Pressburg (ROAN) 10-K 15 Mar 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Jan. 31, 2016	Jun. 30, 2015
Document and Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Entity Registrant Name	Linn Energy, LLC
Entity Central Index Key	1,326,428
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 2
Entity Common Stock, Shares Outstanding		355,241,631
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 2,168	$ 1,809
Accounts receivable – trade, net	216,556	471,684
Derivative instruments	1,220,230	1,077,142
Other current assets	119,921	155,955
Total current assets	1,558,875	1,706,590
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	18,121,155	18,068,900
Less accumulated depletion and amortization	(11,097,492)	(4,867,682)
Oil and natural gas properties, successful efforts method, net	7,023,663	13,201,218
Other property and equipment	708,711	669,149
Less accumulated depreciation	(195,661)	(144,282)
Other property and equipment, net	513,050	524,867
Derivative instruments	566,401	848,097
Restricted cash	257,363	6,225
Other noncurrent assets	57,594	136,512
Noncurrent assets, excluding property, total	881,358	990,834
Total noncurrent assets	8,418,071	14,716,919
Total assets	9,976,946	16,423,509
Current liabilities:
Accounts payable and accrued expenses	455,374	814,809
Derivative instruments	2,241	0
Current portion of long-term debt	3,716,508	0
Other accrued liabilities	119,593	167,736
Total current liabilities	4,293,716	982,545
Noncurrent liabilities:
Derivative instruments	857	684
Long-term debt, net	5,328,235	10,295,809
Other noncurrent liabilities	623,039	600,866
Total noncurrent liabilities	$ 5,952,131	$ 10,897,359
Commitments and contingencies (Note 11)
Unitholders’ capital (deficit):
355,017,428 units and 331,974,913 units issued and outstanding at December 31, 2015, and December 31, 2014, respectively	$ 5,343,116	$ 5,395,811
Accumulated deficit	(5,612,017)	(852,206)
Total unitholders' capital (deficit)	(268,901)	4,543,605
Total liabilities and unitholders’ capital (deficit)	$ 9,976,946	$ 16,423,509

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common Unit, Issued	355,017,428	331,974,913
Common Unit, Outstanding	355,017,428	331,974,913

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues and other:
Oil, natural gas and natural gas liquids sales	$ 1,726,271	$ 3,610,539	$ 2,073,240
Gains on oil and natural gas derivatives	1,056,189	1,206,179	177,857
Marketing revenues	74,129	135,260	54,171
Other revenues	26,745	31,325	26,387
Total revenues	2,883,334	4,983,303	2,331,655
Expenses:
Lease operating expenses	617,764	805,164	372,523
Transportation expenses	219,721	207,331	128,440
Marketing expenses	57,144	117,465	37,892
General and administrative expenses	296,887	293,073	236,271
Exploration costs	9,473	125,037	5,251
Depreciation, depletion and amortization	805,757	1,073,902	829,311
Impairment of long-lived assets	5,813,954	2,303,749	828,317
Taxes, other than income taxes	181,895	267,403	138,631
(Gains) losses on sale of assets and other, net	(197,409)	(366,500)	13,637
Total expenses	7,805,186	4,826,624	2,590,273
Other income and (expenses):
Interest expense, net of amounts capitalized	(546,453)	(587,838)	(421,137)
Gain (loss) on extinguishment of debt	719,259	0	(5,304)
Other, net	(17,226)	(16,213)	(8,477)
Total other income and (expenses)	155,580	(604,051)	(434,918)
Loss before income taxes	(4,766,272)	(447,372)	(693,536)
Income tax expense (benefit)	(6,461)	4,437	(2,199)
Net loss	$ (4,759,811)	$ (451,809)	$ (691,337)
Net loss per unit:
Basic (in usd per unit)	$ (13.87)	$ (1.40)	$ (2.94)
Diluted (in usd per unit)	$ (13.87)	$ (1.40)	$ (2.94)
Weighted average units outstanding:
Basic (in units)	343,323	328,918	237,544
Diluted (in units)	343,323	328,918	237,544
Distributions declared per unit (in usd per unit)	$ 0.938	$ 2.90	$ 2.90

CONSOLIDATED STATEMENT OF UNITH

CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Common Units, Outstanding (in units)		331,974,913			331,974,913
Balance Beginning		$ 4,543,605		$ 5,891,427	$ 4,543,605	$ 5,891,427	$ 4,427,180
Sale of units, net of offering costs of $8,762					224,665
Issuance of units					0	13,354	2,783,907
Cancellation of units					0
Purchase of units					(672)
Distributions to unitholders					(323,878)	(962,048)	(682,241)
Unit-based compensation expenses					56,136	53,284	42,703
Reclassification of distributions paid on forfeited restricted units					865	602	176
Excess tax benefit from unit-based compensation and other						347	160
Excess tax benefit from unit-based compensation and other					(9,811)
Deferred tax on capital contribution						(1,552)	(10,879)
Net loss	$ (2,472,207)	$ (339,160)	$ (154,502)	$ (85,337)	(4,759,811)	(451,809)	(691,337)
Balance Ending	$ (268,901)		$ 4,543,605		$ (268,901)	$ 4,543,605	$ 5,891,427
Common Units, Outstanding (in units)	355,017,428		331,974,913		355,017,428	331,974,913
Units
Common Units, Outstanding (in units)		331,975,000		329,661,000	331,975,000	329,661,000	234,513,000
Sale of units, net of offering costs (in units)					19,622,000
Issuance of units (in units)					3,611,000	2,314,000	95,148,000
Cancellation of units (in units)					(191,000)
Common Units, Outstanding (in units)	355,017,000		331,975,000		355,017,000	331,975,000	329,661,000
Unitholders’ Capital
Balance Beginning		$ 5,395,811		$ 6,291,824	$ 5,395,811	$ 6,291,824	$ 4,136,240
Sale of units, net of offering costs of $8,762					224,665
Issuance of units					0	13,354	2,783,907
Cancellation of units					(672)
Purchase of units					0
Distributions to unitholders					(323,878)	(962,048)	(682,241)
Unit-based compensation expenses					56,136	53,284	42,703
Reclassification of distributions paid on forfeited restricted units					865	602	176
Excess tax benefit from unit-based compensation and other						347	160
Excess tax benefit from unit-based compensation and other					(9,811)
Deferred tax on capital contribution						(1,552)	(10,879)
Net loss					0	0	0
Balance Ending	$ 5,343,116		$ 5,395,811		5,343,116	5,395,811	6,291,824
Accumulated Income (Deficit)
Balance Beginning		(852,206)		(400,397)	(852,206)	(400,397)	290,940
Sale of units, net of offering costs of $8,762					0
Issuance of units					0	0	0
Cancellation of units					0
Purchase of units					0
Distributions to unitholders					0	0	0
Unit-based compensation expenses					0	0	0
Reclassification of distributions paid on forfeited restricted units					0	0	0
Excess tax benefit from unit-based compensation and other						0	0
Excess tax benefit from unit-based compensation and other					0
Deferred tax on capital contribution						0	0
Net loss					(4,759,811)	(451,809)	(691,337)
Balance Ending	(5,612,017)		(852,206)		(5,612,017)	(852,206)	(400,397)
Treasury Units (at Cost)
Balance Beginning		$ 0		$ 0	0	0	0
Sale of units, net of offering costs of $8,762					0
Issuance of units					0	0	0
Cancellation of units					672
Purchase of units					(672)
Distributions to unitholders					0	0	0
Unit-based compensation expenses					0	0	0
Reclassification of distributions paid on forfeited restricted units					0	0	0
Excess tax benefit from unit-based compensation and other						0	0
Excess tax benefit from unit-based compensation and other					0
Deferred tax on capital contribution						0	0
Net loss					0	0	0
Balance Ending	$ 0		$ 0		$ 0	$ 0	$ 0

CONSOLIDATED STATEMENT OF UNIT6

CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (Parenthetical) $ in Thousands	12 Months Ended
	Dec. 31, 2013USD ($)
Statement of Stockholders' Equity [Abstract]
Underwriting discounts and expenses	$ 8,762

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flow from operating activities:
Net loss	$ (4,759,811)	$ (451,809)	$ (691,337)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	805,757	1,073,902	829,311
Impairment of long-lived assets	5,813,954	2,303,749	828,317
Unit-based compensation expenses	56,136	53,284	42,703
(Gain) loss on extinguishment of debt	(719,259)	0	5,304
Amortization and write-off of deferred financing fees	34,743	50,926	21,507
(Gains) losses on sale of assets and other, net	(189,161)	(261,571)	37,232
Deferred income taxes	4,538	3,943	(2,541)
Derivatives activities:
Total gains	(1,063,082)	(1,206,179)	(177,857)
Cash settlements	1,199,410	95,514	248,862
Cash settlements on canceled derivatives	4,679	12,281	0
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net	267,241	5,064	89,188
(Increase) decrease in other assets	9,582	(17,824)	16,179
Increase (decrease) in accounts payable and accrued expenses	(156,394)	99,029	(76,993)
Decrease in other liabilities	(58,876)	(48,419)	(3,663)
Net cash provided by operating activities	1,249,457	1,711,890	1,166,212
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	0	(2,479,252)	(279,213)
Development of oil and natural gas properties	(608,889)	(1,569,877)	(1,078,025)
Purchases of other property and equipment	(66,708)	(74,540)	(92,352)
Proceeds from sale of properties and equipment and other	368,295	2,203,565	196,273
Net cash used in investing activities	(307,302)	(1,920,104)	(1,253,317)
Cash flow from financing activities:
Proceeds from sale of units	233,427	0	0
Proceeds from borrowings	1,445,000	5,940,024	2,230,000
Repayments of debt	(2,183,879)	(4,811,124)	(1,404,898)
Distributions to unitholders	(323,878)	(962,048)	(682,241)
Financing fees and offering costs	(28,055)	(69,694)	(16,033)
Excess tax benefit from unit-based compensation		766	160
Excess tax benefit from unit-based compensation	(9,467)
Other	(74,944)	59,928	11,045
Net cash provided by (used in) financing activities	(941,796)	157,852	138,033
Net increase (decrease) in cash and cash equivalents	359	(50,362)	50,928
Cash and cash equivalents:
Beginning	1,809	52,171	1,243
Ending	$ 2,168	$ 1,809	$ 52,171

Basis of Presentation and Signi

Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Significant Accounting Policies	Basis of Presentation and Significant Accounting Policies Nature of Business Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company that began operations in March 2003 and was formed as a Delaware limited liability company in April 2005. The Company completed its initial public offering in January 2006 and its units representing limited liability company interests (“units”) are listed on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “LINE.” LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. The Company’s properties are located in eight operating regions in the United States (“U.S.”): Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin), North Dakota (Williston Basin) and Colorado (Piceance Basin); California, which includes properties located in the San Joaquin Valley and Los Angeles basins; TexLa, which includes properties located in east Texas and north Louisiana; Mid-Continent, which includes properties located in the Anadarko and Arkoma basins in Oklahoma, as well as waterfloods in the Central Oklahoma Platform; Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; Permian Basin, which includes properties located in west Texas and southeast New Mexico; and South Texas. The operations of the Company are governed by the provisions of a limited liability company agreement executed by and among its members. The agreement includes specific provisions with respect to the maintenance of the capital accounts of each of the Company’s unitholders. Pursuant to applicable provisions of the Delaware Limited Liability Company Act (“Delaware Act”) and the Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC, as amended (“LLC Agreement”), unitholders have no liability for the debts, obligations and liabilities of the Company, except as expressly required in the LLC Agreement or the Delaware Act. The Company will remain in existence unless and until dissolved in accordance with the terms of the LLC Agreement. Going Concern Uncertainty The Company’s liquidity outlook has changed since the third quarter of 2015 due to continued low commodity prices, which are expected to result in significantly lower levels of cash flow from operating activities in the future as the Company’s current commodity derivative contracts expire, and have limited the Company’s ability to access the capital markets. In addition, each of the Company’s Credit Facilities is subject to scheduled redeterminations of its borrowing base, semi-annually in April and October, based primarily on reserve reports using lender commodity price expectations at such time. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs, along with the maturity schedule of the Company’s hedges, are expected to adversely impact the upcoming April redeterminations and will likely have a significant negative impact on the Company’s liquidity. As a result of these and other factors, the following issues have adversely impacted the Company’s ability to continue as a going concern: • the Company’s ability to comply with financial covenants and ratios in its Credit Facilities and indentures has been affected by continued low commodity prices. Absent a waiver or amendment, failure to meet these covenants and ratios would result in a default and, to the extent the applicable lenders so elect, an acceleration of the Company’s existing indebtedness, causing such debt of approximately $3.6 billion to be immediately due and payable. Based on the Company’s current estimates and expectations for commodity prices in 2016, the Company does not expect to remain in compliance with all of the restrictive covenants contained in its Credit Facilities throughout 2016 unless those requirements are waived or amended. The Company does not currently have adequate liquidity to repay all of its outstanding debt in full if such debt were accelerated; • because the Credit Facilities are effectively fully drawn, any reduction of the borrowing bases under the Company’s Credit Facilities would require mandatory prepayments to the extent existing indebtedness exceeds the new borrowing bases. The Company may not have sufficient cash on hand to be able to make any such mandatory prepayments; and • the Company’s ability to make interest payments as they become due and repay indebtedness upon maturities (whether under existing terms or as a result of acceleration) is impacted by the Company’s liquidity. As of February 29, 2016, there was less than $1 million of available borrowing capacity under the Credit Facilities. The Company’s Credit Facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception. Consequently, as of the filing date, March 15, 2016, the Company is in default under the LINN Credit Facility. If the Company is unable to obtain a waiver or other suitable relief from the lenders under the LINN Credit Facility prior to the expiration of the 30 day grace period, an Event of Default (as defined in the applicable agreements) will result and the lenders holding a majority of the commitments under the LINN Credit Facility could accelerate the outstanding indebtedness, which would make it immediately due and payable. If the Company is unable to obtain a waiver from or otherwise reach an agreement with the lenders under the LINN Credit Facility and the indebtedness under the LINN Credit Facility is accelerated, then an Event of Default under LINN Energy’s senior notes and second lien notes would occur, which, if it continues beyond any applicable cure periods, would, to the extent the applicable lenders so elect, result in the acceleration of those obligations. Furthermore, an Event of Default under the LINN Credit Facility will also result in an Event of Default under the Berry Credit Facility, which in the absence of a waiver or other suitable relief and upon the election of the agent or lenders holding a majority of commitments under the Berry Credit Facility would result in the acceleration of indebtedness under the Berry Credit Facility. Such Event of Default would trigger an Event of Default under the Berry senior notes. If such Event of Default continues beyond any applicable cure periods, such Event of Default would result in an acceleration of the Berry senior notes. Additionally, the indenture governing the second lien notes (“Second Lien Indenture”) required the Company to deliver mortgages by February 18, 2016, subject to a 45 day grace period. The Company elected to exercise its right to the grace period and not deliver the mortgages, and as a result, the Company is currently in default under the Second Lien Indenture. If the Company does not deliver the mortgages within the 45 day grace period or is otherwise unable to obtain a waiver or other suitable relief from the holders under the Second Lien Indenture prior to the expiration of the 45 day grace period, an Event of Default (as defined in the Second Lien Indenture) will result and if the trustee or noteholders holding at least 25% in the aggregate outstanding principal amount of the second lien notes so elect would accelerate the second lien notes causing them to be immediately due and payable. Furthermore, the Company has decided to defer making interest payments totaling approximately $60 million due March 15, 2016, including approximately $30 million on LINN Energy’s 7.75% senior notes due February 2021, approximately $12 million on LINN Energy’s 6.50% senior notes due September 2021 and approximately $18 million on Berry’s senior notes due September 2022, which will result in the Company being in default under these senior notes. The indentures governing each of the applicable series of notes permit the Company a 30 day grace period to make the interest payments. If the Company fails to make the interest payments within the grace period, or is otherwise unable to obtain a waiver or suitable relief from the holders of these senior notes, an Event of Default will result and if the trustee or noteholders holding at least 25% in the aggregate outstanding principal amount of each series of notes so elect would accelerate the notes causing them to be immediately due and payable. An Event of Default under the Second Lien Indenture or any of the indentures governing the senior notes triggers a cross-default under the LINN Credit Facility and Berry Credit Facility and, as discussed above, if the applicable lenders so elect would result in acceleration under the LINN Credit Facility and Berry Credit Facility. In addition, as discussed above, an acceleration of the obligations under the Second Lien Indenture or LINN Credit Facility would trigger a cross-default to LINN Energy’s senior notes and if the applicable lenders so elect would result in a cross-acceleration under LINN Energy’s senior notes, and an acceleration of the Berry Credit Facility if the applicable lenders so elect would result in cross-acceleration under the Berry senior notes. See Note 6 for additional details about the Company’s debt. If lenders, and subsequently noteholders, accelerate the Company’s outstanding indebtedness (approximately $9.0 billion as of December 31, 2015 ), it will become immediately due and payable and the Company will not have sufficient liquidity to repay those amounts. If the Company is unable to reach an agreement with its creditors prior to any of the above described accelerations, the Company could be required to immediately file for protection under Chapter 11 of the U.S. Bankruptcy Code. The significant risks and uncertainties described above raise substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. The Company is currently in discussions with various stakeholders and is pursuing or considering a number of actions including: (i) obtaining additional sources of capital from asset sales, private issuances of equity or equity-linked securities, debt for equity swaps, or any combination thereof; (ii) pursuing in- and out-of-court restructuring transactions; (iii) obtaining waivers or amendments from its lenders; and (iv) continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations. There can be no assurance that sufficient liquidity can be obtained from one or more of these actions or that these actions can be consummated within the period needed. Principles of Consolidation and Reporting The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss), unitholders’ capital (deficit) or cash flows. Use of Estimates The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods. Recently Issued Accounting Standards In November 2015, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to simplify the presentation of deferred taxes by requiring that all deferred taxes be presented as noncurrent. This ASU will be applied either prospectively or retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2016, and interim periods within those years (early adoption permitted). Adoption of this ASU is expected to result in a decrease in the Company’s current assets or current liabilities on its consolidated balance sheets, depending on its deferred taxes classification at such date, with no impact to the consolidated statements of operations. In April 2015, the FASB issued an ASU that is intended to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2015, and interim periods within those years (early adoption permitted). Adoption of this ASU is expected to result in a decrease to the Company’s assets and liabilities in its consolidated balance sheets, with no impact to the consolidated statements of operations. In August 2014, the FASB issued an ASU that provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter (early adoption permitted). The Company does not expect the adoption of this ASU to have a material impact on its financial statements or related disclosures. In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU will be applied either retrospectively or as a cumulative-effect adjustment as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those years (early adoption permitted for fiscal years beginning after December 15, 2016, including interim periods within that year). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures. Cash Equivalents For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows. Accounts Receivable – Trade, Net Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million at both December 31, 2015 , and December 31, 2014 . Inventories Materials, supplies and commodity inventories are valued at the lower of average cost or market. Inventories also include California carbon allowance instruments. Oil and Natural Gas Properties Proved Properties The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $5 million , $9 million and $2 million for the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , respectively. The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. 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 underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Based on the analysis described above, the Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties: Year Ended December 31, 2015 2014 2013 (in thousands) Rockies region $ 1,758,939 $ 585,705 $ — Hugoton Basin region 1,667,768 — — California region 537,511 22 — TexLa region 430,859 4,836 — Mid-Continent region 405,370 244,413 828,317 Permian Basin region 71,990 1,337,444 — South Texas region 42,433 131,329 — $ 4,914,870 $ 2,303,749 $ 828,317 The impairment charges in 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The impairment charges in 2014 include approximately $1.7 billion due to a steep decline in commodity prices during the fourth quarter of 2014 and approximately $603 million due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for proved oil and natural gas properties. The impairment charges in 2013 include approximately $791 million associated with properties in the Granite Wash formation related to asset performance resulting in reserve revisions and a decline in commodity prices as well as approximately $37 million associated with the write-down of the carrying value of the Panther Operated Cleveland Properties sold in May 2013 (see Note 2). The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. Subsequent to December 31, 2015, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results of operations. Unproved Properties Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past. The Company recorded the following noncash impairment charges (before and after tax) associated with unproved oil and natural gas properties: Year Ended December 31, 2015 (in thousands) TexLa region $ 416,846 Permian Basin region 226,922 Rockies region 184,137 California region 71,179 $ 899,084 The Company recorded no impairment charges for unproved properties for the years ended December 31, 2014, or December 31, 2013. The impairment charges in 2015 were due to a decline in commodity prices and changes in expected capital development. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statement of operations. Exploration Costs Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $2 million , $125 million and $5 million for the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , respectively, which are included in “exploration costs” on the consolidated statements of operations. Other Property and Equipment Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from two to 39 years for the individual asset or group of assets. Restricted Cash At December 31, 2015 , “restricted cash” on the consolidated balance sheet includes $250 million that LINN Energy borrowed under the LINN Credit Facility and contributed to Berry Petroleum Company, LLC (“Berry”) in May 2015 to post with Berry’s lenders in connection with the reduction in the Berry Credit Facility’s borrowing base. See Note 6 for additional details. Restricted cash also includes approximately $7 million and $6 million at December 31, 2015 , and December 31, 2014 , respectively, of cash deposited by the Company into a separate account designated for asset retirement obligations in accordance with contractual agreements. Derivative Instruments The Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials. By removing a portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices. The Company maintains a substantial portion of its hedges in the form of swap contracts. From time to time, the Company has chosen to purchase put option contracts to hedge volumes in excess of those already hedged with swap contracts. In 2013, the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. The Company does not enter into derivative contracts for trading purposes. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price. Derivative instruments are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads are applied to the Company’s commodity derivatives. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments. The Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. At December 31, 2015 , the Company had no outstanding derivative contracts in the form of interest rate swaps. Revenue Recognition Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. Imbalance receivables and payables are valued at the lower of the price in effect at the time of production, the current market value or, if a contract is in hand, the contract price. At December 31, 2015 , and December 31, 2014 , the Company had natural gas production imbalance receivables of approximately $13 million and $17 million , respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets. At December 31, 2015 , and December 31, 2014 , the Company had natural gas production imbalance payables of approximately $11 million and $13 million , respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets. The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses. The Company generates electricity with excess natural gas, which it uses to serve certain of its operating facilities in California. Any excess electricity is sold to the California wholesale power market. The revenue from this activity is included in “other revenues” on the consolidated statements of operations. Unit-Based Compensation The Company recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based awards granted to employees a

