with natural gas and oil production.

[4]

The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the btrade month rollb).

Derivatives_Balance_Sheet_Pres

Derivatives (Balance Sheet Presentation) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Asset, Fair Value	$1,073,942,000	$1,282,390,000
Derivative Liability, Fair Value	233,107,000	405,619,000
Maximum Loss Upon All Counterparties Failing To Perform	$1,100,000,000

Derivatives_Gains_Losses_On_De

Derivatives (Gains (Losses) On Derivatives) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gains (losses) on oil and natural gas derivatives	($63,931)	($411,405)	$154,432	$30,273

Fair_Value_Measurements_on_a_R2

Fair Value Measurements on a Recurring Basis (Details) (Commodity Contracts, USD $)	Sep. 30, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Fair value assets measured on recurring basis, derivative financial instruments, assets	$853,299		$880,911
Fair value assets measured on recurring basis, derivative financial instruments, liabilities	12,464		4,140
Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Fair value assets measured on recurring basis, derivative financial instruments, assets	1,073,942		1,282,390
Fair value assets measured on recurring basis, derivative financial instruments, liabilities	233,107		405,619
Counterparty netting under agreements governing derivatives
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement Captions [Line Items]
Fair value assets measured on recurring basis, derivative financial instruments, assets	-220,643	[1]	-401,479
Fair value assets measured on recurring basis, derivative financial instruments, liabilities	($220,643)	[1]	($401,479)
[1]	Represents counterparty netting under agreements governing such derivatives.

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013
Asset Retirement Obligation Disclosure [Abstract]
Future inflation factor used in the calculation of the asset retirement obligations	2.00%
Credit adjusted risk-free interest rate for the calculation of the asset retirement obligations	6.40%
Asset retirement obligations rollforward
Asset retirement obligations, beginning of the period	$151,974
Liabilities added from acquisitions	639
Liabilities added from drilling	2,803
Liabilities associated with assets sold	-1,092
Current year accretion expense	8,463
Settlements	-3,758
Revision of estimates	20,287
Asset retirement obligations, end of the period	$179,316

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	0 Months Ended			1 Months Ended	18 Months Ended
In Millions, unless otherwise specified	Apr. 30, 2013	Oct. 03, 2012	Apr. 19, 2012	Mar. 31, 2011	Sep. 30, 2013
Loss Contingency, Estimate [Abstract]
Amount of general unsecured claims from termination agreements				$51
Distribution received under termination agreement	5	3	25		33
Recovery of bankruptcy claim included in gains (losses) on oil and natural gas derivatives			18
Pending Litigation [Member]
Loss Contingency, Estimate [Abstract]
Loss Contingency, Range of Possible Loss, Minimum					1
Loss Contingency, Range of Possible Loss, Maximum					$4.50

Earnings_Per_Unit_Details

Earnings Per Unit (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Earnings Per Share [Abstract]
Net loss allocated to units	($30,060)	($430,005)	$93,212	($199,121)
Net loss allocated to participating securities	-1,266	-1,398	-3,796	-4,165
Net loss available to common unitholders, basic	($31,326)	($431,403)	$89,416	($203,286)
Weighted average units outstanding
Basic net loss per unit (in units)	233,552,000	197,675,000	233,393,000	196,152,000
Dilutive effect of unit equivalents (in units)	0	0	372,000	0
Diluted net loss per unit (in units)	233,552,000	197,675,000	233,765,000	196,152,000
Earnings per share reconciliation
Basic loss per unit (in usd per unit)	($0.13)	($2.18)	$0.38	($1.04)
Dilutive effect of unit equivalents (in usd per unit)	$0	$0	$0	$0
Diluted loss per unit (in usd per unit)	($0.13)	($2.18)	$0.38	($1.04)
Unit options and warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average anti-dilutive unit equivalents excluded from computation of earnings per unit (in units)	4,000,000	1,000,000	3,000,000	1,000,000

Supplemental_Disclosures_to_th2

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Balance Sheets) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Accrued compensation	$24,931,000	$35,431,000
Accrued interest	124,029,000	72,668,000
Other	7,178,000	7,146,000
Other accrued liabilities	156,138,000	115,245,000
Restricted cash	5,000,000	5,000,000
Net Outstanding Checks	$0	$35,000,000

Supplemental_Disclosures_to_th3

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Cash Flows) (Details) (USD $)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Cash payments for interest, net of amounts capitalized	$240,261,000	$178,194,000
Cash payments for income taxes	14,000	306,000
Noncash investing activities - liabilities assumed
Fair value of assets acquired	47,901,000	2,854,410,000
Cash paid	28,524,000	2,487,767,000
Receivables from sellers	3,654,000	772,000
Payables to sellers	-6,854,000	-422,000
Fair value of liabilities assumed	16,177,000	366,993,000
Joint-venture funding	112,000,000
Cash deposit	$53,000,000

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	3 Months Ended		9 Months Ended		0 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Oct. 17, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
					LinnCo [Member]	LinnCo [Member]	LinnCo [Member]	Director [Member]	Director [Member]
Related Party Transaction [Line Items]
Initial public offering, proceeds					$1,200,000,000
Units of LINN Energy acquired					34,787,500
Ownership percentage						15.00%	15.00%
General and administrative expenses	45,431,000	45,166,000	150,302,000	129,672,000		1,000,000	15,000,000
General and administrative expenses paid on behalf of LinnCo							9,000,000
Third party transaction costs related to the pending acquisition of Berry						0	13,000,000
Related party transaction, amounts of transaction						403,000	1,000,000	7,000,000	20,000,000
Offering costs related to pending acquisition of Berry						361,000	361,000
Distribution paid during period							$76,000,000