Divestitures, Exchanges of Prop

Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding	Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding Divestiture – 2015 On August 31, 2015, the Company, through certain of its wholly owned subsidiaries, completed the sale of its remaining position in Howard County in the Permian Basin (“Howard County Assets Sale”). Cash proceeds received from the sale of these properties were approximately $276 million , net of costs to sell of approximately $1 million , and the Company recognized a net gain of approximately $177 million . The gain is included in “gains (losses) on sale of assets and other, net” on the consolidated statement of operations. The Company used the net proceeds from the sale to repay a portion of the outstanding indebtedness under the LINN Credit Facility. Divestitures – 2014 On December 15, 2014, the Company completed the sale of its entire position in the Granite Wash and Cleveland plays located in the Texas Panhandle and western Oklahoma to privately held institutional affiliates of EnerVest, Ltd. and its joint venture partner FourPoint Energy, LLC. Cash proceeds received from the sale of these properties were approximately $1.8 billion , net of costs to sell of approximately $10 million , and the Company recognized a net gain of approximately $294 million . On November 14, 2014, the Company completed the sale of certain of its Wolfberry properties in Ector and Midland counties in the Permian Basin to Fleur de Lis Energy, LLC. Cash proceeds received from the sale of these properties were approximately $352 million , net of costs to sell of approximately $2 million , and the Company recognized a net loss of approximately $28 million . On October 30, 2014, the Company completed the sale of its interests in certain non-producing oil and natural gas properties located in the Mid-Continent region. Cash proceeds received from the sale of these properties were approximately $44 million , and the Company recognized a net gain of approximately $36 million . The gains and loss on divestitures in 2014 are included in “(gains) losses on the sale of assets and other, net” on the consolidated statement of operations. The Company used the net cash proceeds received from these sales to repay the short-period term loan in full as well as repay a portion of the borrowings outstanding under the LINN Credit Facility. Exchanges of Properties – 2014 On November 21, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation (“ExxonMobil”) in exchange for properties in California’s South Belridge Field. The noncash exchange was accounted for at fair value and the Company recognized a net gain of approximately $20 million , including costs to sell of approximately $3 million . On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc. (“Exxon XTO”), in exchange for properties in the Hugoton Basin. The noncash exchange was accounted for at fair value and the Company recognized a net gain of approximately $65 million , including costs to sell of approximately $3 million . The gains on the exchanges are equal to the difference between the carrying value and the fair value of the assets exchanged less costs to sell, and are included in “(gains) losses on sale of assets and other, net” on the consolidated statement of operations in 2014. The fair value measurements were based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. Acquisitions – 2014 On September 11, 2014, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin from Pioneer Natural Resources Company for total consideration of approximately $328 million , which was initially financed with borrowings under the LINN Credit Facility. On August 29, 2014, the Company completed the acquisition of certain oil and natural gas properties located in five operating regions in the U.S. from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) for total consideration of approximately $2.1 billion , which was initially financed with proceeds from a bridge loan and borrowings under a short-period term loan. During the third quarter of 2014, the Company used the net proceeds from the issuance of its 6.50% senior notes due May 2019 and 6.50% senior notes due September 2021 to repay the bridge loan in full. During the fourth quarter of 2014, the Company used the net proceeds from the sales of its Granite Wash properties as well as certain of its Wolfberry properties to repay the short-period term loan in full. These acquisitions were accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition dates, while transaction and integration costs associated with the acquisitions were expensed as incurred. The results of operations of all acquisitions have been included in the consolidated financial statements since the acquisition dates. The revenues and expenses related to the Devon Assets Acquisition are included on the Company’s consolidated statements of operations as of August 29, 2014. The following unaudited pro forma financial information presents a summary of the Company’s condensed combined results of operations for the year ended December 31, 2014 , assuming the Devon Assets Acquisition had been completed as of January 1, 2014, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information has been prepared for informational purposes only and does not purport to represent what the actual results of operations would have been had the transaction been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The pro forma financial information does not give effect to the costs of any integration activities or benefits that may result from the realization of future cost savings from operating efficiencies, or any other synergies that may result from the transaction. Year Ended December 31, 2014 (in thousands, except per unit amounts) Total revenues and other $ 5,335,442 Total operating expenses $ (5,039,279 ) Net loss $ (403,415 ) Net loss per unit: Basic $ (1.25 ) Diluted $ (1.25 ) The pro forma condensed combined results of operations includes adjustments to: • Reflect the results of the Devon Assets Acquisition. • Reflect incremental depreciation, depletion and amortization expense, using the unit-of-production method related to oil and natural gas properties acquired and an estimated useful life of 10 years for other property and equipment. • Reflect incremental accretion expense related to asset retirement obligations on oil and natural gas properties acquired. • Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price. • Reflect incremental amortization of deferred financing fees associated with debt incurred to fund the purchase price. • Exclude transaction costs related to the Devon Assets Acquisition included in the historical statements of operations as they reflect nonrecurring charges not expected to have a continuing impact on the combined results. Joint-Venture Funding – 2014 For the year ended December 31, 2014 , the Company paid approximately $25 million , including interest, to fund the commitment related to the joint-venture agreement it entered into with an affiliate of Anadarko Petroleum Company in April 2012. For the years ended December 31, 2013 , and December 31, 2012 , the Company paid approximately $173 million and $202 million , respectively, to fund the commitment. As of February 2014, the Company had fully funded the total commitment of $400 million . Berry Acquisition – 2013 On December 16, 2013, the Company completed the transactions contemplated by the merger agreement between the Company, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and the Company, under which LinnCo contributed Berry to the Company in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. The transaction was valued at approximately $4.6 billion , including the assumption of approximately $2.3 billion of Berry’s debt and net of cash acquired of approximately $451 million .

Unitholders' Capital (Deficit)

Unitholders' Capital (Deficit)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Unitholders' Capital (Deficit)	Unitholders’ Capital (Deficit) At-the-Market Offering Program The Company’s Board of Directors has authorized the sale of up to $500 million of units under an at-the-market offering program. Sales of units, if any, will be made under an equity distribution agreement by means of ordinary brokers’ transactions, through the facilities of the NASDAQ, any other national securities exchange or facility thereof, a trading facility of a national securities association or an alternate trading system, to or through a market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, at market prices, in block transactions, or as otherwise agreed with a sales agent. The Company expects to use the net proceeds from any sale of units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt. During the year ended December 31, 2015 , the Company, under its equity distribution agreement, sold 3,621,983 units representing limited liability company interests at an average price of $12.37 per unit for net proceeds of approximately $44 million (net of approximately $448,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional services expenses of approximately $459,000 . The Company used the net proceeds for general corporate purposes, including the open market repurchases of a portion of its senior notes (see Note 6). At December 31, 2015 , units totaling approximately $455 million in aggregate offering price remained available to be sold under the agreement. Public Offering of Units In May 2015, the Company sold 16,000,000 units representing limited liability company interests in an underwritten public offering at $11.79 per unit ( $11.32 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering costs of approximately $8 million ). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under the LINN Credit Facility. Forfeiture of Units in Exchange for Cash In August 2015, in accordance with terms of the separation agreement between the Company and Kolja Rockov, former Chief Financial Officer, dated August 31, 2015, Mr. Rockov agreed to forfeit 191,446 units issued to him under the Company’s equity compensation plan (see Note 5) in exchange for a cash payment of approximately $672,000 . These units are available for issuance under the Company’s equity compensation plan. 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, if any, over the next four quarters. Distributions paid by the Company are presented on the consolidated statements of unitholders’ capital (deficit) and the consolidated statements of cash flows. Monthly distributions were paid by the Company through September 2015. In October 2015, the Company’s Board of Directors determined to suspend payment of the Company’s distribution. The Company’s Board of Directors will continue to evaluate the Company’s ability to reinstate the distribution. Unit Repurchase Plan The Company’s Board of Directors has authorized the repurchase of up to $250 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. The timing and amounts of any such repurchases are at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. The Company did not repurchase any units during the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , and as of December 31, 2015 , the entire amount remained available for unit repurchase under the program. Berry Acquisition On December 16, 2013, in connection with the Berry acquisition (see Note 2), Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units with a value of approximately $2.8 billion .

Significant Customers

Significant Customers	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Significant Customers	Significant Customers The Company has a concentration of customers who are engaged in oil and natural gas purchasing, transportation and/or refining within the U.S. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company’s customers consist primarily of major oil and natural gas purchasers and the Company generally does not require collateral since it has not experienced significant credit losses on such sales. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectibility (see Note 1). For the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , the Company’s largest customer represented approximately 12% , 14% and 12% , respectively, of the Company’s sales. At December 31, 2015 , no individual customer exceeded 10% of the Company’s receivables. At December 31, 2014 , trade accounts receivable from one customer represented approximately 11% of the Company’s receivables.

Unit-Based Compensation and Oth

Unit-Based Compensation and Other Benefit Plans	12 Months Ended
	Dec. 31, 2015
Unit Based Compensation and Other Benefit Plans [Abstract]
Unit-Based Compensation and Other Benefit Plans	Unit-Based Compensation and Other Benefit Plans Incentive Plan Summary The Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (the “Plan”), originally became effective in December 2005. The Plan, which is administered by the Compensation Committee of the Board of Directors (“Compensation Committee”), permits granting unrestricted units, restricted units, phantom units, unit options, performance units and unit appreciation rights to employees, consultants and nonemployee directors under the terms of the Plan. The restricted units, phantom units and unit options generally vest ratably over three years . The contractual life of unit options is 10 years . Performance units were granted for the first time in January 2014 to certain executive officers. The initial 2014 awards vest 50% in two years and 50% in three years from the award date. Performance units granted in January 2015 vest three years from the award date. The Plan limits the number of units that may be delivered pursuant to awards to 21 million units. The Board of Directors and the Compensation Committee have the right to alter or amend the Plan or any part of the Plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval as required by the exchange upon which the units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the benefits to the participant without the consent of the participant. Units to be delivered as restricted units, upon the vesting of phantom units or performance units, or upon exercise of a unit option or unit appreciation right may be new units issued by the Company, units acquired by the Company in the open market, units acquired by the Company from any other person, units already owned by the Company, or any combination of the foregoing. If the Company issues new units upon the grant of restricted units, vesting of phantom units or performance units, or exercise of a unit option or unit appreciation right, the total number of units outstanding will increase. To date, the Company has issued awards of unrestricted units, restricted units, phantom units, performance units and unit options. The Plan provides for all of the following types of awards: Unit Grants – A unit grant is the grant of an unrestricted unit that vests immediately upon issuance. Restricted Units – A restricted unit is a unit that vests over a period of time and that during such time is subject to forfeiture. The Company intends the restricted units under the Plan to serve as a means of incentive compensation for performance. Therefore, Plan participants do not pay any consideration for the units they receive. If a grantee’s employment, consulting relationship or membership on the Company’s Board of Directors terminates for any reason, other than death, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. The restricted units will vest upon a change of control, unless provided otherwise by the Compensation Committee. Phantom Units – A phantom unit entitles the grantee to receive a unit upon the vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the value of a unit. The Compensation Committee may grant tandem distribution equivalent rights with respect to phantom units that entitle the holder to receive cash equal to any cash distributions made on units while the phantom units are outstanding. The Compensation Committee determines the period over which phantom units will vest, subject to applicable minimum vesting periods except with respect to phantom unit grants to nonemployee directors. The Company intends the phantom units under the Plan to serve as a means of incentive compensation for performance. Therefore, Plan participants do not pay any consideration for the units they receive. If a grantee’s employment, consulting relationship or membership on the Company’s Board of Directors terminates for any reason, other than death or retirement, the grantee’s phantom units will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. The phantom units will vest upon a change of control, unless provided otherwise by the Compensation Committee. Unit Options – A unit option is a right to purchase a unit at a specified price. Unit options have an exercise price that is equal to the fair market value of the units on the date of grant. If a grantee’s employment, consulting relationship or membership on the Company’s Board of Directors terminates for any reason, the grantee’s unvested unit options will be automatically forfeited unless, and to the extent, the Compensation Committee or the terms of the award agreement provide otherwise. The unit options will become exercisable upon a change of control, unless provided otherwise by the Compensation Committee. Performance Units – A performance unit is a unit that vests over a period of time in an amount based on certain comparative performance criteria. The Company intends the performance units under the Plan to serve as a means of incentive compensation for performance. Therefore, Plan participants do not pay any consideration for the units they receive. Upon termination of employment with the Company other than for “Cause” or with “Good Reason” (as those terms are defined in the employment agreement), the performance units vest on the original scheduled vesting date at the performance level multiplier applicable on that date. If employment terminates by reason of death or “Disability” (as defined in the employment agreement), the performance units immediately vest at the target level. Additionally, performance units vest upon a change of control and the number of units awarded is determined as if the vesting period ended on the change of control date instead of the original scheduled date. Unit Appreciation Rights – A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. The excess may be paid in the Company’s units, cash or a combination thereof, as determined by the Compensation Committee in its discretion. To date, the Company has not granted any unit appreciation rights. Securities Authorized for Issuance Under the Plan As of December 31, 2015 , approximately 5.8 million units were issuable under the Plan pursuant to outstanding award or other agreements, including unvested restricted units, phantom units and outstanding unit options, and 5.4 million additional units were reserved for future issuance under the Plan. Accounting for Unit-Based Compensation The Company recognizes as expense, beginning at the grant date, the fair value of equity-based compensation issued to employees and nonemployee directors. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period using the straight-line method in the Company’s consolidated statements of operations. A summary of unit-based compensation expenses included in the consolidated statements of operations is presented below: Year Ended December 31, 2015 2014 2013 (in thousands) General and administrative expenses $ 47,312 $ 45,195 $ 37,375 Lease operating expenses 8,824 8,089 5,328 Total unit-based compensation expenses $ 56,136 $ 53,284 $ 42,703 Income tax benefit $ 20,742 $ 19,688 $ 15,779 Restricted Units/Phantom Units/Unrestricted Units The fair value of restricted units, phantom units and unrestricted unit grants issued is determined based on the fair market value of the Company units on the date of grant. As of December 31, 2015 , a summary of the status of the nonvested units is presented below: Number of Nonvested Units Weighted Average Grant-Date Per Unit Nonvested units at December 31, 2014 2,838,973 $ 32.70 Granted 4,576,631 $ 10.21 Vested (1,870,384 ) $ 26.41 Forfeited (618,648 ) $ 16.65 Nonvested units at December 31, 2015 4,926,572 $ 16.22 The weighted average grant-date fair value of restricted units, phantom units and unrestricted units granted was $33.10 per unit and $30.71 per unit during the years ended December 31, 2014 , and December 31, 2013 , respectively. The total fair value of units that vested was approximately $49 million , $42 million and $31 million for the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , respectively. As of December 31, 2015 , there was approximately $31 million of unrecognized compensation cost related to nonvested restricted units and phantom units. The cost is expected to be recognized over a weighted average period of approximately 1.5 years . Cash-Based Performance Unit Awards In January 2015, the Company granted 567,320 performance units (the maximum number of units available to be earned) to certain executive officers. The 2015 performance unit awards vest three years from the award date. The vesting of these units is determined based on the Company’s performance compared to the performance of a predetermined group of peer companies over a specified performance period, and the value of vested units is to be paid in cash. To date, no performance units have vested and no amounts have been paid to settle any such awards. Performance unit awards that are settled in cash are recorded as a liability with the changes in fair value recognized over the vesting period. Based on the performance criteria, there was no liability recorded for these performance unit awards at December 31, 2015 . Unit Options The following provides information related to unit option activity for the year ended December 31, 2015: Number of Units Underlying Options Weighted Average Exercise Price Per Unit Weighted Average Remaining Contractual Life in Years Aggregate Intrinsic Value Outstanding at December 31, 2014 5,444,417 $ 31.95 5.12 $ — Forfeited or expired (4,619,706 ) $ 33.60 Outstanding at December 31, 2015 824,711 $ 22.72 2.27 $ — Exercisable at December 31, 2015 821,787 $ 22.69 2.25 $ — No unit options were granted during the years ended December 31, 2015 , or December 31, 2014 . During the year ended December 31, 2013 , the weighted average grant-date fair value of unit options granted was $7.52 per unit. All unit options granted in 2013 were replacement awards issued in exchange for options assumed in the Berry acquisition. There were no unit options exercised during the year ended December 31, 2015 . During the years ended December 31, 2014 , and December 31, 2013 , the total intrinsic value of unit options exercised was approximately $11 million and $2 million , respectively. There was no unrecognized compensation cost related to nonvested unit options as of December 31, 2015 . The fair value of unit-based compensation for unit options was estimated on the date of grant using a Black-Scholes pricing model based on certain assumptions. That value may not be indicative of the fair value observed in a willing buyer/willing seller market transaction. The Company’s determination of the fair value of unit-based awards is affected by the Company’s unit price as well as assumptions consisting of a number of complex and subjective variables. The Company’s employee unit options have various restrictions including vesting provisions and restrictions on transfers and hedging, among others, and often are expected to be exercised prior to their contractual maturity. Expected volatilities used in the estimation of fair value of the unit option grants have been determined using available volatility data for the Company. Expected distributions are estimated based on the Company’s distribution rate at the date of grant. Forfeitures are estimated using historical Company data and are revised, if necessary, in subsequent periods if actual forfeitures differ from estimates. The risk-free rate for periods within the expected term of the unit option is based on the U.S. Treasury yield curve in effect at the time of grant. Historical data of the Company is used to estimate expected term. All employees granted awards have been determined to have similar behaviors for purposes of determining the expected term used to estimate fair value. The fair values of the Company’s unit option grants were based upon the following assumptions: 2013 (1) Expected volatility 29.65% – 50.88% Expected distributions 9.84% Risk-free rate 0.13% – 1.55% Expected term 0.68 years – 5 years (1) All unit options granted in 2013 were replacement awards issued in exchange for options assumed in the Berry acquisition. Berry Acquisition On December 16, 2013, in connection with the Berry acquisition (see Note 2), certain Berry awards were exchanged for awards issued by the Company. Each unvested Berry restricted stock unit (“RSU”) (excluding any Berry RSUs held by a former nonemployee director of Berry or by an employee of Berry whose employment was terminated in connection with the acquisition as agreed by the parties and any performance-based Berry RSUs) was converted into a restricted unit award in respect of the number of LINN Energy units. Each option to purchase shares of Berry common stock was converted into an option to purchase a number of LINN Energy units. Under the acquisition method of accounting, Berry employee RSUs and options were measured and recorded at their fair values on the acquisition date, resulting in additional purchase price consideration of approximately $19 million . The portion of the replacement awards attributable to post-combination service was calculated as the difference between the fair value of the replacement awards and the amount attributed to pre-combination service, and is recognized as compensation expense over the vesting period. Nonemployee Grants At December 31, 2015 , the Company had 15,000 outstanding unit warrants with an exercise price of $25.50 per unit, which are fully exercisable and expire in 2017. Defined Contribution Plan The Company sponsors a 401(k) defined contribution plan for eligible employees. Company contributions to the 401(k) plan consist of a discretionary matching contribution equal to 100% of the first 6% of eligible compensation contributed by the employee on a before-tax basis. The Company contributed approximately $11 million , $10 million and $7 million during the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , respectively, to the 401(k) plan’s trustee account. The 401(k) plan funds are held in a trustee account on behalf of the plan participants.

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	Debt The following summarizes the Company’s outstanding debt: December 31, 2015 2014 (in thousands, except percentages) LINN credit facility (1) $ 2,215,000 $ 1,795,000 Berry credit facility (2) 873,175 1,173,175 Term loan (3) 500,000 500,000 6.50% senior notes due May 2019 562,234 1,200,000 6.25% senior notes due November 2019 581,402 1,800,000 8.625% senior notes due April 2020 718,596 1,300,000 6.75% Berry senior notes due November 2020 261,100 299,970 12.00% senior secured second lien notes due December 2020 (4) 1,000,000 — Interest payable on second lien notes due December 2020 (4) 608,333 — 7.75% senior notes due February 2021 779,474 1,000,000 6.50% senior notes due September 2021 381,423 650,000 6.375% Berry senior notes due September 2022 572,700 599,163 Net unamortized discounts and premiums (8,694 ) (21,499 ) Total debt, net 9,044,743 10,295,809 Less current portion (5) (3,716,508 ) — Total long-term debt, net $ 5,328,235 $ 10,295,809 (1) Variable interest rates of 2.66% and 1.92% at December 31, 2015 , and December 31, 2014 , respectively. (2) Variable interest rates of 3.17% and 2.67% at December 31, 2015 , and December 31, 2014 , respectively. (3) Variable interest rates of 3.17% and 2.66% at December 31, 2015 and December 31, 2014 , respectively. (4) In November 2015, the Company issued $1.0 billion in aggregate principal amount of new 12.00% senior secured second lien notes due December 2020 in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes. See below for additional details. (5) Due to existing and anticipated covenant violations, the Company’s Credit Facilities and term loan were classified as current at December 31, 2015. The current portion also includes approximately $128 million of interest payable on the Second Lien Notes due within one year. Fair Value The Company’s debt is recorded at the carrying amount in the consolidated balance sheets. The carrying amounts of the Company’s credit facilities and term loan approximate fair value because the interest rates are variable and reflective of market rates. The Company uses a market approach to determine the fair value of its senior secured second lien notes and senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement. December 31, 2015 December 31, 2014 Carrying Value Fair Value Carrying Value Fair Value (in thousands) Credit facilities $ 3,088,175 $ 3,088,175 $ 2,968,175 $ 2,968,175 Term loan 500,000 500,000 500,000 500,000 Senior secured second lien notes 1,000,000 501,250 — — Interest payable on second lien notes 608,333 608,333 — — Senior notes, net 3,848,235 662,179 6,827,634 5,703,649 Total debt, net $ 9,044,743 $ 5,359,937 $ 10,295,809 $ 9,171,824 Credit Facilities LINN Credit Facility The Company’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) provides for (1) a senior secured revolving credit facility and (2) a $500 million senior secured term loan, in aggregate subject to the then-effective borrowing base. Borrowing capacity under the revolving credit facility is limited to the lesser of: (i) the then-effective borrowing base reduced by the $500 million term loan and (ii) the maximum commitment amount of $4.0 billion , and was $3.1 billion as of December 31, 2015 . The maturity date is April 2019. At December 31, 2015 , the borrowing base under the LINN Credit Facility was $4.05 billion , but the maximum borrowing availability was limited to $3.6 billion due to certain conditions. The borrowing base under the LINN Credit Facility automatically decreased to $3.6 billion on January 1, 2016, since certain conditions were not met. At December 31, 2015 , availability under the revolving credit facility was approximately $879 million , which includes reductions for the $500 million term loan and $6 million of outstanding letters of credit. In October 2015, the Company entered into an amendment to the LINN Credit Facility to provide for, among other things: (i) a “springing maturity” based on the maturity of any outstanding LINN Energy junior lien debt; (ii) the ability to incur up to $4.0 billion of junior lien debt to accommodate exchanges of the Company’s outstanding unsecured senior notes and Berry senior notes or as additional indebtedness, but such additional indebtedness may not exceed $1.0 billion ; (iii) a minimum liquidity requirement equal to the greater of $500 million and 15% of the then effective available borrowing base after giving effect to certain redemptions or repurchases of certain debt; (iv) a decrease in the covenant requiring the maintenance of an EBITDA to Interest Expense ratio of 2.5 to 1.0 , such that the minimum required ratio is decreased to 2.0 to 1.0 from December 31, 2015 through December 31, 2016, to 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and returning to 2.5 to 1.0 thereafter; (v) the ability to make necessary tax-related distributions or contributions to LinnCo, LLC; (vi) an increase in the mortgage requirement on the total value of the oil and natural gas properties included on our most recent reserve report from 80% to 90% ; and (vii) an increase to the applicable margin charged on borrowings under the LINN Credit Facility by 0.25% and an increase in the commitment fee under the LINN Credit Facility on the average daily unused amount of the maximum commitment amount of the lenders to 0.5% per annum. Redetermination of the borrowing base under the LINN Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. The administrative agent, at the direction of a super-majority of certain of the lenders, has the right to request one interim borrowing base redetermination per year. The Company also has the right to request one interim borrowing base redetermination per year, as well as the right to an additional interim redetermination each year in connection with certain acquisitions. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs, along with the maturity schedule of the Company’s hedges, are expected to adversely impact future redeterminations. The spring 2015 semi-annual borrowing base redetermination was completed in May 2015, and as a result of lower commodity prices, the borrowing base under the LINN Credit Facility decreased from $4.5 billion to $4.05 billion . The fall 2015 semi-annual redetermination was completed in October 2015 and the borrowing base under the LINN Credit Facility was reaffirmed at $4.05 billion , subject to certain conditions being met on or before January 1, 2016. On January 1, 2016, the borrowing base automatically decreased to $3.6 billion . The Company’s obligations under the LINN Credit Facility, as amended, are secured by mortgages on certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in the Company’s direct and indirect material subsidiaries. The Company is required to maintain mortgages on properties representing at least 90% of the total value of oil and natural gas properties included on its most recent reserve report. Additionally, the obligations under the LINN Credit Facility are guaranteed by all of the Company’s material subsidiaries, other than Berry, and are required to be guaranteed by any future material subsidiaries. At the Company’s election, interest on borrowings under the LINN Credit Facility, as amended, is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the LINN Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.75% and 1.75% per annum (depending on the then-current level of borrowings under the LINN Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR. The Company is required to pay a commitment fee to the lenders under the LINN Credit Facility, which accrues at a rate per annum of 0.50% on the average daily unused amount of the maximum commitment amount of the lenders. The $500 million term loan has a maturity date of April 2019, subject to a “springing maturity” based on the maturity of any outstanding LINN Energy junior lien debt, and incurs interest based on either the LIBOR plus a margin of 2.75% per annum or the ABR plus a margin of 1.75% per annum, at the Company’s election. Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR. The term loan may be repaid at the option of the Company without premium or penalty, subject to breakage costs. While the term loan is outstanding, the Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report, or 2) a Term Loan Collateral Coverage Ratio of at least 2.5 to 1.0 . The Term Loan Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount and the aggregate amount of the term loan outstanding. The other terms and conditions of the LINN Credit Facility, including the financial and other restrictive covenants set forth therein, are applicable to the term loan. Berry Credit Facility Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) had a borrowing base of $900 million , subject to lender commitments, as of December 31, 2015 . The maturity date is April 2019. At December 31, 2015 , lender commitments under the facility were also $900 million but there was less than $1 million of available borrowing capacity, including outstanding letters of credit. In October 2015, Berry entered into an amendment to the Berry Credit Facility to provide for, among other things: (i) a springing maturity based on the maturity of any outstanding Berry junior lien debt; (ii) the ability of Berry to incur junior lien debt to refinance its senior notes or as additional indebtedness, but such additional indebtedness issued may not exceed $500 million outstanding at any one time and is subject to a borrowing base reduction; (iii) a decrease in Berry’s covenant requiring the maintenance of an EBITDA to Interest Expense ratio of 2.5 to 1.0 , such that the permissible ratio is decreased to 2.0 to 1.0 from December 31, 2015 through December 31, 2016, to 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and returning to 2.5 to 1.0 thereafter; (iv) an increase in the mortgage requirement on the total value of the oil and natural gas properties included in Berry’s most recent reserve report from 80% to 90% ; (v) an increase to the applicable margin charged on borrowings under the Berry Credit Facility by 0.25% and increase the commitment fee under the Berry Credit Facility to 0.5% per annum; and (vi) permission to prepay or exchange Berry’s senior notes with notes issued by LINN Energy. Redetermination of the borrowing base under the Berry Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. A super-majority of the lenders under the Berry Credit Facility and Berry also have the right to request interim borrowing base redeterminations once between scheduled redeterminations. The spring 2015 semi-annual borrowing base redetermination was completed in May 2015, and as a result of lower commodity prices, the borrowing base under the Berry Credit Facility decreased from $1.4 billion to $1.2 billion . The fall 2015 semi-annual redetermination was completed in October 2015 and the borrowing base under the Berry Credit Facility decreased from $1.2 billion to $900 million . In connection with the reduction in Berry’s borrowing base in October 2015, Berry repaid $300 million of borrowings outstanding under the Berry Credit Facility. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs are expected to adversely impact future redeterminations. In connection with the reduction in Berry’s borrowing base in May 2015, LINN Energy borrowed $250 million under the LINN Credit Facility and contributed it to Berry to post as restricted cash with Berry’s lenders. As directed by LINN Energy, the $250 million was deposited on Berry’s behalf in a security account with the administrative agent subject to a security control agreement. Berry’s ability to withdraw funds from this account is subject to a concurrent reduction of the borrowing base under the Berry Credit Facility or lender’s consent in connection with a redetermination of such borrowing base. The $250 million may be used to satisfy obligations under the Berry Credit Facility or, subject to restrictions in the indentures governing Berry’s senior notes, may be returned to LINN Energy in the future. The amount is included in “restricted cash” on the consolidated balance sheet. Berry’s obligations under the Berry Credit Facility, as amended, are secured by mortgages on its oil and natural gas properties and other personal property. Berry is required to maintain mortgages on properties representing at least 90% of the present value of its oil and natural gas proved reserves. At Berry’s election, interest on borrowings under the Berry Credit Facility, as amended, is determined by reference to either the LIBOR plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the Berry Credit Facility) or a Base Rate (as defined in the Berry Credit Facility) plus an applicable margin between 0.75% and 1.75% per annum (depending on the then-current level of borrowings under the Berry Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the Base Rate and at the end of the applicable interest period for loans bearing interest at the LIBOR. Berry is required to pay a commitment fee to the lenders under the Berry Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the maximum commitment amount of the lenders. The Company refers to the LINN Credit Facility and the Berry Credit Facility, collectively, as the “Credit Facilities.” Senior Secured Second Lien Notes Due December 2020 On November 20, 2015, the Company issued $1.0 billion in aggregate principal amount of 12.00% senior secured second lien notes due December 2020 (“Second Lien Notes”) in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes as follows (in thousands): Par Value of Senior Notes Exchanged 6.50% senior notes due May 2019 $ 584,422 6.25% senior notes due November 2019 824,348 8.625% senior notes due April 2020 286,344 7.75% senior notes due February 2021 184,300 6.50% senior notes due September 2021 120,586 $ 2,000,000 The exchanges were accounted for as a troubled debt restructuring (“TDR”). Since the total future cash payments of the new debt were less than the carrying amount of the previous debt, a gain of approximately $352 million , or $1.03 per unit, was recognized and included in “gain (loss) on extinguishment of debt” on the consolidated statement of operations. TDR accounting requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. As a result, the Company’s reported interest expense will be significantly less than the contractual interest payments throughout the term of the Second Lien Notes. There were no interest payments made on the Second Lien Notes for the year ended December 31, 2015. The Second Lien Notes were issued under an indenture dated as of November 20, 2015, entered into by the Company and certain of its material domestic subsidiaries (the “Subsidiary Guarantors”). The Second Lien Notes mature on December 15, 2020, subject to a “springing maturity date” ahead of junior lien or unsecured indebtedness if more than $250 million of a particular series of such indebtedness is outstanding 92 days prior to the respective maturity date of such series, and bear interest at a rate of 12.00% per year, payable semiannually in arrears on June 15 and December 15 of each year, beginning on June 15, 2016. The Second Lien Notes are secured by second-priority liens on all of the Company’s and Subsidiary Guarantors’ assets that secure the LINN Credit Facility (the “Collateral”), and rank effectively junior to any indebtedness of the Company secured on a priority basis to the Second Lien Notes, including indebtedness under the LINN Credit Facility, to the extent of the value of the assets securing such indebtedness. The Collateral consists of: (i) certain of the Company’s and the Subsidiary Guarantors’ oil and natural gas properties and other personal property, as well as (ii) a pledge of all ownership interests in the Subsidiary Guarantors. At any time prior to December 15, 2018, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of Second Lien Notes at a redemption price of 112.00% of the principal amount, plus accrued and unpaid interest and Additional Interest (as defined in the Second Lien Notes indenture), if any, to the redemption date using the net cash proceeds of one or more equity offerings by the Company, provided that: • at least 65% of the aggregate principal amount of the Second Lien Notes remain outstanding immediately after the occurrence of such redemption (excluding Second Lien Notes held by the Company); and • the redemption occurs within 180 days of the date of the closing of such equity offering. Prior to December 15, 2018, the Company may redeem all or part of the Second Lien Notes, upon not less than 30 or more than 60 days’ notice, at a redemption price equal to the sum of: • 100% of the principal amount thereof, plus • the Make Whole Premium (as defined in the Second Lien Notes indenture) at the redemption date, plus • accrued and unpaid interest, if any, to the redemption date. On and after December 15, 2018, the Company has the option to redeem all or part of the Second Lien Notes, upon not less than 30 or more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest and Additional Interest, if any, to the redemption date, if redeemed during the twelve-month period beginning on December 15 of the years indicated below: Percentage 2018 112.000 % 2019 and thereafter 106.000 % The Second Lien Notes indenture contains covenants that, among other things, limit the Company’s ability and the ability of the Company’s restricted subsidiaries to: (i) declare or pay distributions on, purchase or redeem the Company’s units or purchase or redeem the Company’s or its restricted subsidiaries’ indebtedness secured by liens junior in priority to liens securing the Second Lien Notes, unsecured indebtedness or subordinated indebtedness; (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. In connection with the issuance of the Second Lien Notes, the Company entered into a Registration Rights Agreement with each of the holders (collectively, the “Registration Rights Agreements”), pursuant to the terms of the exchange agreements. Under the Registration Rights Agreements, the Company agreed to use its reasonable efforts to file with the U.S. Securities and Exchange Commission and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the Second Lien Notes in exchange for outstanding Second Lien Notes within 370 days after the notes were issued. In certain circumstances, the Company may be required to file a shelf registration statement to cover resales of the Second Lien Notes. The Company will be obligated to file one or more registration statements as described above only if the restrictive legend on the Second Lien Notes has not been removed and the Second Lien Notes are not freely tradable pursuant to Rule 144 under the Securities Act of 1933, as amended, as of the 370th day after the notes were issued. If the Company fails to satisfy these obligations, the Company may be required to pay additional interest to holders of the Second Lien Notes under certain circumstances. Repurchases of Senior Notes During the year ended December 31, 2015 , the Company repurchased, through privately negotiated transactions and on the open market, approximately $992 million of its outstanding senior notes as follows: • 6.50% senior notes due May 2019 – $53 million ; • 6.25% senior notes due November 2019 – $395 million ; • 8.625% senior notes due April 2020 – $295 million ; • 6.75% Berry senior notes due November 2020 – $39 million ; • 7.75% senior notes due February 2021 – $36 million ; • 6.50% senior notes due September 2021 – $148 million ; and • 6.375% Berry senior notes due September 2022 – $26 million . In connection with the repurchases, the Company paid approximately $609 million in cash and recorded a gain on extinguishment of debt of approximately $367 million for the year ended December 31, 2015 . Senior Notes Covenants The Company’s senior notes contain covenants that, among other things, may limit its ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. As of December 31, 2015 , the Company was in compliance with all financial and other covenants of its senior notes. Berry’s senior notes contain covenants that, among other things, may limit its ability to: (i) incur or guarantee additional indebtedness; (ii) pay distributions or dividends on Berry’s equity or redeem its subordinated debt; (iii) create certain liens; (iv) enter into agreements that restrict distributions or other payments from Berry’s restricted subsidiaries to Berry; (v) sell assets; (vi) engage in transactions with affiliates; and (vii) consolidate, merge or transfer all or substantially all of Berry’s assets. As of December 31, 2015 , Berry was in compliance with all financial and other covenants of its senior notes. In addition, any cash generated by Berry is currently being used by Berry to fund its activities. To the extent that Berry generates cash in excess of its needs and determines to distribute such amounts to LINN Energy, the indentures governing Berry’s senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and Berry may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Berry indentures. Berry’s restricted payments basket may be increased in accordance with the terms of the Berry indentures by, among other things, 50% of Berry’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions. Covenant Violations The audit report the Company received with respect to its consolidated financial statements contains an explanatory paragraph expressing uncertainty as to the Company’s ability to continue as a going concern, the delivery of which constitutes a default under the LINN Credit Facility. The Company is also currently in default under the Second Lien Indenture due to its failure to deliver mortgages by February 18, 2016. See “Going Concern Uncertainty” in Note 1 for additional information.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives Commodity Derivatives The Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business, service debt and, if and when resumed, pay distributions. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials. The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. In connection with the 2013 acquisition of Berry, the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives. The following table presents derivative positions for the periods indicated as of December 31, 2015 : 2016 2017 2018 Natural gas positions: Fixed price swaps (NYMEX Henry Hub): Hedged volume (MMMBtu) 121,841 120,122 36,500 Average price ($/MMBtu) $ 4.20 $ 4.26 $ 5.00 Put options (NYMEX Henry Hub): Hedged volume (MMMBtu) 76,269 66,886 — Average price ($/MMBtu) $ 5.00 $ 4.88 $ — Oil positions: Fixed price swaps (NYMEX WTI): (1) Hedged volume (MBbls) 11,465 4,755 — Average price ($/Bbl) $ 90.56 $ 89.02 $ — Put options (NYMEX WTI): Hedged volume (MBbls) 3,271 384 — Average price ($/Bbl) $ 90.00 $ 90.00 $ — Natural gas basis differential positions: (2) Panhandle basis swaps: (3) Hedged volume (MMMBtu) 59,954 59,138 16,425 Hedged differential ($/MMBtu) $ (0.32 ) $ (0.33 ) $ (0.33 ) 2016 2017 2018 NWPL Rockies basis swaps: (3) Hedged volume (MMMBtu) 65,794 38,880 10,804 Hedged differential ($/MMBtu) $ (0.24 ) $ (0.19 ) $ (0.19 ) MichCon basis swaps: (3) Hedged volume (MMMBtu) 7,768 7,437 2,044 Hedged differential ($/MMBtu) $ 0.05 $ 0.05 $ 0.05 Houston Ship Channel basis swaps: (3) Hedged volume (MMMBtu) 34,364 36,730 986 Hedged differential ($/MMBtu) $ (0.02 ) $ (0.02 ) $ (0.08 ) Permian basis swaps: (3) Hedged volume (MMMBtu) 2,975 2,629 1,314 Hedged differential ($/MMBtu) $ (0.20 ) $ (0.20 ) $ (0.20 ) SoCal basis swaps: (4) Hedged volume (MMMBtu) 32,940 — — Hedged differential ($/MMBtu) $ (0.03 ) $ — $ — Oil timing differential positions: Trade month roll swaps (NYMEX WTI): (5) Hedged volume (MBbls) 2,652 2,654 — Hedged differential ($/Bbl) $ 0.25 $ 0.25 $ — (1) Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for the year ending December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, at counterparty election on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years. (2) Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price. (3) For positions which hedge exposure to differentials in producing areas, the Company receives the NYMEX Henry Hub natural gas price plus the respective spread and pays the specified index price. Cash settlements are made on a net basis. (4) For positions which hedge exposure to differentials in consuming areas, the Company pays the NYMEX Henry Hub natural gas price plus the respective spread and receives the specified index price. Cash settlements are made on a net basis. (5) The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”). During the year ended December 31, 2015, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for May 2015 through December 2017 to hedge exposure to differentials in certain producing areas and oil swaps for April 2015 through December 2015. In addition, the Company entered into natural gas basis swaps for May 2015 through December 2016 to hedge exposure to the differential in California, where it consumes natural gas in its heavy oil development operations. During the fourth quarter of 2015, the Company canceled certain of its commodity derivative contracts, consisting of Permian basis swaps for 2016 and 2017, trade month roll swaps for 2016 and 2017, and positions representing oil swaps which could have been extended at counterparty election for 2017. The Company received net cash settlements of approximately $5 million from the cancellations. During the fourth quarter of 2014, the Company canceled all of its ICE Brent – NYMEX WTI basis swaps for 2015 and received cash settlements of approximately $12 million . As of December 31, 2014, the Company had no outstanding ICE Brent – NYMEX WTI basis swaps. During the year ended December 31, 2013, the Company entered into commodity derivative contracts consisting of oil basis swaps for 2013 and natural gas basis swaps for 2013 through 2018. Also, in connection with the Berry acquisition (see Note 2), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including oil swaps, oil trade month roll swaps and oil collars through 2014, and oil basis swaps and oil three-way collars through 2015. Settled derivatives on natural gas production for the year ended December 31, 2015 , included volumes of 189,895 MMMBtu at an average contract price of $5.12 per MMBtu. Settled derivatives on oil production for the year ended December 31, 2015 , included volumes of 18,884 MBbls at an average contract price of $89.28 per Bbl. Settled derivatives on natural gas production for the year ended December 31, 2014 , included volumes of 177,029 MMMBtu at an average contract price of $5.14 per MMBtu. Settled derivatives on oil production for the year ended December 31, 2014 , included volumes of 24,988 MBbls at an average contract price of $92.39 per Bbl. Settled derivatives on natural gas production for the year ended December 31, 2013 , included volumes of 173,488 MMMBtu at an average contract price of $5.29 per MMBtu. Settled derivatives on oil production for the year ended December 31, 2013 , included volumes of 15,590 MBbls at an average contract price of $95.35 per Bbl. The natural gas derivatives are settled based on the closing price of NYMEX Henry Hub 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 WTI crude oil for each day of the delivery month. Balance Sheet Presentation The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. The following table summarizes the fair value of derivatives outstanding on a gross basis: December 31, 2015 2014 (in thousands) Assets: Commodity derivatives $ 1,812,375 $ 2,014,815 Liabilities: Commodity derivatives $ 28,842 $ 90,260 By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facilities or were participants or affiliates of participants in its Credit Facilities at the time it originally entered into the derivatives. The Credit Facilities are secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $1.8 billion at December 31, 2015 . The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated. Gains (Losses) on Derivatives A summary of gains and losses on derivatives included on the consolidated statements of operations is presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Gains on oil and natural gas derivatives $ 1,056,189 $ 1,206,179 $ 177,857 Lease operating expenses (1) 6,893 — — Total gains on oil and natural gas derivatives $ 1,063,082 $ 1,206,179 $ 177,857 (1) Consists of gains and (losses) on derivatives used to hedge exposure to differentials in consuming areas, which were entered into in March 2015. For the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , the Company received net cash settlements of approximately $1.2 billion , $108 million and $249 million , respectively.

Fair Value Measurements on a Re

Fair Value Measurements on a Recurring Basis	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements on a Recurring Basis	Fair Value Measurements on a Recurring Basis The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads are applied to the Company’s commodity derivatives. Fair Value Hierarchy In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Financial assets and liabilities recorded in the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows: Level 1 Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Level 2 Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives). Level 3 Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis: December 31, 2015 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 1,812,375 $ (25,744 ) $ 1,786,631 Liabilities: Commodity derivatives $ 28,842 $ (25,744 ) $ 3,098 December 31, 2014 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 2,014,815 $ (89,576 ) $ 1,925,239 Liabilities: Commodity derivatives $ 90,260 $ (89,576 ) $ 684 (1) Represents counterparty netting under agreements governing such derivatives.

Other Property and Equipment

Other Property and Equipment	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Other Property and Equipment	Other Property and Equipment Other property and equipment consists of the following: December 31, 2015 2014 (in thousands) Natural gas plant and pipeline $ 480,161 $ 479,754 Furniture and office equipment 106,462 88,893 Buildings and leasehold improvements 72,976 49,046 Vehicles 37,641 36,534 Drilling and other equipment 7,934 6,994 Land 3,537 7,928 708,711 669,149 Less accumulated depreciation (195,661 ) (144,282 ) $ 513,050 $ 524,867

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other noncurrent liabilities” on the consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors ( 2% for each of the years in the three-year period ended December 31, 2015 ); and (iv) a credit-adjusted risk-free interest rate (average of 5.5% , 5.3% and 6.2% for the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , respectively). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The following table presents a reconciliation of the Company’s asset retirement obligations: December 31, 2015 2014 (in thousands) Asset retirement obligations at beginning of year $ 497,570 $ 289,321 Liabilities added from acquisitions — 176,538 Liabilities added from drilling 3,574 10,476 Liabilities associated with assets divested (3,306 ) (25,656 ) Current year accretion expense 30,016 22,164 Settlements (6,336 ) (12,620 ) Revision of estimates 2,023 37,347 Asset retirement obligations at end of year $ 523,541 $ 497,570

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies For certain statewide class action royalty payment disputes 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 courts, will result in no loss to the Company. 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. During the years ended December 31, 2015, December 31, 2014, and December 31, 2013, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. In 2008, Lehman Brothers Holdings Inc. and Lehman Brothers Commodity Services Inc. (together “Lehman”), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. In March 2011, the Company and Lehman entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman in the amount of $51 million (the “Company Claim”). In December 2011, a Chapter 11 Plan was approved by the Bankruptcy Court. In 2015, 2014 and 2013, the Company received approximately $4 million , $7 million and $11 million , respectively, of the Company Claim which are each included in “gains on oil and natural gas derivatives” on the consolidated statements of operations. In the aggregate, the Company has received approximately $50 million of the Company Claim.

Operating Leases

Operating Leases	12 Months Ended
	Dec. 31, 2015
Leases, Operating [Abstract]
Operating Leases	Operating Leases The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2034 . The Company recognized expense under operating leases of approximately $21 million , $14 million and $7 million for the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , respectively. As of December 31, 2015 , future minimum lease payments were as follows (in thousands): 2016 $ 10,647 2017 8,887 2018 7,521 2019 7,865 2020 7,721 Thereafter 27,336 $ 69,977

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Unit	Earnings Per Unit Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect. The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net loss: Year Ended December 31, 2015 2014 2013 (in thousands, except per unit data) Net loss $ (4,759,811 ) $ (451,809 ) $ (691,337 ) Allocated to participating securities (3,039 ) (7,117 ) (5,935 ) $ (4,762,850 ) $ (458,926 ) $ (697,272 ) Basic net loss per unit $ (13.87 ) $ (1.40 ) $ (2.94 ) Diluted net loss per unit $ (13.87 ) $ (1.40 ) $ (2.94 ) Basic weighted average units outstanding 343,323 328,918 237,544 Dilutive effect of unit equivalents — — — Diluted weighted average units outstanding 343,323 328,918 237,544 Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 4 million , 6 million and 4 million unit options and warrants for the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , respectively. All equivalent units were antidilutive for each of the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company, except as set forth in the tables below. Amounts recognized for income taxes are reported in “income tax expense (benefit)” on the consolidated statements of operations. The Company’s taxable income or loss, which may vary substantially from the net income or net loss reported on the consolidated statements of operations, is includable in the federal and state income tax returns of each unitholder. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholder’s tax attributes. Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Income tax expense (benefit) consisted of the following: Year Ended December 31, 2015 2014 2013 (in thousands) Current taxes: Federal $ (12,021 ) $ 473 $ 144 State 1,022 21 198 Deferred taxes: Federal 8,237 (104 ) (2,805 ) State (3,699 ) 4,047 264 $ (6,461 ) $ 4,437 $ (2,199 ) As of December 31, 2015 , the Company’s taxable entities had approximately $1 million of net operating loss carryforwards for federal income tax purposes which will begin expiring in 2036 . A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Year Ended December 31, 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % State, net of federal tax benefit 0.1 (0.9 ) (0.1 ) Loss excluded from nontaxable entities (34.8 ) (34.6 ) (34.6 ) Other (0.2 ) (0.5 ) — Effective rate 0.1 % (1.0 )% 0.3 % Significant components of the deferred tax assets and liabilities were as follows: December 31, 2015 2014 (in thousands) Deferred tax assets: Net operating loss carryforwards $ 370 $ — Unit-based compensation 18,214 22,105 Valuation allowance (2,159 ) — Other 7,300 6,857 Total deferred tax assets 23,725 28,962 Deferred tax liabilities: Property and equipment principally due to differences in depreciation (12,534 ) (10,991 ) Other 8 (6,370 ) Total deferred tax liabilities (12,526 ) (17,361 ) Net deferred tax assets $ 11,199 $ 11,601 Net deferred tax assets and liabilities were classified on the consolidated balance sheets as follows: December 31, 2015 2014 (in thousands) Deferred tax assets $ 23,188 $ 28,442 Deferred tax liabilities (675 ) (2,964 ) Other current assets $ 22,513 $ 25,478 Deferred tax assets $ 537 $ 520 Deferred tax liabilities (11,851 ) (14,397 ) Other noncurrent liabilities $ (11,314 ) $ (13,877 ) In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2015 , based on projections of future taxable income for the periods in which the deferred tax assets are deductible, valuation allowances of approximately $2 million were recorded for tax carryforwards and attributes to reduce the net deferred tax assets to an amount that is more likely than not to be realized. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2015 , and December 31, 2014 . The tax years 2012 – 2015 remain open to examination for federal income tax purposes.

Supplemental Disclosures to the

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows	12 Months Ended
	Dec. 31, 2015
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows	Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows “Other accrued liabilities” reported on the consolidated balance sheets include the following: December 31, 2015 2014 (in thousands) Accrued interest $ 63,957 $ 105,310 Accrued compensation 37,061 44,875 Asset retirement obligations 14,234 16,187 Other 4,341 1,364 $ 119,593 $ 167,736 Supplemental disclosures to the consolidated statements of cash flows are presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Cash payments for interest, net of amounts capitalized $ 562,303 $ 542,775 $ 392,607 Cash payments for income taxes $ 643 $ — $ 14 Noncash investing and financing activities: In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follow: Fair value of assets acquired $ — $ 2,679,547 $ 5,726,681 Cash paid, net of cash acquired — (2,395,339 ) (109,350 ) Units issued in connection with the Berry acquisition — — (2,781,888 ) Noncash gains on exchanges of properties — (85,493 ) — Receivables from sellers — 16,213 (93 ) Payables to sellers — (3,515 ) (6,854 ) Liabilities assumed $ — $ 211,413 $ 2,828,496 Accrued capital expenditures $ 81,656 $ 240,331 $ 334,542 Included in “acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired” on the consolidated statements of cash flows for the years ended December 31, 2014 , and December 31, 2013 , is approximately $25 million and $170 million , respectively, paid by the Company towards the future funding commitment related to the joint-venture agreement entered into with Anadarko (see Note 2). In November 2015, the Company issued $1.0 billion in aggregate principal amount of Second Lien Notes in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes (see Note 6). On November 21, 2014, the Company, through two of its wholly owned subsidiaries, completed a noncash exchange of a portion of its Permian Basin properties to ExxonMobil in exchange for properties in California’s South Belridge Field. On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed a noncash exchange of a portion of its Permian Basin properties to Exxon XTO for properties in the Hugoton Basin. For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At December 31, 2015 , “restricted cash” on the consolidated balance sheet includes $250 million that LINN Energy borrowed under the LINN Credit Facility and contributed to Berry in May 2015 to post with Berry’s lenders in connection with the reduction in the Berry Credit Facility’s borrowing base. Restricted cash also includes approximately $7 million and $6 million at December 31, 2015 , and December 31, 2014 , respectively, of cash deposited by the Company into a separate account designated for asset retirement obligations in accordance with contractual agreements. The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facilities. At December 31, 2015 , and December 31, 2014 , net outstanding checks of approximately $21 million and $95 million , respectively, were reclassified and included in “accounts payable and accrued expenses” on the consolidated balance sheets. Net outstanding checks are presented as cash flows from financing activities and included in “other” on the consolidated statements of cash flows.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions LinnCo LinnCo, an affiliate of LINN Energy, was formed on April 30, 2012. LinnCo’s initial sole purpose was to own units in LINN Energy. In connection with the acquisition of Berry, LinnCo amended its limited liability company agreement to permit, among other things, the acquisition and subsequent contribution of assets to LINN Energy. All of LinnCo’s common shares are held by the public. As of December 31, 2015 , LinnCo had no significant assets or operations other than those related to its interest in LINN Energy and owned approximately 37% of LINN Energy’s outstanding units. On December 16, 2013, LinnCo and LINN Energy completed the transactions contemplated by the merger agreement, as amended, under which Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement between LinnCo and LINN Energy, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units valued at approximately $2.8 billion . LINN Energy has agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any financial, legal, accounting, tax advisory, financial advisory and engineering fees, and other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity. These expenses include costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees. In addition, the Company has agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities. All expenses and costs paid by LINN Energy on LinnCo’s behalf are expensed by LINN Energy. For the year ended December 31, 2015 , LinnCo incurred total general and administrative expenses and certain offering costs of approximately $3 million , all of which had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2015 . The expenses for the year ended December 31, 2015 , include approximately $2 million related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses. For the year ended December 31, 2014 , LinnCo incurred total general and administrative expenses and certain offering costs of approximately $3 million , all of which had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2014 . The expenses for the year ended December 31, 2014 , include approximately $2 million related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses. In addition, during the year ended December 31, 2014 , LINN Energy paid approximately $11 million on LinnCo’s behalf for general and administrative expenses incurred by LinnCo in 2013. For the year ended December 31, 2013 , LinnCo incurred total general and administrative expenses and certain offering costs of approximately $42 million . The expenses for the year ended December 31, 2013 , include approximately $40 million of transaction costs related to the Berry acquisition (see Note 2), including approximately $9 million of noncash share-based compensation expense. The expenses for the year ended December 31, 2013 , also include approximately $2 million related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses. During the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , the Company paid approximately $121 million , $373 million and $101 million , respectively, in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy. Other One of the Company’s directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , the Company incurred expenditures of approximately $9 million , $21 million and $26 million , respectively, related to services rendered by Superior and its subsidiaries.

Subsidiary Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Subsidiary Guarantors	Subsidiary Guarantors Linn Energy, LLC’s May 2019 senior notes, November 2019 senior notes, April 2020 senior notes, December 2020 second lien notes, February 2021 senior notes and September 2021 senior notes are guaranteed by all of the Company’s material subsidiaries, other than Berry Petroleum Company, LLC, which is an indirect 100% wholly owned subsidiary of the Company. The following condensed consolidating financial information presents the financial information of Linn Energy, LLC, the guarantor subsidiaries and the non-guarantor subsidiary in accordance with Securities and Exchange Commission (“SEC”) Regulation S-X Rule 3-10. The condensed consolidating financial information for the co-issuer, Linn Energy Finance Corp., is not presented as it has no assets, operations or cash flows. The financial information may not necessarily be indicative of the financial position or results of operations had the guarantor subsidiaries or non-guarantor subsidiary operated as independent entities. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries. CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2015 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) ASSETS Current assets: Cash and cash equivalents $ 1,073 $ 72 $ 1,023 $ — $ 2,168 Accounts receivable – trade, net — 170,503 46,053 — 216,556 Accounts receivable – affiliates 2,920,082 8,621 — (2,928,703 ) — Derivative instruments — 1,207,012 13,218 — 1,220,230 Other current assets 26,905 72,120 20,897 (1 ) 119,921 Total current assets 2,948,060 1,458,328 81,191 (2,928,704 ) 1,558,875 Noncurrent assets: Oil and natural gas properties (successful efforts method) — 13,110,094 5,011,061 — 18,121,155 Less accumulated depletion and amortization — (9,557,283 ) (1,596,165 ) 55,956 (11,097,492 ) — 3,552,811 3,414,896 55,956 7,023,663 Other property and equipment — 597,216 111,495 — 708,711 Less accumulated depreciation — (183,139 ) (12,522 ) — (195,661 ) — 414,077 98,973 — 513,050 Derivative instruments — 566,401 — — 566,401 Restricted cash — 7,004 250,359 — 257,363 Notes receivable – affiliates 175,100 — — (175,100 ) — Investments in consolidated subsidiaries 3,940,444 — — (3,940,444 ) — Other noncurrent assets 35,559 5,978 16,057 — 57,594 4,151,103 579,383 266,416 (4,115,544 ) 881,358 Total noncurrent assets 4,151,103 4,546,271 3,780,285 (4,059,588 ) 8,418,071 Total assets $ 7,099,163 $ 6,004,599 $ 3,861,476 $ (6,988,292 ) $ 9,976,946 LIABILITIES AND UNITHOLDERS’ CAPITAL (DEFICIT) Current liabilities: Accounts payable and accrued expenses $ 1,285 $ 336,962 $ 117,127 $ — $ 455,374 Accounts payable – affiliates — 2,920,082 8,621 (2,928,703 ) — Derivative instruments — — 2,241 — 2,241 Current portion of long-term debt 2,843,333 — 873,175 — 3,716,508 Other accrued liabilities 49,861 52,997 16,736 (1 ) 119,593 Total current liabilities 2,894,479 3,310,041 1,017,900 (2,928,704 ) 4,293,716 Noncurrent liabilities: Derivative instruments — 857 — — 857 Long-term debt, net 4,482,867 — 845,368 — 5,328,235 Notes payable – affiliates — 175,100 — (175,100 ) — Other noncurrent liabilities — 410,990 212,049 — 623,039 Total noncurrent liabilities 4,482,867 586,947 1,057,417 (175,100 ) 5,952,131 Unitholders’ capital (deficit): Units issued and outstanding 5,333,834 4,831,758 2,798,713 (7,621,189 ) 5,343,116 Accumulated deficit (5,612,017 ) (2,724,147 ) (1,012,554 ) 3,736,701 (5,612,017 ) (278,183 ) 2,107,611 1,786,159 (3,884,488 ) (268,901 ) Total liabilities and unitholders’ capital (deficit) $ 7,099,163 $ 6,004,599 $ 3,861,476 $ (6,988,292 ) $ 9,976,946 CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2014 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) ASSETS Current assets: Cash and cash equivalents $ 38 $ 185 $ 1,586 $ — $ 1,809 Accounts receivable – trade, net — 371,325 100,359 — 471,684 Accounts receivable – affiliates 4,028,890 13,205 — (4,042,095 ) — Derivative instruments — 1,033,448 43,694 — 1,077,142 Other current assets 18 96,678 59,259 — 155,955 Total current assets 4,028,946 1,514,841 204,898 (4,042,095 ) 1,706,590 Noncurrent assets: Oil and natural gas properties (successful efforts method) — 13,196,841 4,872,059 — 18,068,900 Less accumulated depletion and amortization — (4,342,675 ) (525,007 ) — (4,867,682 ) — 8,854,166 4,347,052 — 13,201,218 Other property and equipment — 553,150 115,999 — 669,149 Less accumulated depreciation — (135,830 ) (8,452 ) — (144,282 ) — 417,320 107,547 — 524,867 Derivative instruments — 848,097 — — 848,097 Restricted cash — 6,100 125 — 6,225 Notes receivable – affiliates 130,500 — — (130,500 ) — Advance to affiliate — — 293,627 (293,627 ) — Investments in consolidated subsidiaries 8,562,608 — — (8,562,608 ) — Other noncurrent assets 116,637 5,716 14,159 — 136,512 8,809,745 859,913 307,911 (8,986,735 ) 990,834 Total noncurrent assets 8,809,745 10,131,399 4,762,510 (8,986,735 ) 14,716,919 Total assets $ 12,838,691 $ 11,646,240 $ 4,967,408 $ (13,028,830 ) $ 16,423,509 LIABILITIES AND UNITHOLDERS’ CAPITAL Current liabilities: Accounts payable and accrued expenses $ 3,784 $ 581,880 $ 229,145 $ — $ 814,809 Accounts payable – affiliates — 4,028,890 13,205 (4,042,095 ) — Advance from affiliate — 293,627 — (293,627 ) — Other accrued liabilities 89,507 59,142 19,087 — 167,736 Total current liabilities 93,291 4,963,539 261,437 (4,335,722 ) 982,545 Noncurrent liabilities: Long-term debt, net 8,208,857 — 2,086,952 — 10,295,809 Notes payable – affiliates — 130,500 — (130,500 ) — Derivative instruments — 684 — — 684 Other noncurrent liabilities — 400,851 200,015 — 600,866 Total noncurrent liabilities 8,208,857 532,035 2,286,967 (130,500 ) 10,897,359 Unitholders’ capital: Units issued and outstanding 5,388,749 4,831,339 2,416,381 (7,240,658 ) 5,395,811 Accumulated income (deficit) (852,206 ) 1,319,327 2,623 (1,321,950 ) (852,206 ) 4,536,543 6,150,666 2,419,004 (8,562,608 ) 4,543,605 Total liabilities and unitholders’ capital $ 12,838,691 $ 11,646,240 $ 4,967,408 $ (13,028,830 ) $ 16,423,509 CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2015 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Revenues and other: Oil, natural gas and natural gas liquids sales $ — $ 1,151,240 $ 575,031 $ — $ 1,726,271 Gains on oil and natural gas derivatives — 1,027,014 29,175 — 1,056,189 Marketing revenues — 43,876 30,253 — 74,129 Other revenues — 19,550 7,195 — 26,745 — 2,241,680 641,654 — 2,883,334 Expenses: Lease operating expenses — 372,609 245,155 — 617,764 Transportation expenses — 167,561 52,160 — 219,721 Marketing expenses — 35,278 21,866 — 57,144 General and administrative expenses — 210,894 85,993 — 296,887 Exploration costs — 9,473 — — 9,473 Depreciation, depletion and amortization — 547,675 251,371 6,711 805,757 Impairment of long-lived assets — 5,024,944 853,810 (64,800 ) 5,813,954 Taxes, other than income taxes 2 111,300 70,593 — 181,895 Gains on sale of assets and other, net — (195,490 ) (1,919 ) — (197,409 ) 2 6,284,244 1,579,029 (58,089 ) 7,805,186 Other income and (expenses): Interest expense, net of amounts capitalized (463,168 ) 2,533 (85,818 ) — (546,453 ) Interest expense – affiliates — (12,123 ) — 12,123 — Interest income – affiliates 12,123 — — (12,123 ) — Gain on extinguishment of debt 708,050 — 11,209 — 719,259 Equity in losses from consolidated subsidiaries (5,002,695 ) — — 5,002,695 — Other, net (13,804 ) (161 ) (3,261 ) — (17,226 ) (4,759,494 ) (9,751 ) (77,870 ) 5,002,695 155,580 Loss before income taxes (4,759,496 ) (4,052,315 ) (1,015,245 ) 5,060,784 (4,766,272 ) Income tax expense (benefit) 315 (6,708 ) (68 ) — (6,461 ) Net loss $ (4,759,811 ) $ (4,045,607 ) $ (1,015,177 ) $ 5,060,784 $ (4,759,811 ) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2014 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Revenues and other: Oil, natural gas and natural gas liquids sales $ — $ 2,312,137 $ 1,298,402 $ — $ 3,610,539 Gains on oil and natural gas derivatives — 1,127,395 78,784 — 1,206,179 Marketing revenues — 84,349 50,911 — 135,260 Other revenues — 28,133 3,192 — 31,325 — 3,552,014 1,431,289 — 4,983,303 Expenses: Lease operating expenses — 440,624 364,540 — 805,164 Transportation expenses — 165,489 41,842 — 207,331 Marketing expenses — 81,210 36,255 — 117,465 General and administrative expenses — 190,286 102,787 — 293,073 Exploration costs — 125,037 — — 125,037 Depreciation, depletion and amortization — 771,549 302,353 — 1,073,902 Impairment of long-lived assets — 2,050,387 253,362 — 2,303,749 Taxes, other than income taxes 40 169,655 97,708 — 267,403 (Gains) losses on sale of assets and other, net — (487,286 ) 120,786 — (366,500 ) 40 3,506,951 1,319,633 — 4,826,624 Other income and (expenses): Interest expense, net of amounts capitalized (480,259 ) (19,631 ) (87,948 ) — (587,838 ) Interest expense – affiliates — (7,954 ) — 7,954 — Interest income – affiliates 7,954 — — (7,954 ) — Equity in earnings from consolidated subsidiaries 28,397 — — (28,397 ) — Other, net (7,861 ) (7,309 ) (1,043 ) — (16,213 ) (451,769 ) (34,894 ) (88,991 ) (28,397 ) (604,051 ) Income (loss) before income taxes (451,809 ) 10,169 22,665 (28,397 ) (447,372 ) Income tax expense — 4,368 69 — 4,437 Net income (loss) $ (451,809 ) $ 5,801 $ 22,596 $ (28,397 ) $ (451,809 ) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2013 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Revenues and other: Oil, natural gas and natural gas liquids sales $ — $ 2,022,916 $ 50,324 $ — $ 2,073,240 Gains (losses) on oil and natural gas derivatives — 182,906 (5,049 ) — 177,857 Marketing revenues — 52,328 1,843 — 54,171 Other revenues — 26,387 — — 26,387 — 2,284,537 47,118 — 2,331,655 Expenses: Lease operating expenses — 357,113 15,410 — 372,523 Transportation expenses — 125,864 2,576 — 128,440 Marketing expenses — 36,259 1,633 — 37,892 General and administrative expenses — 215,973 20,298 — 236,271 Exploration costs — 5,251 — — 5,251 Depreciation, depletion and amortization — 818,466 10,845 — 829,311 Impairment of long-lived assets — 828,317 — — 828,317 Taxes, other than income taxes — 136,501 2,130 — 138,631 Losses on sale of assets and other, net 724 2,705 10,208 — 13,637 724 2,526,449 63,100 — 2,590,273 Other income and (expenses): Interest expense, net of amounts capitalized (415,670 ) (1,504 ) (3,963 ) — (421,137 ) Interest expense – affiliates — (5,543 ) — 5,543 — Interest income – affiliates 5,543 — — (5,543 ) — Loss on extinguishment of debt (5,304 ) — — — (5,304 ) Equity in losses from consolidated subsidiaries (266,899 ) — — 266,899 — Other, net (8,283 ) (166 ) (28 ) — (8,477 ) (690,613 ) (7,213 ) (3,991 ) 266,899 (434,918 ) Loss before income taxes (691,337 ) (249,125 ) (19,973 ) 266,899 (693,536 ) Income tax benefit — (2,199 ) — — (2,199 ) Net loss $ (691,337 ) $ (246,926 ) $ (19,973 ) $ 266,899 $ (691,337 ) CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2015 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from operating activities: Net loss $ (4,759,811 ) $ (4,045,607 ) $ (1,015,177 ) $ 5,060,784 $ (4,759,811 ) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization — 547,675 251,371 6,711 805,757 Impairment of long-lived assets — 5,024,944 853,810 (64,800 ) 5,813,954 Unit-based compensation expenses — 56,136 — — 56,136 Gain on extinguishment of debt (708,050 ) — (11,209 ) — (719,259 ) Amortization and write-off of deferred financing fees 30,993 — 3,750 — 34,743 Gains on sale of assets and other, net — (188,200 ) (961 ) — (189,161 ) Equity in losses from consolidated subsidiaries 5,002,695 — — (5,002,695 ) — Deferred income taxes — 4,606 (68 ) — 4,538 Derivatives activities: Total gains — (1,027,014 ) (36,068 ) — (1,063,082 ) Cash settlements — 1,130,640 68,770 — 1,199,410 Cash settlements on canceled derivatives — 4,679 — — 4,679 Changes in assets and liabilities: Decrease in accounts receivable – trade, net — 207,300 59,941 — 267,241 Decrease in accounts receivable – affiliates 1,167,823 4,584 — (1,172,407 ) — (Increase) decrease in other assets — (9,142 ) 18,724 — 9,582 Decrease in accounts payable and accrued expenses (14 ) (98,209 ) (58,171 ) — (156,394 ) Decrease in accounts payable and accrued expenses – affiliates — (1,167,823 ) (4,584 ) 1,172,407 — Decrease in other liabilities (39,646 ) (11,620 ) (7,610 ) — (58,876 ) Net cash provided by operating activities 693,990 432,949 122,518 — 1,249,457 Cash flow from investing activities: Development of oil and natural gas properties — (576,256 ) (32,633 ) — (608,889 ) Purchases of other property and equipment — (48,967 ) (17,741 ) — (66,708 ) Investment in affiliates (132,332 ) — — 132,332 — Change in notes receivable with affiliate (44,600 ) — — 44,600 — Settlement of advance to affiliate — — 129,217 (129,217 ) — Proceeds from sale of properties and equipment and other (3,430 ) 349,200 22,525 — 368,295 Net cash provided by (used in) investing activities (180,362 ) (276,023 ) 101,368 47,715 (307,302 ) LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from financing activities: Proceeds from sale of units 233,427 — — — 233,427 Proceeds from borrowings 1,445,000 — — — 1,445,000 Repayments of debt (1,828,461 ) — (355,418 ) — (2,183,879 ) Distributions to unitholders (323,878 ) — — — (323,878 ) Financing fees and offering costs (26,678 ) — (1,377 ) — (28,055 ) Change in note payable with affiliate — 44,600 — (44,600 ) — Settlement of advance from affiliate — (129,217 ) — 129,217 — Capital contributions – affiliates — — 132,332 (132,332 ) — Excess tax benefit from unit-based compensation (9,467 ) — — — (9,467 ) Other (2,536 ) (72,422 ) 14 — (74,944 ) Net cash used in financing activities (512,593 ) (157,039 ) (224,449 ) (47,715 ) (941,796 ) Net increase (decrease) in cash and cash equivalents 1,035 (113 ) (563 ) — 359 Cash and cash equivalents: Beginning 38 185 1,586 — 1,809 Ending $ 1,073 $ 72 $ 1,023 $ — $ 2,168 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2014 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from operating activities: Net income (loss) $ (451,809 ) $ 5,801 $ 22,596 $ (28,397 ) $ (451,809 ) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depreciation, depletion and amortization — 771,549 302,353 — 1,073,902 Impairment of long-lived assets — 2,050,387 253,362 — 2,303,749 Unit-based compensation expenses — 53,284 — — 53,284 Amortization and write-off of deferred financing fees 38,785 17,054 (4,913 ) — 50,926 (Gains) losses on sale of assets and other, net — (372,945 ) 111,374 — (261,571 ) Equity in earnings from consolidated subsidiaries (28,397 ) — — 28,397 — Deferred income taxes — 3,874 69 — 3,943 Derivatives activities: Total gains — (1,127,395 ) (78,784 ) — (1,206,179 ) Cash settlements — 88,776 6,738 — 95,514 Cash settlements on canceled derivatives — — 12,281 — 12,281 Changes in assets and liabilities: (Increase) decrease in accounts receivable – trade, net — (11,419 ) 16,483 — 5,064 Decrease in accounts receivable – affiliates 257,485 16,950 — (274,435 ) — (Increase) decrease in other assets 312 (2,187 ) (15,949 ) — (17,824 ) Increase in accounts payable and accrued expenses — 99,003 26 — 99,029 Decrease in accounts payable and accrued expenses – affiliates — (270,690 ) (3,745 ) 274,435 — Increase (decrease) in other liabilities 14,465 (24,473 ) (38,411 ) — (48,419 ) Net cash provided by (used in) operating activities (169,159 ) 1,297,569 583,480 — 1,711,890 Cash flow from investing activities: Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired — (2,475,315 ) (3,937 ) — (2,479,252 ) Development of oil and natural gas properties — (1,061,395 ) (508,482 ) — (1,569,877 ) Purchases of other property and equipment — (63,070 ) (11,470 ) — (74,540 ) Investment in affiliates (100,921 ) — — 100,921 — Change in notes receivable with affiliate (44,300 ) — — 44,300 — Proceeds from sale of properties and equipment and other (14,117 ) 2,210,015 7,667 — 2,203,565 Net cash used in investing activities (159,338 ) (1,389,765 ) (516,222 ) 145,221 (1,920,104 ) LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from financing activities: Proceeds from borrowings 4,640,024 1,300,000 — — 5,940,024 Repayments of debt (3,305,000 ) (1,300,000 ) (206,124 ) — (4,811,124 ) Distributions to unitholders (962,048 ) — — — (962,048 ) Financing fees and offering costs (59,048 ) — (10,646 ) — (69,694 ) Change in note payable with affiliate — 44,300 — (44,300 ) — Capital contribution – affiliates — — 100,921 (100,921 ) — Excess tax benefit from unit-based compensation 810 (44 ) — — 766 Other 13,745 47,047 (864 ) — 59,928 Net cash provided by (used in) financing activities 328,483 91,303 (116,713 ) (145,221 ) 157,852 Net decrease in cash and cash equivalents (14 ) (893 ) (49,455 ) — (50,362 ) Cash and cash equivalents: Beginning 52 1,078 51,041 — 52,171 Ending $ 38 $ 185 $ 1,586 $ — $ 1,809 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2013 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from operating activities: Net loss $ (691,337 ) $ (246,926 ) $ (19,973 ) $ 266,899 $ (691,337 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion and amortization — 818,466 10,845 — 829,311 Impairment of long-lived assets — 828,317 — — 828,317 Unit-based compensation expenses — 42,703 — — 42,703 Loss on extinguishment of debt 5,304 — — — 5,304 Amortization and write-off of deferred financing fees 22,122 — (615 ) — 21,507 Losses on sale of assets and other, net — 37,232 — — 37,232 Equity in losses from consolidated subsidiaries 266,899 — — (266,899 ) — Deferred income taxes — (2,541 ) — — (2,541 ) Derivatives activities: Total (gains) losses — (182,906 ) 5,049 — (177,857 ) Cash settlements — 248,862 — — 248,862 Changes in assets and liabilities: Decrease in accounts receivable – trade, net — 17,754 71,434 — 89,188 Increase in accounts receivable – affiliates (120,967 ) (16,950 ) — 137,917 — (Increase) decrease in other assets (330 ) 5,896 10,613 — 16,179 Increase (decrease) in accounts payable and accrued expenses 178 (52,143 ) (25,028 ) — (76,993 ) Increase in accounts payable and accrued expenses – affiliates — 120,967 16,950 (137,917 ) — Increase (decrease) in other liabilities 2,092 6,842 (12,597 ) — (3,663 ) Net cash provided by (used in) operating activities (516,039 ) 1,625,573 56,678 — 1,166,212 Cash flow from investing activities: Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired — (730,326 ) 451,113 — (279,213 ) Development of oil and natural gas properties — (1,060,547 ) (17,478 ) — (1,078,025 ) Purchases of other property and equipment — (92,352 ) — — (92,352 ) Investment in affiliates 435,000 — — (435,000 ) — Change in notes receivable with affiliate (26,700 ) — — 26,700 — Proceeds from sale of properties and equipment and other (22,039 ) 218,312 — — 196,273 Net cash provided by (used in) investing activities 386,261 (1,664,913 ) 433,635 (408,300 ) (1,253,317 ) LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from financing activities: Proceeds from borrowings 2,230,000 — — — 2,230,000 Repayments of debt (1,404,898 ) — — — (1,404,898 ) Distributions to unitholders (682,241 ) — — — (682,241 ) Financing fees and offering costs (16,033 ) — — — (16,033 ) Change in note payable with affiliate — 26,700 — (26,700 ) — Capital contribution – affiliates — — (435,000 ) 435,000 — Excess tax benefit from unit-based compensation — 160 — — 160 Other 2,895 12,422 (4,272 ) — 11,045 Net cash provided by (used in) financing activities 129,723 39,282 (439,272 ) 408,300 138,033 Net increase (decrease) in cash and cash equivalents (55 ) (58 ) 51,041 — 50,928 Cash and cash equivalents: Beginning 107 1,136 — — 1,243 Ending $ 52 $ 1,078 $ 51,041 $ — $ 52,171

Supplemental Oil and Natural Ga

Supplemental Oil and Natural Gas Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Natural Gas Data (Unaudited)	The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.” Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Property acquisition costs: (1) Proved $ — $ 2,784,852 $ 3,740,379 Unproved — 788,682 1,638,302 Exploration costs 19,929 792 13,096 Development costs 430,357 1,487,204 1,153,770 Asset retirement costs 6,303 20,919 7,351 Total costs incurred $ 456,589 $ 5,082,449 $ 6,552,898 (1) See Note 2 for details about the Company’s acquisitions. Oil and Natural Gas Capitalized Costs Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below: December 31, 2015 2014 (in thousands) Proved properties: Leasehold acquisition $ 13,361,171 $ 13,362,642 Development 2,976,643 2,830,841 Unproved properties 1,783,341 1,875,417 18,121,155 18,068,900 Less accumulated depletion and amortization (11,097,492 ) (4,867,682 ) $ 7,023,663 $ 13,201,218 Results of Oil and Natural Gas Producing Activities The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Revenues and other: Oil, natural gas and natural gas liquids sales $ 1,726,271 $ 3,610,539 $ 2,073,240 Gains on oil and natural gas derivatives 1,056,189 1,206,179 177,857 2,782,460 4,816,718 2,251,097 Production costs: Lease operating expenses 617,764 805,164 372,523 Transportation expenses 219,721 207,331 128,440 Severance taxes, ad valorem taxes and California carbon allowances 181,941 267,100 139,202 1,019,426 1,279,595 640,165 Other costs: Exploration costs 9,473 125,037 5,251 Depletion and amortization 745,512 1,020,674 790,320 Impairment of long-lived assets 5,813,954 2,303,749 828,317 Gains on sale of assets and other, net (198,924 ) (388,733 ) (138 ) Texas margin tax expense (benefit) (2,789 ) 4,053 458 6,367,226 3,064,780 1,624,208 Results of operations $ (4,604,192 ) $ 472,343 $ (13,276 ) There is no federal tax provision included in the results above because the Company’s subsidiaries subject to federal tax do not own any of the Company’s oil and natural gas interests. Limited liability companies are subject to Texas margin tax. See Note 14 for additional information about income taxes. Proved Oil, Natural Gas and NGL Reserves The proved reserves of oil, natural gas and NGL of the Company have been prepared by the independent engineering firm, DeGolyer and MacNaughton. In accordance with SEC regulations, reserves at December 31, 2015, December 31, 2014, and December 31, 2013, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below: Year Ended December 31, 2015 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 4,255 341.8 166.3 7,304 Revisions of previous estimates (1,404 ) (122.2 ) (40.4 ) (2,379 ) Sales of minerals in place (13 ) (4.1 ) (2.0 ) (50 ) Extensions, discoveries and other additions 15 4.6 0.8 47 Production (234 ) (22.8 ) (10.4 ) (434 ) End of year 2,619 197.3 114.3 4,488 Proved developed reserves: Beginning of year 3,549 246.0 132.2 5,818 End of year 2,619 197.3 114.3 4,488 Proved undeveloped reserves: Beginning of year 706 95.8 34.1 1,486 End of year — — — — Year Ended December 31, 2014 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 3,010 365.6 200.0 6,403 Revisions of previous estimates 96 (22.3 ) (46.8 ) (318 ) Purchases of minerals in place 1,763 50.0 71.9 2,495 Sales of minerals in place (477 ) (51.7 ) (49.5 ) (1,084 ) Extensions, discoveries and other additions 72 26.8 2.9 250 Production (209 ) (26.6 ) (12.2 ) (442 ) End of year 4,255 341.8 166.3 7,304 Proved developed reserves: Beginning of year 2,027 252.4 133.2 4,340 End of year 3,549 246.0 132.2 5,818 Proved undeveloped reserves: Beginning of year 983 113.2 66.8 2,063 End of year 706 95.8 34.1 1,486 Year Ended December 31, 2013 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 2,571 191.5 179.4 4,796 Revisions of previous estimates (17 ) (21.3 ) (2.0 ) (157 ) Purchases of minerals in place 356 191.1 17.8 1,610 Sales of minerals in place (24 ) (5.2 ) (2.9 ) (73 ) Extensions, discoveries and other additions 286 21.7 18.5 527 Production (162 ) (12.2 ) (10.8 ) (300 ) End of year 3,010 365.6 200.0 6,403 Proved developed reserves: Beginning of year 1,661 131.4 113.0 3,127 End of year 2,027 252.4 133.2 4,340 Proved undeveloped reserves: Beginning of year 910 60.1 66.4 1,669 End of year 983 113.2 66.8 2,063 The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents using the ratio of one barrel to six Mcf. Proved reserves decreased by approximately 2,816 Bcfe to approximately 4,488 Bcfe for the year ended December 31, 2015, from 7,304 Bcfe for the year ended December 31, 2014. The year ended December 31, 2015, includes approximately 2,379 Bcfe of negative revisions of previous estimates ( 1,776 Bcfe due to lower commodity prices, 349 Bcfe due to uncertainty regarding the Company’s future commitment to capital and 302 Bcfe due to the SEC five-year development limitation on PUDs, partially offset by 48 Bcfe of positive revisions due to asset performance). During the year ended December 31, 2015, divestitures including the Howard County Assets Sale decreased proved reserves by approximately 50 Bcfe. In addition, extensions and discoveries, primarily from 584 productive wells drilled during the year, contributed approximately 47 Bcfe to the increase in proved reserves. As a result of the uncertainty regarding the Company’s future commitment to capital, the Company reclassified all of its PUDs to unproved as of December 31, 2015. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for details regarding the Company’s going concern uncertainty. The prices of oil, natural gas and NGL have continued to be volatile in 2016. In the future, if commodity prices continue to decline, the Company may have additional negative revisions which could have a material impact on its estimated quantities of oil, natural gas and NGL reserves. For information about potential risks that could affect the Company if lower commodity prices were to continue, see Item 1A. “Risk Factors.” Proved reserves increased by approximately 901 Bcfe to approximately 7,304 Bcfe for the year ended December 31, 2014, from 6,403 Bcfe for the year ended December 31, 2013. The year ended December 31, 2014, includes approximately 318 Bcfe of negative revisions of previous estimates, due primarily to 174 Bcfe of negative revisions due to ethane rejection in the Hugoton and Green River basins, 146 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs and 43 Bcfe of negative revisions due to asset performance, partially offset by 45 Bcfe of positive revisions primarily due to higher natural gas prices. During the year ended December 31, 2014, acquisitions and properties acquired in the two exchanges with Exxon XTO and ExxonMobil increased proved reserves by approximately 2,495 Bcfe and the 2014 divestitures and properties relinquished in the two exchanges with Exxon XTO and ExxonMobil decreased proved reserves by approximately 1,084 Bcfe. In addition, extensions and discoveries, primarily from 917 productive wells drilled during the year, contributed approximately 250 Bcfe to the increase in proved reserves. Proved reserves increased by approximately 1,607 Bcfe to approximately 6,403 Bcfe for the year ended December 31, 2013, from 4,796 Bcfe for the year ended December 31, 2012. The year ended December 31, 2013, includes 157 Bcfe of negative revisions of previous estimates, due primarily to 100 Bcfe of negative revisions due to asset performance, 109 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs, partially offset by 52 Bcfe of positive revisions primarily due to higher natural gas prices. During the year ended December 31, 2013, three acquisitions increased proved reserves by approximately 1,610 Bcfe and the sale of the Panther Operated Cleveland Properties decreased proved reserves by approximately 73 Bcfe. In addition, extensions and discoveries, primarily from 557 productive wells drilled during the year, contributed approximately 527 Bcfe to the increase in proved reserves. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts are not material. See Note 14 for additional information about income taxes. December 31, 2015 2014 2013 (in thousands) Future estimated revenues $ 17,293,943 $ 55,195,268 $ 51,112,346 Future estimated production costs (10,734,979 ) (24,100,468 ) (19,306,728 ) Future estimated development costs (1,107,639 ) (4,032,588 ) (5,110,896 ) Future net cash flows 5,451,325 27,062,212 26,694,722 10% annual discount for estimated timing of cash flows (2,417,780 ) (14,549,921 ) (14,795,393 ) Standardized measure of discounted future net cash flows $ 3,033,545 $ 12,512,291 $ 11,899,329 Representative NYMEX prices: (1) Natural gas (MMBtu) $ 2.59 $ 4.35 $ 3.67 Oil (Bbl) $ 50.16 $ 95.27 $ 96.89 (1) In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Year Ended December 31, 2015 2014 2013 (in thousands) Sales and transfers of oil, natural gas and NGL produced during the period $ (706,845 ) $ (2,330,944 ) $ (1,433,075 ) Changes in estimated future development costs 1,501,593 156,614 317,064 Net change in sales and transfer prices and production costs related to future production (9,309,151 ) (599,121 ) 203,370 Purchases of minerals in place — 3,021,768 5,113,335 Sales of minerals in place (97,785 ) (1,681,504 ) (139,384 ) Extensions, discoveries and improved recovery 90,090 910,787 801,254 Previously estimated development costs incurred during the period 159,248 819,987 444,861 Net change due to revisions in quantity estimates (1,633,958 ) (672,800 ) (220,224 ) Accretion of discount 1,251,229 1,189,933 607,298 Changes in production rates and other (733,167 ) (201,758 ) 131,849 $ (9,478,746 ) $ 612,962 $ 5,826,348 The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

Supplemental Quarterly Data (Un

Supplemental Quarterly Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Supplemental Quarterly Data (Unaudited)	The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.” Quarterly Financial Data Quarters Ended March 31 June 30 September 30 December 31 (in thousands, except per unit amounts) 2015: Oil, natural gas and natural gas liquids sales $ 450,569 $ 496,419 $ 427,245 $ 352,038 Gains (losses) on oil and natural gas derivatives 424,781 (191,188 ) 549,029 273,567 Total revenues and other 916,547 321,828 998,304 646,655 Total expenses (1) 1,136,442 578,586 2,790,081 3,497,486 Gains on sale of assets and other, net (12,287 ) (17,996 ) (166,980 ) (146 ) Net loss (339,160 ) (379,127 ) (1,569,317 ) (2,472,207 ) Net loss per unit: Basic $ (1.03 ) $ (1.12 ) $ (4.47 ) $ (7.05 ) Diluted $ (1.03 ) $ (1.12 ) $ (4.47 ) $ (7.05 ) Quarters Ended March 31 June 30 September 30 December 31 (in thousands, except per unit amounts) 2014: Oil, natural gas and natural gas liquids sales $ 938,877 $ 967,850 $ 937,458 $ 766,354 Gains (losses) on oil and natural gas derivatives (241,493 ) (408,788 ) 451,702 1,404,758 Total revenues and other 733,587 596,951 1,435,115 2,217,650 Total expenses (1) 674,568 664,452 1,320,157 2,533,947 (Gains) losses on sale of assets and other, net 2,586 5,467 (35,803 ) (338,750 ) Net loss (85,337 ) (207,870 ) (4,100 ) (154,502 ) Net loss per unit: Basic $ (0.27 ) $ (0.64 ) $ (0.02 ) $ (0.47 ) Diluted $ (0.27 ) $ (0.64 ) $ (0.02 ) $ (0.47 ) (1) Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.

Basis of Presentation and Sig27

Basis of Presentation and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Business	Nature of Business Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company that began operations in March 2003 and was formed as a Delaware limited liability company in April 2005. The Company completed its initial public offering in January 2006 and its units representing limited liability company interests (“units”) are listed on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “LINE.” LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. The Company’s properties are located in eight operating regions in the United States (“U.S.”): Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin), North Dakota (Williston Basin) and Colorado (Piceance Basin); California, which includes properties located in the San Joaquin Valley and Los Angeles basins; TexLa, which includes properties located in east Texas and north Louisiana; Mid-Continent, which includes properties located in the Anadarko and Arkoma basins in Oklahoma, as well as waterfloods in the Central Oklahoma Platform; Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; Permian Basin, which includes properties located in west Texas and southeast New Mexico; and South Texas. The operations of the Company are governed by the provisions of a limited liability company agreement executed by and among its members. The agreement includes specific provisions with respect to the maintenance of the capital accounts of each of the Company’s unitholders. Pursuant to applicable provisions of the Delaware Limited Liability Company Act (“Delaware Act”) and the Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC, as amended (“LLC Agreement”), unitholders have no liability for the debts, obligations and liabilities of the Company, except as expressly required in the LLC Agreement or the Delaware Act. The Company will remain in existence unless and until dissolved in accordance with the terms of the LLC Agreement.
Going Concern Uncertainty	Going Concern Uncertainty The Company’s liquidity outlook has changed since the third quarter of 2015 due to continued low commodity prices, which are expected to result in significantly lower levels of cash flow from operating activities in the future as the Company’s current commodity derivative contracts expire, and have limited the Company’s ability to access the capital markets. In addition, each of the Company’s Credit Facilities is subject to scheduled redeterminations of its borrowing base, semi-annually in April and October, based primarily on reserve reports using lender commodity price expectations at such time. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs, along with the maturity schedule of the Company’s hedges, are expected to adversely impact the upcoming April redeterminations and will likely have a significant negative impact on the Company’s liquidity. As a result of these and other factors, the following issues have adversely impacted the Company’s ability to continue as a going concern: • the Company’s ability to comply with financial covenants and ratios in its Credit Facilities and indentures has been affected by continued low commodity prices. Absent a waiver or amendment, failure to meet these covenants and ratios would result in a default and, to the extent the applicable lenders so elect, an acceleration of the Company’s existing indebtedness, causing such debt of approximately $3.6 billion to be immediately due and payable. Based on the Company’s current estimates and expectations for commodity prices in 2016, the Company does not expect to remain in compliance with all of the restrictive covenants contained in its Credit Facilities throughout 2016 unless those requirements are waived or amended. The Company does not currently have adequate liquidity to repay all of its outstanding debt in full if such debt were accelerated; • because the Credit Facilities are effectively fully drawn, any reduction of the borrowing bases under the Company’s Credit Facilities would require mandatory prepayments to the extent existing indebtedness exceeds the new borrowing bases. The Company may not have sufficient cash on hand to be able to make any such mandatory prepayments; and • the Company’s ability to make interest payments as they become due and repay indebtedness upon maturities (whether under existing terms or as a result of acceleration) is impacted by the Company’s liquidity. As of February 29, 2016, there was less than $1 million of available borrowing capacity under the Credit Facilities. The Company’s Credit Facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception. Consequently, as of the filing date, March 15, 2016, the Company is in default under the LINN Credit Facility. If the Company is unable to obtain a waiver or other suitable relief from the lenders under the LINN Credit Facility prior to the expiration of the 30 day grace period, an Event of Default (as defined in the applicable agreements) will result and the lenders holding a majority of the commitments under the LINN Credit Facility could accelerate the outstanding indebtedness, which would make it immediately due and payable. If the Company is unable to obtain a waiver from or otherwise reach an agreement with the lenders under the LINN Credit Facility and the indebtedness under the LINN Credit Facility is accelerated, then an Event of Default under LINN Energy’s senior notes and second lien notes would occur, which, if it continues beyond any applicable cure periods, would, to the extent the applicable lenders so elect, result in the acceleration of those obligations. Furthermore, an Event of Default under the LINN Credit Facility will also result in an Event of Default under the Berry Credit Facility, which in the absence of a waiver or other suitable relief and upon the election of the agent or lenders holding a majority of commitments under the Berry Credit Facility would result in the acceleration of indebtedness under the Berry Credit Facility. Such Event of Default would trigger an Event of Default under the Berry senior notes. If such Event of Default continues beyond any applicable cure periods, such Event of Default would result in an acceleration of the Berry senior notes. Additionally, the indenture governing the second lien notes (“Second Lien Indenture”) required the Company to deliver mortgages by February 18, 2016, subject to a 45 day grace period. The Company elected to exercise its right to the grace period and not deliver the mortgages, and as a result, the Company is currently in default under the Second Lien Indenture. If the Company does not deliver the mortgages within the 45 day grace period or is otherwise unable to obtain a waiver or other suitable relief from the holders under the Second Lien Indenture prior to the expiration of the 45 day grace period, an Event of Default (as defined in the Second Lien Indenture) will result and if the trustee or noteholders holding at least 25% in the aggregate outstanding principal amount of the second lien notes so elect would accelerate the second lien notes causing them to be immediately due and payable. Furthermore, the Company has decided to defer making interest payments totaling approximately $60 million due March 15, 2016, including approximately $30 million on LINN Energy’s 7.75% senior notes due February 2021, approximately $12 million on LINN Energy’s 6.50% senior notes due September 2021 and approximately $18 million on Berry’s senior notes due September 2022, which will result in the Company being in default under these senior notes. The indentures governing each of the applicable series of notes permit the Company a 30 day grace period to make the interest payments. If the Company fails to make the interest payments within the grace period, or is otherwise unable to obtain a waiver or suitable relief from the holders of these senior notes, an Event of Default will result and if the trustee or noteholders holding at least 25% in the aggregate outstanding principal amount of each series of notes so elect would accelerate the notes causing them to be immediately due and payable. An Event of Default under the Second Lien Indenture or any of the indentures governing the senior notes triggers a cross-default under the LINN Credit Facility and Berry Credit Facility and, as discussed above, if the applicable lenders so elect would result in acceleration under the LINN Credit Facility and Berry Credit Facility. In addition, as discussed above, an acceleration of the obligations under the Second Lien Indenture or LINN Credit Facility would trigger a cross-default to LINN Energy’s senior notes and if the applicable lenders so elect would result in a cross-acceleration under LINN Energy’s senior notes, and an acceleration of the Berry Credit Facility if the applicable lenders so elect would result in cross-acceleration under the Berry senior notes. See Note 6 for additional details about the Company’s debt. If lenders, and subsequently noteholders, accelerate the Company’s outstanding indebtedness (approximately $9.0 billion as of December 31, 2015 ), it will become immediately due and payable and the Company will not have sufficient liquidity to repay those amounts. If the Company is unable to reach an agreement with its creditors prior to any of the above described accelerations, the Company could be required to immediately file for protection under Chapter 11 of the U.S. Bankruptcy Code. The significant risks and uncertainties described above raise substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. The Company is currently in discussions with various stakeholders and is pursuing or considering a number of actions including: (i) obtaining additional sources of capital from asset sales, private issuances of equity or equity-linked securities, debt for equity swaps, or any combination thereof; (ii) pursuing in- and out-of-court restructuring transactions; (iii) obtaining waivers or amendments from its lenders; and (iv) continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations. There can be no assurance that sufficient liquidity can be obtained from one or more of these actions or that these actions can be consummated within the period needed.
Principles of Consolidation and Reporting	Principles of Consolidation and Reporting The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss), unitholders’ capital (deficit) or cash flows.
Use of Estimates	Use of Estimates The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In November 2015, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to simplify the presentation of deferred taxes by requiring that all deferred taxes be presented as noncurrent. This ASU will be applied either prospectively or retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2016, and interim periods within those years (early adoption permitted). Adoption of this ASU is expected to result in a decrease in the Company’s current assets or current liabilities on its consolidated balance sheets, depending on its deferred taxes classification at such date, with no impact to the consolidated statements of operations. In April 2015, the FASB issued an ASU that is intended to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2015, and interim periods within those years (early adoption permitted). Adoption of this ASU is expected to result in a decrease to the Company’s assets and liabilities in its consolidated balance sheets, with no impact to the consolidated statements of operations. In August 2014, the FASB issued an ASU that provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter (early adoption permitted). The Company does not expect the adoption of this ASU to have a material impact on its financial statements or related disclosures. In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU will be applied either retrospectively or as a cumulative-effect adjustment as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those years (early adoption permitted for fiscal years beginning after December 15, 2016, including interim periods within that year). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.
Cash Equivalents	Cash Equivalents For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows.
Accounts Receivable - Trade, Net	Accounts Receivable – Trade, Net Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million at both December 31, 2015 , and December 31, 2014 .
Inventories	Inventories Materials, supplies and commodity inventories are valued at the lower of average cost or market. Inventories also include California carbon allowance instruments.
Oil and Natural Gas Properties	Oil and Natural Gas Properties Proved Properties The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $5 million , $9 million and $2 million for the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , respectively. The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. 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 underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Based on the analysis described above, the Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties: Year Ended December 31, 2015 2014 2013 (in thousands) Rockies region $ 1,758,939 $ 585,705 $ — Hugoton Basin region 1,667,768 — — California region 537,511 22 — TexLa region 430,859 4,836 — Mid-Continent region 405,370 244,413 828,317 Permian Basin region 71,990 1,337,444 — South Texas region 42,433 131,329 — $ 4,914,870 $ 2,303,749 $ 828,317 The impairment charges in 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The impairment charges in 2014 include approximately $1.7 billion due to a steep decline in commodity prices during the fourth quarter of 2014 and approximately $603 million due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for proved oil and natural gas properties. The impairment charges in 2013 include approximately $791 million associated with properties in the Granite Wash formation related to asset performance resulting in reserve revisions and a decline in commodity prices as well as approximately $37 million associated with the write-down of the carrying value of the Panther Operated Cleveland Properties sold in May 2013 (see Note 2). The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. Subsequent to December 31, 2015, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results of operations. Unproved Properties Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past. The Company recorded the following noncash impairment charges (before and after tax) associated with unproved oil and natural gas properties: Year Ended December 31, 2015 (in thousands) TexLa region $ 416,846 Permian Basin region 226,922 Rockies region 184,137 California region 71,179 $ 899,084 The Company recorded no impairment charges for unproved properties for the years ended December 31, 2014, or December 31, 2013. The impairment charges in 2015 were due to a decline in commodity prices and changes in expected capital development. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statement of operations. Exploration Costs Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $2 million , $125 million and $5 million for the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , respectively, which are included in “exploration costs” on the consolidated statements of operations.
Oil and Natural Gas Properties	Oil and Natural Gas Properties Proved Properties The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $5 million , $9 million and $2 million for the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , respectively.
Impairment of Oil and Natural Gas Properties	The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. 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 underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Based on the analysis described above, the Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties: Year Ended December 31, 2015 2014 2013 (in thousands) Rockies region $ 1,758,939 $ 585,705 $ — Hugoton Basin region 1,667,768 — — California region 537,511 22 — TexLa region 430,859 4,836 — Mid-Continent region 405,370 244,413 828,317 Permian Basin region 71,990 1,337,444 — South Texas region 42,433 131,329 — $ 4,914,870 $ 2,303,749 $ 828,317 The impairment charges in 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The impairment charges in 2014 include approximately $1.7 billion due to a steep decline in commodity prices during the fourth quarter of 2014 and approximately $603 million due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for proved oil and natural gas properties. The impairment charges in 2013 include approximately $791 million associated with properties in the Granite Wash formation related to asset performance resulting in reserve revisions and a decline in commodity prices as well as approximately $37 million associated with the write-down of the carrying value of the Panther Operated Cleveland Properties sold in May 2013 (see Note 2). The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. Subsequent to December 31, 2015, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results of operations. Unproved Properties Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past. The Company recorded the following noncash impairment charges (before and after tax) associated with unproved oil and natural gas properties: Year Ended December 31, 2015 (in thousands) TexLa region $ 416,846 Permian Basin region 226,922 Rockies region 184,137 California region 71,179 $ 899,084 The Company recorded no impairment charges for unproved properties for the years ended December 31, 2014, or December 31, 2013. The impairment charges in 2015 were due to a decline in commodity prices and changes in expected capital development. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statement of operations.
Unproved Properties Disclosure [Table Text Block]	Unproved Properties Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past. The Company recorded the following noncash impairment charges (before and after tax) associated with unproved oil and natural gas properties: Year Ended December 31, 2015 (in thousands) TexLa region $ 416,846 Permian Basin region 226,922 Rockies region 184,137 California region 71,179 $ 899,084 The Company recorded no impairment charges for unproved properties for the years ended December 31, 2014, or December 31, 2013. The impairment charges in 2015 were due to a decline in commodity prices and changes in expected capital development. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statement of operations.
Other Property and Equipment	Other Property and Equipment Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from two to 39 years for the individual asset or group of assets.
Revenue Recognition	Revenue Recognition Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. Imbalance receivables and payables are valued at the lower of the price in effect at the time of production, the current market value or, if a contract is in hand, the contract price. At December 31, 2015 , and December 31, 2014 , the Company had natural gas production imbalance receivables of approximately $13 million and $17 million , respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets. At December 31, 2015 , and December 31, 2014 , the Company had natural gas production imbalance payables of approximately $11 million and $13 million , respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets. The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses. The Company generates electricity with excess natural gas, which it uses to serve certain of its operating facilities in California. Any excess electricity is sold to the California wholesale power market. The revenue from this activity is included in “other revenues” on the consolidated statements of operations.
Restricted Cash	Restricted Cash At December 31, 2015 , “restricted cash” on the consolidated balance sheet includes $250 million that LINN Energy borrowed under the LINN Credit Facility and contributed to Berry Petroleum Company, LLC (“Berry”) in May 2015 to post with Berry’s lenders in connection with the reduction in the Berry Credit Facility’s borrowing base. See Note 6 for additional details. Restricted cash also includes approximately $7 million and $6 million at December 31, 2015 , and December 31, 2014 , respectively, of cash deposited by the Company into a separate account designated for asset retirement obligations in accordance with contractual agreements.
Derivative Instruments	Derivative Instruments The Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials. By removing a portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices. The Company maintains a substantial portion of its hedges in the form of swap contracts. From time to time, the Company has chosen to purchase put option contracts to hedge volumes in excess of those already hedged with swap contracts. In 2013, the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. The Company does not enter into derivative contracts for trading purposes. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price. Derivative instruments are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads are applied to the Company’s commodity derivatives. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments. The Company may from time to time enter into derivative contracts in the form of interest rate swaps to minimize the effects of fluctuations in interest rates. At December 31, 2015 , the Company had no outstanding derivative contracts in the form of interest rate swaps.
Unit-Based Compensation	Unit-Based Compensation The Company recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based awards granted to employees and nonemployee directors. The fair value of unit-based awards, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. See Note 5 for additional details about the Company’s accounting for unit-based compensation. The benefit of tax deductions in excess of recognized compensation costs is required to be reported as financing cash flow rather than operating cash flow. This requirement reduces net operating cash flow and increases net financing cash flow in periods in which such tax benefit exists. The amount of the Company’s excess tax benefit is also reported in “excess tax benefit from unit-based compensation and other” on the consolidated statements of unitholders’ capital (deficit).
Deferred Financing Fees	Deferred Financing Fees The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2015 , net deferred financing fees of approximately $35 million are included in “other current assets” and approximately $36 million are included in “other noncurrent assets” on the consolidated balance sheet. At December 31, 2014 , net deferred financing fees of approximately $129 million are included in “other noncurrent assets” on the consolidated balance sheet. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense. For the years ended December 31, 2015 , December 31, 2014 , and December 31, 2013 , amortization expense of approximately $23 million , $46 million and $18 million , respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations. For the year ended December 31, 2015 , approximately $10 million were written off to expense and included in “other, net” on the consolidated statement of operations related to amendments of the Credit Facilities (as defined in Note 6). For the year ended December 31, 2014 , approximately $8 million were written off to expense and included in “other, net” on the consolidated statement of operations related to the term loan that was repaid and the Credit Facilities that were amended in 2014. No fees related to amendments of the Credit Facilities were written off to expense during the year ended December 31, 2013 .
Fair Value of Financial Instruments	Fair Value of Financial Instruments The carrying values of the Company’s receivables, payables an d Credit Facilities are estimated to be substantially the same as their fair values at December 31, 2015 , and December 31, 2014 . See Note 6 for fair value disclosures related to the Company’s other outstanding debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments.
Income Taxes	Income Taxes The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes, which are accounted for using the asset and liability method. 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. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and tax carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 14 for details of amounts recorded in the consolidated financial statements.

Basis of Presentation and Sig28

Basis of Presentation and Significant Accounting Policies Tables (Tables)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Impairment of Proved Oil and Natural Gas Properties	Based on the analysis described above, the Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties: Year Ended December 31, 2015 2014 2013 (in thousands) Rockies region $ 1,758,939 $ 585,705 $ — Hugoton Basin region 1,667,768 — — California region 537,511 22 — TexLa region 430,859 4,836 — Mid-Continent region 405,370 244,413 828,317 Permian Basin region 71,990 1,337,444 — South Texas region 42,433 131,329 — $ 4,914,870 $ 2,303,749 $ 828,317
Impairment of Unproved Oil and Natural Gas Properties	The Company recorded the following noncash impairment charges (before and after tax) associated with unproved oil and natural gas properties: Year Ended December 31, 2015 (in thousands) TexLa region $ 416,846 Permian Basin region 226,922 Rockies region 184,137 California region 71,179 $ 899,084

Divestitures, Exchanges of Pr29

Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Schedule of Pro Forma Results of Operations	The pro forma financial information does not give effect to the costs of any integration activities or benefits that may result from the realization of future cost savings from operating efficiencies, or any other synergies that may result from the transaction. Year Ended December 31, 2014 (in thousands, except per unit amounts) Total revenues and other $ 5,335,442 Total operating expenses $ (5,039,279 ) Net loss $ (403,415 ) Net loss per unit: Basic $ (1.25 ) Diluted $ (1.25 ) The pro forma condensed combined results of operations includes adjustments to: • Reflect the results of the Devon Assets Acquisition. • Reflect incremental depreciation, depletion and amortization expense, using the unit-of-production method related to oil and natural gas properties acquired and an estimated useful life of 10 years for other property and equipment. • Reflect incremental accretion expense related to asset retirement obligations on oil and natural gas properties acquired. • Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price. • Reflect incremental amortization of deferred financing fees associated with debt incurred to fund the purchase price. • Exclude transaction costs related to the Devon Assets Acquisition included in the historical statements of operations as they reflect nonrecurring charges not expected to have a continuing impact on the combined results.

Unit-Based Compensation and O30

Unit-Based Compensation and Other Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Unit Based Compensation and Other Benefit Plans [Abstract]
Employee Service Share-Based Compensation Expense	A summary of unit-based compensation expenses included in the consolidated statements of operations is presented below: Year Ended December 31, 2015 2014 2013 (in thousands) General and administrative expenses $ 47,312 $ 45,195 $ 37,375 Lease operating expenses 8,824 8,089 5,328 Total unit-based compensation expenses $ 56,136 $ 53,284 $ 42,703 Income tax benefit $ 20,742 $ 19,688 $ 15,779
Nonvested Units	As of December 31, 2015 , a summary of the status of the nonvested units is presented below: Number of Nonvested Units Weighted Average Grant-Date Per Unit Nonvested units at December 31, 2014 2,838,973 $ 32.70 Granted 4,576,631 $ 10.21 Vested (1,870,384 ) $ 26.41 Forfeited (618,648 ) $ 16.65 Nonvested units at December 31, 2015 4,926,572 $ 16.22
Unit Options Activity	The following provides information related to unit option activity for the year ended December 31, 2015: Number of Units Underlying Options Weighted Average Exercise Price Per Unit Weighted Average Remaining Contractual Life in Years Aggregate Intrinsic Value Outstanding at December 31, 2014 5,444,417 $ 31.95 5.12 $ — Forfeited or expired (4,619,706 ) $ 33.60 Outstanding at December 31, 2015 824,711 $ 22.72 2.27 $ — Exercisable at December 31, 2015 821,787 $ 22.69 2.25 $ —
Valuation Assumptions	The fair values of the Company’s unit option grants were based upon the following assumptions: 2013 (1) Expected volatility 29.65% – 50.88% Expected distributions 9.84% Risk-free rate 0.13% – 1.55% Expected term 0.68 years – 5 years (1) All unit options granted in 2013 were replacement awards issued in exchange for options assumed in the Berry acquisition.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Summary of Outstanding Debt	The following summarizes the Company’s outstanding debt: December 31, 2015 2014 (in thousands, except percentages) LINN credit facility (1) $ 2,215,000 $ 1,795,000 Berry credit facility (2) 873,175 1,173,175 Term loan (3) 500,000 500,000 6.50% senior notes due May 2019 562,234 1,200,000 6.25% senior notes due November 2019 581,402 1,800,000 8.625% senior notes due April 2020 718,596 1,300,000 6.75% Berry senior notes due November 2020 261,100 299,970 12.00% senior secured second lien notes due December 2020 (4) 1,000,000 — Interest payable on second lien notes due December 2020 (4) 608,333 — 7.75% senior notes due February 2021 779,474 1,000,000 6.50% senior notes due September 2021 381,423 650,000 6.375% Berry senior notes due September 2022 572,700 599,163 Net unamortized discounts and premiums (8,694 ) (21,499 ) Total debt, net 9,044,743 10,295,809 Less current portion (5) (3,716,508 ) — Total long-term debt, net $ 5,328,235 $ 10,295,809 (1) Variable interest rates of 2.66% and 1.92% at December 31, 2015 , and December 31, 2014 , respectively. (2) Variable interest rates of 3.17% and 2.67% at December 31, 2015 , and December 31, 2014 , respectively. (3) Variable interest rates of 3.17% and 2.66% at December 31, 2015 and December 31, 2014 , respectively. (4) In November 2015, the Company issued $1.0 billion in aggregate principal amount of new 12.00% senior secured second lien notes due December 2020 in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes. See below for additional details. (5) Due to existing and anticipated covenant violations, the Company’s Credit Facilities and term loan were classified as current at December 31, 2015. The current portion also includes approximately $128 million of interest payable on the Second Lien Notes due within one year.
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	December 31, 2015 December 31, 2014 Carrying Value Fair Value Carrying Value Fair Value (in thousands) Credit facilities $ 3,088,175 $ 3,088,175 $ 2,968,175 $ 2,968,175 Term loan 500,000 500,000 500,000 500,000 Senior secured second lien notes 1,000,000 501,250 — — Interest payable on second lien notes 608,333 608,333 — — Senior notes, net 3,848,235 662,179 6,827,634 5,703,649 Total debt, net $ 9,044,743 $ 5,359,937 $ 10,295,809 $ 9,171,824
Schedule of Senior Notes Exchanged	On November 20, 2015, the Company issued $1.0 billion in aggregate principal amount of 12.00% senior secured second lien notes due December 2020 (“Second Lien Notes”) in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes as follows (in thousands): Par Value of Senior Notes Exchanged 6.50% senior notes due May 2019 $ 584,422 6.25% senior notes due November 2019 824,348 8.625% senior notes due April 2020 286,344 7.75% senior notes due February 2021 184,300 6.50% senior notes due September 2021 120,586 $ 2,000,000
Debt Instrument Redemption Prices	On and after December 15, 2018, the Company has the option to redeem all or part of the Second Lien Notes, upon not less than 30 or more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest and Additional Interest, if any, to the redemption date, if redeemed during the twelve-month period beginning on December 15 of the years indicated below: Percentage 2018 112.000 % 2019 and thereafter 106.000 %

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	The following table presents derivative positions for the periods indicated as of December 31, 2015 : 2016 2017 2018 Natural gas positions: Fixed price swaps (NYMEX Henry Hub): Hedged volume (MMMBtu) 121,841 120,122 36,500 Average price ($/MMBtu) $ 4.20 $ 4.26 $ 5.00 Put options (NYMEX Henry Hub): Hedged volume (MMMBtu) 76,269 66,886 — Average price ($/MMBtu) $ 5.00 $ 4.88 $ — Oil positions: Fixed price swaps (NYMEX WTI): (1) Hedged volume (MBbls) 11,465 4,755 — Average price ($/Bbl) $ 90.56 $ 89.02 $ — Put options (NYMEX WTI): Hedged volume (MBbls) 3,271 384 — Average price ($/Bbl) $ 90.00 $ 90.00 $ — Natural gas basis differential positions: (2) Panhandle basis swaps: (3) Hedged volume (MMMBtu) 59,954 59,138 16,425 Hedged differential ($/MMBtu) $ (0.32 ) $ (0.33 ) $ (0.33 ) 2016 2017 2018 NWPL Rockies basis swaps: (3) Hedged volume (MMMBtu) 65,794 38,880 10,804 Hedged differential ($/MMBtu) $ (0.24 ) $ (0.19 ) $ (0.19 ) MichCon basis swaps: (3) Hedged volume (MMMBtu) 7,768 7,437 2,044 Hedged differential ($/MMBtu) $ 0.05 $ 0.05 $ 0.05 Houston Ship Channel basis swaps: (3) Hedged volume (MMMBtu) 34,364 36,730 986 Hedged differential ($/MMBtu) $ (0.02 ) $ (0.02 ) $ (0.08 ) Permian basis swaps: (3) Hedged volume (MMMBtu) 2,975 2,629 1,314 Hedged differential ($/MMBtu) $ (0.20 ) $ (0.20 ) $ (0.20 ) SoCal basis swaps: (4) Hedged volume (MMMBtu) 32,940 — — Hedged differential ($/MMBtu) $ (0.03 ) $ — $ — Oil timing differential positions: Trade month roll swaps (NYMEX WTI): (5) Hedged volume (MBbls) 2,652 2,654 — Hedged differential ($/Bbl) $ 0.25 $ 0.25 $ — (1) Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for the year ending December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, at counterparty election on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years. (2) Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price. (3) For positions which hedge exposure to differentials in producing areas, the Company receives the NYMEX Henry Hub natural gas price plus the respective spread and pays the specified index price. Cash settlements are made on a net basis. (4) For positions which hedge exposure to differentials in consuming areas, the Company pays the NYMEX Henry Hub natural gas price plus the respective spread and receives the specified index price. Cash settlements are made on a net basis. (5) The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).
Fair Value of Derivatives Outstanding on a Gross Basis by Location on the Balance Sheet	The following table summarizes the fair value of derivatives outstanding on a gross basis: December 31, 2015 2014 (in thousands) Assets: Commodity derivatives $ 1,812,375 $ 2,014,815 Liabilities: Commodity derivatives $ 28,842 $ 90,260
Derivative Instruments, Gain (Loss)	A summary of gains and losses on derivatives included on the consolidated statements of operations is presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Gains on oil and natural gas derivatives $ 1,056,189 $ 1,206,179 $ 177,857 Lease operating expenses (1) 6,893 — — Total gains on oil and natural gas derivatives $ 1,063,082 $ 1,206,179 $ 177,857 (1) Consists of gains and (losses) on derivatives used to hedge exposure to differentials in consuming areas, which were entered into in March 2015.

Fair Value Measurements on a 33

Fair Value Measurements on a Recurring Basis (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements on a Recurring Basis	The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis: December 31, 2015 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 1,812,375 $ (25,744 ) $ 1,786,631 Liabilities: Commodity derivatives $ 28,842 $ (25,744 ) $ 3,098 December 31, 2014 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 2,014,815 $ (89,576 ) $ 1,925,239 Liabilities: Commodity derivatives $ 90,260 $ (89,576 ) $ 684 (1) Represents counterparty netting under agreements governing such derivatives.

Other Property and Equipment (T

Other Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Other Property and Equipment	Other property and equipment consists of the following: December 31, 2015 2014 (in thousands) Natural gas plant and pipeline $ 480,161 $ 479,754 Furniture and office equipment 106,462 88,893 Buildings and leasehold improvements 72,976 49,046 Vehicles 37,641 36,534 Drilling and other equipment 7,934 6,994 Land 3,537 7,928 708,711 669,149 Less accumulated depreciation (195,661 ) (144,282 ) $ 513,050 $ 524,867

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations Reconciliation	The following table presents a reconciliation of the Company’s asset retirement obligations: December 31, 2015 2014 (in thousands) Asset retirement obligations at beginning of year $ 497,570 $ 289,321 Liabilities added from acquisitions — 176,538 Liabilities added from drilling 3,574 10,476 Liabilities associated with assets divested (3,306 ) (25,656 ) Current year accretion expense 30,016 22,164 Settlements (6,336 ) (12,620 ) Revision of estimates 2,023 37,347 Asset retirement obligations at end of year $ 523,541 $ 497,570

Operating Leases (Tables)

Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2015
Leases, Operating [Abstract]
Future Minimum Lease Payments	As of December 31, 2015 , future minimum lease payments were as follows (in thousands): 2016 $ 10,647 2017 8,887 2018 7,521 2019 7,865 2020 7,721 Thereafter 27,336 $ 69,977

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation	The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net loss: Year Ended December 31, 2015 2014 2013 (in thousands, except per unit data) Net loss $ (4,759,811 ) $ (451,809 ) $ (691,337 ) Allocated to participating securities (3,039 ) (7,117 ) (5,935 ) $ (4,762,850 ) $ (458,926 ) $ (697,272 ) Basic net loss per unit $ (13.87 ) $ (1.40 ) $ (2.94 ) Diluted net loss per unit $ (13.87 ) $ (1.40 ) $ (2.94 ) Basic weighted average units outstanding 343,323 328,918 237,544 Dilutive effect of unit equivalents — — — Diluted weighted average units outstanding 343,323 328,918 237,544

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Components of income tax expense (benefit)	Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Income tax expense (benefit) consisted of the following: Year Ended December 31, 2015 2014 2013 (in thousands) Current taxes: Federal $ (12,021 ) $ 473 $ 144 State 1,022 21 198 Deferred taxes: Federal 8,237 (104 ) (2,805 ) State (3,699 ) 4,047 264 $ (6,461 ) $ 4,437 $ (2,199 )
Effective income tax rate reconciliation	A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Year Ended December 31, 2015 2014 2013 Federal statutory rate 35.0 % 35.0 % 35.0 % State, net of federal tax benefit 0.1 (0.9 ) (0.1 ) Loss excluded from nontaxable entities (34.8 ) (34.6 ) (34.6 ) Other (0.2 ) (0.5 ) — Effective rate 0.1 % (1.0 )% 0.3 %
Significant components of the deferred tax assets and liabilities	Significant components of the deferred tax assets and liabilities were as follows: December 31, 2015 2014 (in thousands) Deferred tax assets: Net operating loss carryforwards $ 370 $ — Unit-based compensation 18,214 22,105 Valuation allowance (2,159 ) — Other 7,300 6,857 Total deferred tax assets 23,725 28,962 Deferred tax liabilities: Property and equipment principally due to differences in depreciation (12,534 ) (10,991 ) Other 8 (6,370 ) Total deferred tax liabilities (12,526 ) (17,361 ) Net deferred tax assets $ 11,199 $ 11,601
Classification of net deferred tax assets and liabilities in consolidated balance sheets	Net deferred tax assets and liabilities were classified on the consolidated balance sheets as follows: December 31, 2015 2014 (in thousands) Deferred tax assets $ 23,188 $ 28,442 Deferred tax liabilities (675 ) (2,964 ) Other current assets $ 22,513 $ 25,478 Deferred tax assets $ 537 $ 520 Deferred tax liabilities (11,851 ) (14,397 ) Other noncurrent liabilities $ (11,314 ) $ (13,877 )

Supplemental Disclosures to t39

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2015
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Other Accrued Liabilities	“Other accrued liabilities” reported on the consolidated balance sheets include the following: December 31, 2015 2014 (in thousands) Accrued interest $ 63,957 $ 105,310 Accrued compensation 37,061 44,875 Asset retirement obligations 14,234 16,187 Other 4,341 1,364 $ 119,593 $ 167,736
Supplemental Cash Flow Disclosures	Supplemental disclosures to the consolidated statements of cash flows are presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Cash payments for interest, net of amounts capitalized $ 562,303 $ 542,775 $ 392,607 Cash payments for income taxes $ 643 $ — $ 14 Noncash investing and financing activities: In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follow: Fair value of assets acquired $ — $ 2,679,547 $ 5,726,681 Cash paid, net of cash acquired — (2,395,339 ) (109,350 ) Units issued in connection with the Berry acquisition — — (2,781,888 ) Noncash gains on exchanges of properties — (85,493 ) — Receivables from sellers — 16,213 (93 ) Payables to sellers — (3,515 ) (6,854 ) Liabilities assumed $ — $ 211,413 $ 2,828,496 Accrued capital expenditures $ 81,656 $ 240,331 $ 334,542

Subsidiary Guarantors (Tables)

Subsidiary Guarantors (Tables)	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheets	CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2015 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) ASSETS Current assets: Cash and cash equivalents $ 1,073 $ 72 $ 1,023 $ — $ 2,168 Accounts receivable – trade, net — 170,503 46,053 — 216,556 Accounts receivable – affiliates 2,920,082 8,621 — (2,928,703 ) — Derivative instruments — 1,207,012 13,218 — 1,220,230 Other current assets 26,905 72,120 20,897 (1 ) 119,921 Total current assets 2,948,060 1,458,328 81,191 (2,928,704 ) 1,558,875 Noncurrent assets: Oil and natural gas properties (successful efforts method) — 13,110,094 5,011,061 — 18,121,155 Less accumulated depletion and amortization — (9,557,283 ) (1,596,165 ) 55,956 (11,097,492 ) — 3,552,811 3,414,896 55,956 7,023,663 Other property and equipment — 597,216 111,495 — 708,711 Less accumulated depreciation — (183,139 ) (12,522 ) — (195,661 ) — 414,077 98,973 — 513,050 Derivative instruments — 566,401 — — 566,401 Restricted cash — 7,004 250,359 — 257,363 Notes receivable – affiliates 175,100 — — (175,100 ) — Investments in consolidated subsidiaries 3,940,444 — — (3,940,444 ) — Other noncurrent assets 35,559 5,978 16,057 — 57,594 4,151,103 579,383 266,416 (4,115,544 ) 881,358 Total noncurrent assets 4,151,103 4,546,271 3,780,285 (4,059,588 ) 8,418,071 Total assets $ 7,099,163 $ 6,004,599 $ 3,861,476 $ (6,988,292 ) $ 9,976,946 LIABILITIES AND UNITHOLDERS’ CAPITAL (DEFICIT) Current liabilities: Accounts payable and accrued expenses $ 1,285 $ 336,962 $ 117,127 $ — $ 455,374 Accounts payable – affiliates — 2,920,082 8,621 (2,928,703 ) — Derivative instruments — — 2,241 — 2,241 Current portion of long-term debt 2,843,333 — 873,175 — 3,716,508 Other accrued liabilities 49,861 52,997 16,736 (1 ) 119,593 Total current liabilities 2,894,479 3,310,041 1,017,900 (2,928,704 ) 4,293,716 Noncurrent liabilities: Derivative instruments — 857 — — 857 Long-term debt, net 4,482,867 — 845,368 — 5,328,235 Notes payable – affiliates — 175,100 — (175,100 ) — Other noncurrent liabilities — 410,990 212,049 — 623,039 Total noncurrent liabilities 4,482,867 586,947 1,057,417 (175,100 ) 5,952,131 Unitholders’ capital (deficit): Units issued and outstanding 5,333,834 4,831,758 2,798,713 (7,621,189 ) 5,343,116 Accumulated deficit (5,612,017 ) (2,724,147 ) (1,012,554 ) 3,736,701 (5,612,017 ) (278,183 ) 2,107,611 1,786,159 (3,884,488 ) (268,901 ) Total liabilities and unitholders’ capital (deficit) $ 7,099,163 $ 6,004,599 $ 3,861,476 $ (6,988,292 ) $ 9,976,946 CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2014 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) ASSETS Current assets: Cash and cash equivalents $ 38 $ 185 $ 1,586 $ — $ 1,809 Accounts receivable – trade, net — 371,325 100,359 — 471,684 Accounts receivable – affiliates 4,028,890 13,205 — (4,042,095 ) — Derivative instruments — 1,033,448 43,694 — 1,077,142 Other current assets 18 96,678 59,259 — 155,955 Total current assets 4,028,946 1,514,841 204,898 (4,042,095 ) 1,706,590 Noncurrent assets: Oil and natural gas properties (successful efforts method) — 13,196,841 4,872,059 — 18,068,900 Less accumulated depletion and amortization — (4,342,675 ) (525,007 ) — (4,867,682 ) — 8,854,166 4,347,052 — 13,201,218 Other property and equipment — 553,150 115,999 — 669,149 Less accumulated depreciation — (135,830 ) (8,452 ) — (144,282 ) — 417,320 107,547 — 524,867 Derivative instruments — 848,097 — — 848,097 Restricted cash — 6,100 125 — 6,225 Notes receivable – affiliates 130,500 — — (130,500 ) — Advance to affiliate — — 293,627 (293,627 ) — Investments in consolidated subsidiaries 8,562,608 — — (8,562,608 ) — Other noncurrent assets 116,637 5,716 14,159 — 136,512 8,809,745 859,913 307,911 (8,986,735 ) 990,834 Total noncurrent assets 8,809,745 10,131,399 4,762,510 (8,986,735 ) 14,716,919 Total assets $ 12,838,691 $ 11,646,240 $ 4,967,408 $ (13,028,830 ) $ 16,423,509 LIABILITIES AND UNITHOLDERS’ CAPITAL Current liabilities: Accounts payable and accrued expenses $ 3,784 $ 581,880 $ 229,145 $ — $ 814,809 Accounts payable – affiliates — 4,028,890 13,205 (4,042,095 ) — Advance from affiliate — 293,627 — (293,627 ) — Other accrued liabilities 89,507 59,142 19,087 — 167,736 Total current liabilities 93,291 4,963,539 261,437 (4,335,722 ) 982,545 Noncurrent liabilities: Long-term debt, net 8,208,857 — 2,086,952 — 10,295,809 Notes payable – affiliates — 130,500 — (130,500 ) — Derivative instruments — 684 — — 684 Other noncurrent liabilities — 400,851 200,015 — 600,866 Total noncurrent liabilities 8,208,857 532,035 2,286,967 (130,500 ) 10,897,359 Unitholders’ capital: Units issued and outstanding 5,388,749 4,831,339 2,416,381 (7,240,658 ) 5,395,811 Accumulated income (deficit) (852,206 ) 1,319,327 2,623 (1,321,950 ) (852,206 ) 4,536,543 6,150,666 2,419,004 (8,562,608 ) 4,543,605 Total liabilities and unitholders’ capital $ 12,838,691 $ 11,646,240 $ 4,967,408 $ (13,028,830 ) $ 16,423,509
Condensed Consolidating Statements of Operations	CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2015 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Revenues and other: Oil, natural gas and natural gas liquids sales $ — $ 1,151,240 $ 575,031 $ — $ 1,726,271 Gains on oil and natural gas derivatives — 1,027,014 29,175 — 1,056,189 Marketing revenues — 43,876 30,253 — 74,129 Other revenues — 19,550 7,195 — 26,745 — 2,241,680 641,654 — 2,883,334 Expenses: Lease operating expenses — 372,609 245,155 — 617,764 Transportation expenses — 167,561 52,160 — 219,721 Marketing expenses — 35,278 21,866 — 57,144 General and administrative expenses — 210,894 85,993 — 296,887 Exploration costs — 9,473 — — 9,473 Depreciation, depletion and amortization — 547,675 251,371 6,711 805,757 Impairment of long-lived assets — 5,024,944 853,810 (64,800 ) 5,813,954 Taxes, other than income taxes 2 111,300 70,593 — 181,895 Gains on sale of assets and other, net — (195,490 ) (1,919 ) — (197,409 ) 2 6,284,244 1,579,029 (58,089 ) 7,805,186 Other income and (expenses): Interest expense, net of amounts capitalized (463,168 ) 2,533 (85,818 ) — (546,453 ) Interest expense – affiliates — (12,123 ) — 12,123 — Interest income – affiliates 12,123 — — (12,123 ) — Gain on extinguishment of debt 708,050 — 11,209 — 719,259 Equity in losses from consolidated subsidiaries (5,002,695 ) — — 5,002,695 — Other, net (13,804 ) (161 ) (3,261 ) — (17,226 ) (4,759,494 ) (9,751 ) (77,870 ) 5,002,695 155,580 Loss before income taxes (4,759,496 ) (4,052,315 ) (1,015,245 ) 5,060,784 (4,766,272 ) Income tax expense (benefit) 315 (6,708 ) (68 ) — (6,461 ) Net loss $ (4,759,811 ) $ (4,045,607 ) $ (1,015,177 ) $ 5,060,784 $ (4,759,811 ) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2014 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Revenues and other: Oil, natural gas and natural gas liquids sales $ — $ 2,312,137 $ 1,298,402 $ — $ 3,610,539 Gains on oil and natural gas derivatives — 1,127,395 78,784 — 1,206,179 Marketing revenues — 84,349 50,911 — 135,260 Other revenues — 28,133 3,192 — 31,325 — 3,552,014 1,431,289 — 4,983,303 Expenses: Lease operating expenses — 440,624 364,540 — 805,164 Transportation expenses — 165,489 41,842 — 207,331 Marketing expenses — 81,210 36,255 — 117,465 General and administrative expenses — 190,286 102,787 — 293,073 Exploration costs — 125,037 — — 125,037 Depreciation, depletion and amortization — 771,549 302,353 — 1,073,902 Impairment of long-lived assets — 2,050,387 253,362 — 2,303,749 Taxes, other than income taxes 40 169,655 97,708 — 267,403 (Gains) losses on sale of assets and other, net — (487,286 ) 120,786 — (366,500 ) 40 3,506,951 1,319,633 — 4,826,624 Other income and (expenses): Interest expense, net of amounts capitalized (480,259 ) (19,631 ) (87,948 ) — (587,838 ) Interest expense – affiliates — (7,954 ) — 7,954 — Interest income – affiliates 7,954 — — (7,954 ) — Equity in earnings from consolidated subsidiaries 28,397 — — (28,397 ) — Other, net (7,861 ) (7,309 ) (1,043 ) — (16,213 ) (451,769 ) (34,894 ) (88,991 ) (28,397 ) (604,051 ) Income (loss) before income taxes (451,809 ) 10,169 22,665 (28,397 ) (447,372 ) Income tax expense — 4,368 69 — 4,437 Net income (loss) $ (451,809 ) $ 5,801 $ 22,596 $ (28,397 ) $ (451,809 ) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS For the Year Ended December 31, 2013 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Revenues and other: Oil, natural gas and natural gas liquids sales $ — $ 2,022,916 $ 50,324 $ — $ 2,073,240 Gains (losses) on oil and natural gas derivatives — 182,906 (5,049 ) — 177,857 Marketing revenues — 52,328 1,843 — 54,171 Other revenues — 26,387 — — 26,387 — 2,284,537 47,118 — 2,331,655 Expenses: Lease operating expenses — 357,113 15,410 — 372,523 Transportation expenses — 125,864 2,576 — 128,440 Marketing expenses — 36,259 1,633 — 37,892 General and administrative expenses — 215,973 20,298 — 236,271 Exploration costs — 5,251 — — 5,251 Depreciation, depletion and amortization — 818,466 10,845 — 829,311 Impairment of long-lived assets — 828,317 — — 828,317 Taxes, other than income taxes — 136,501 2,130 — 138,631 Losses on sale of assets and other, net 724 2,705 10,208 — 13,637 724 2,526,449 63,100 — 2,590,273 Other income and (expenses): Interest expense, net of amounts capitalized (415,670 ) (1,504 ) (3,963 ) — (421,137 ) Interest expense – affiliates — (5,543 ) — 5,543 — Interest income – affiliates 5,543 — — (5,543 ) — Loss on extinguishment of debt (5,304 ) — — — (5,304 ) Equity in losses from consolidated subsidiaries (266,899 ) — — 266,899 — Other, net (8,283 ) (166 ) (28 ) — (8,477 ) (690,613 ) (7,213 ) (3,991 ) 266,899 (434,918 ) Loss before income taxes (691,337 ) (249,125 ) (19,973 ) 266,899 (693,536 ) Income tax benefit — (2,199 ) — — (2,199 ) Net loss $ (691,337 ) $ (246,926 ) $ (19,973 ) $ 266,899 $ (691,337 )
Condensed Consolidating Statements of Cash Flow	CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2015 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from operating activities: Net loss $ (4,759,811 ) $ (4,045,607 ) $ (1,015,177 ) $ 5,060,784 $ (4,759,811 ) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization — 547,675 251,371 6,711 805,757 Impairment of long-lived assets — 5,024,944 853,810 (64,800 ) 5,813,954 Unit-based compensation expenses — 56,136 — — 56,136 Gain on extinguishment of debt (708,050 ) — (11,209 ) — (719,259 ) Amortization and write-off of deferred financing fees 30,993 — 3,750 — 34,743 Gains on sale of assets and other, net — (188,200 ) (961 ) — (189,161 ) Equity in losses from consolidated subsidiaries 5,002,695 — — (5,002,695 ) — Deferred income taxes — 4,606 (68 ) — 4,538 Derivatives activities: Total gains — (1,027,014 ) (36,068 ) — (1,063,082 ) Cash settlements — 1,130,640 68,770 — 1,199,410 Cash settlements on canceled derivatives — 4,679 — — 4,679 Changes in assets and liabilities: Decrease in accounts receivable – trade, net — 207,300 59,941 — 267,241 Decrease in accounts receivable – affiliates 1,167,823 4,584 — (1,172,407 ) — (Increase) decrease in other assets — (9,142 ) 18,724 — 9,582 Decrease in accounts payable and accrued expenses (14 ) (98,209 ) (58,171 ) — (156,394 ) Decrease in accounts payable and accrued expenses – affiliates — (1,167,823 ) (4,584 ) 1,172,407 — Decrease in other liabilities (39,646 ) (11,620 ) (7,610 ) — (58,876 ) Net cash provided by operating activities 693,990 432,949 122,518 — 1,249,457 Cash flow from investing activities: Development of oil and natural gas properties — (576,256 ) (32,633 ) — (608,889 ) Purchases of other property and equipment — (48,967 ) (17,741 ) — (66,708 ) Investment in affiliates (132,332 ) — — 132,332 — Change in notes receivable with affiliate (44,600 ) — — 44,600 — Settlement of advance to affiliate — — 129,217 (129,217 ) — Proceeds from sale of properties and equipment and other (3,430 ) 349,200 22,525 — 368,295 Net cash provided by (used in) investing activities (180,362 ) (276,023 ) 101,368 47,715 (307,302 ) LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from financing activities: Proceeds from sale of units 233,427 — — — 233,427 Proceeds from borrowings 1,445,000 — — — 1,445,000 Repayments of debt (1,828,461 ) — (355,418 ) — (2,183,879 ) Distributions to unitholders (323,878 ) — — — (323,878 ) Financing fees and offering costs (26,678 ) — (1,377 ) — (28,055 ) Change in note payable with affiliate — 44,600 — (44,600 ) — Settlement of advance from affiliate — (129,217 ) — 129,217 — Capital contributions – affiliates — — 132,332 (132,332 ) — Excess tax benefit from unit-based compensation (9,467 ) — — — (9,467 ) Other (2,536 ) (72,422 ) 14 — (74,944 ) Net cash used in financing activities (512,593 ) (157,039 ) (224,449 ) (47,715 ) (941,796 ) Net increase (decrease) in cash and cash equivalents 1,035 (113 ) (563 ) — 359 Cash and cash equivalents: Beginning 38 185 1,586 — 1,809 Ending $ 1,073 $ 72 $ 1,023 $ — $ 2,168 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2014 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from operating activities: Net income (loss) $ (451,809 ) $ 5,801 $ 22,596 $ (28,397 ) $ (451,809 ) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depreciation, depletion and amortization — 771,549 302,353 — 1,073,902 Impairment of long-lived assets — 2,050,387 253,362 — 2,303,749 Unit-based compensation expenses — 53,284 — — 53,284 Amortization and write-off of deferred financing fees 38,785 17,054 (4,913 ) — 50,926 (Gains) losses on sale of assets and other, net — (372,945 ) 111,374 — (261,571 ) Equity in earnings from consolidated subsidiaries (28,397 ) — — 28,397 — Deferred income taxes — 3,874 69 — 3,943 Derivatives activities: Total gains — (1,127,395 ) (78,784 ) — (1,206,179 ) Cash settlements — 88,776 6,738 — 95,514 Cash settlements on canceled derivatives — — 12,281 — 12,281 Changes in assets and liabilities: (Increase) decrease in accounts receivable – trade, net — (11,419 ) 16,483 — 5,064 Decrease in accounts receivable – affiliates 257,485 16,950 — (274,435 ) — (Increase) decrease in other assets 312 (2,187 ) (15,949 ) — (17,824 ) Increase in accounts payable and accrued expenses — 99,003 26 — 99,029 Decrease in accounts payable and accrued expenses – affiliates — (270,690 ) (3,745 ) 274,435 — Increase (decrease) in other liabilities 14,465 (24,473 ) (38,411 ) — (48,419 ) Net cash provided by (used in) operating activities (169,159 ) 1,297,569 583,480 — 1,711,890 Cash flow from investing activities: Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired — (2,475,315 ) (3,937 ) — (2,479,252 ) Development of oil and natural gas properties — (1,061,395 ) (508,482 ) — (1,569,877 ) Purchases of other property and equipment — (63,070 ) (11,470 ) — (74,540 ) Investment in affiliates (100,921 ) — — 100,921 — Change in notes receivable with affiliate (44,300 ) — — 44,300 — Proceeds from sale of properties and equipment and other (14,117 ) 2,210,015 7,667 — 2,203,565 Net cash used in investing activities (159,338 ) (1,389,765 ) (516,222 ) 145,221 (1,920,104 ) LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from financing activities: Proceeds from borrowings 4,640,024 1,300,000 — — 5,940,024 Repayments of debt (3,305,000 ) (1,300,000 ) (206,124 ) — (4,811,124 ) Distributions to unitholders (962,048 ) — — — (962,048 ) Financing fees and offering costs (59,048 ) — (10,646 ) — (69,694 ) Change in note payable with affiliate — 44,300 — (44,300 ) — Capital contribution – affiliates — — 100,921 (100,921 ) — Excess tax benefit from unit-based compensation 810 (44 ) — — 766 Other 13,745 47,047 (864 ) — 59,928 Net cash provided by (used in) financing activities 328,483 91,303 (116,713 ) (145,221 ) 157,852 Net decrease in cash and cash equivalents (14 ) (893 ) (49,455 ) — (50,362 ) Cash and cash equivalents: Beginning 52 1,078 51,041 — 52,171 Ending $ 38 $ 185 $ 1,586 $ — $ 1,809 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2013 LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from operating activities: Net loss $ (691,337 ) $ (246,926 ) $ (19,973 ) $ 266,899 $ (691,337 ) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depreciation, depletion and amortization — 818,466 10,845 — 829,311 Impairment of long-lived assets — 828,317 — — 828,317 Unit-based compensation expenses — 42,703 — — 42,703 Loss on extinguishment of debt 5,304 — — — 5,304 Amortization and write-off of deferred financing fees 22,122 — (615 ) — 21,507 Losses on sale of assets and other, net — 37,232 — — 37,232 Equity in losses from consolidated subsidiaries 266,899 — — (266,899 ) — Deferred income taxes — (2,541 ) — — (2,541 ) Derivatives activities: Total (gains) losses — (182,906 ) 5,049 — (177,857 ) Cash settlements — 248,862 — — 248,862 Changes in assets and liabilities: Decrease in accounts receivable – trade, net — 17,754 71,434 — 89,188 Increase in accounts receivable – affiliates (120,967 ) (16,950 ) — 137,917 — (Increase) decrease in other assets (330 ) 5,896 10,613 — 16,179 Increase (decrease) in accounts payable and accrued expenses 178 (52,143 ) (25,028 ) — (76,993 ) Increase in accounts payable and accrued expenses – affiliates — 120,967 16,950 (137,917 ) — Increase (decrease) in other liabilities 2,092 6,842 (12,597 ) — (3,663 ) Net cash provided by (used in) operating activities (516,039 ) 1,625,573 56,678 — 1,166,212 Cash flow from investing activities: Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired — (730,326 ) 451,113 — (279,213 ) Development of oil and natural gas properties — (1,060,547 ) (17,478 ) — (1,078,025 ) Purchases of other property and equipment — (92,352 ) — — (92,352 ) Investment in affiliates 435,000 — — (435,000 ) — Change in notes receivable with affiliate (26,700 ) — — 26,700 — Proceeds from sale of properties and equipment and other (22,039 ) 218,312 — — 196,273 Net cash provided by (used in) investing activities 386,261 (1,664,913 ) 433,635 (408,300 ) (1,253,317 ) LINN Energy, LLC Guarantor Subsidiaries Non- Guarantor Subsidiary Eliminations Consolidated (in thousands) Cash flow from financing activities: Proceeds from borrowings 2,230,000 — — — 2,230,000 Repayments of debt (1,404,898 ) — — — (1,404,898 ) Distributions to unitholders (682,241 ) — — — (682,241 ) Financing fees and offering costs (16,033 ) — — — (16,033 ) Change in note payable with affiliate — 26,700 — (26,700 ) — Capital contribution – affiliates — — (435,000 ) 435,000 — Excess tax benefit from unit-based compensation — 160 — — 160 Other 2,895 12,422 (4,272 ) — 11,045 Net cash provided by (used in) financing activities 129,723 39,282 (439,272 ) 408,300 138,033 Net increase (decrease) in cash and cash equivalents (55 ) (58 ) 51,041 — 50,928 Cash and cash equivalents: Beginning 107 1,136 — — 1,243 Ending $ 52 $ 1,078 $ 51,041 $ — $ 52,171

Supplemental Oil and Natural 41

Supplemental Oil and Natural Gas Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development	Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Property acquisition costs: (1) Proved $ — $ 2,784,852 $ 3,740,379 Unproved — 788,682 1,638,302 Exploration costs 19,929 792 13,096 Development costs 430,357 1,487,204 1,153,770 Asset retirement costs 6,303 20,919 7,351 Total costs incurred $ 456,589 $ 5,082,449 $ 6,552,898 (1) See Note 2 for details about the Company’s acquisitions.
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities	Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below: December 31, 2015 2014 (in thousands) Proved properties: Leasehold acquisition $ 13,361,171 $ 13,362,642 Development 2,976,643 2,830,841 Unproved properties 1,783,341 1,875,417 18,121,155 18,068,900 Less accumulated depletion and amortization (11,097,492 ) (4,867,682 ) $ 7,023,663 $ 13,201,218
Results of Operations for Oil and Gas Producing Activities	The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below: Year Ended December 31, 2015 2014 2013 (in thousands) Revenues and other: Oil, natural gas and natural gas liquids sales $ 1,726,271 $ 3,610,539 $ 2,073,240 Gains on oil and natural gas derivatives 1,056,189 1,206,179 177,857 2,782,460 4,816,718 2,251,097 Production costs: Lease operating expenses 617,764 805,164 372,523 Transportation expenses 219,721 207,331 128,440 Severance taxes, ad valorem taxes and California carbon allowances 181,941 267,100 139,202 1,019,426 1,279,595 640,165 Other costs: Exploration costs 9,473 125,037 5,251 Depletion and amortization 745,512 1,020,674 790,320 Impairment of long-lived assets 5,813,954 2,303,749 828,317 Gains on sale of assets and other, net (198,924 ) (388,733 ) (138 ) Texas margin tax expense (benefit) (2,789 ) 4,053 458 6,367,226 3,064,780 1,624,208 Results of operations $ (4,604,192 ) $ 472,343 $ (13,276 ) There is no federal tax provision included in the results above because the Company’s subsidiaries subject to federal tax do not own any of the Company’s oil and natural gas interests. Limited liability companies are subject to Texas margin tax. See Note 14 for additional information about income taxes.
Estimated Quantities of Oil, Natural Gas and NGL Reserves	An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below: Year Ended December 31, 2015 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 4,255 341.8 166.3 7,304 Revisions of previous estimates (1,404 ) (122.2 ) (40.4 ) (2,379 ) Sales of minerals in place (13 ) (4.1 ) (2.0 ) (50 ) Extensions, discoveries and other additions 15 4.6 0.8 47 Production (234 ) (22.8 ) (10.4 ) (434 ) End of year 2,619 197.3 114.3 4,488 Proved developed reserves: Beginning of year 3,549 246.0 132.2 5,818 End of year 2,619 197.3 114.3 4,488 Proved undeveloped reserves: Beginning of year 706 95.8 34.1 1,486 End of year — — — — Year Ended December 31, 2014 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 3,010 365.6 200.0 6,403 Revisions of previous estimates 96 (22.3 ) (46.8 ) (318 ) Purchases of minerals in place 1,763 50.0 71.9 2,495 Sales of minerals in place (477 ) (51.7 ) (49.5 ) (1,084 ) Extensions, discoveries and other additions 72 26.8 2.9 250 Production (209 ) (26.6 ) (12.2 ) (442 ) End of year 4,255 341.8 166.3 7,304 Proved developed reserves: Beginning of year 2,027 252.4 133.2 4,340 End of year 3,549 246.0 132.2 5,818 Proved undeveloped reserves: Beginning of year 983 113.2 66.8 2,063 End of year 706 95.8 34.1 1,486 Year Ended December 31, 2013 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 2,571 191.5 179.4 4,796 Revisions of previous estimates (17 ) (21.3 ) (2.0 ) (157 ) Purchases of minerals in place 356 191.1 17.8 1,610 Sales of minerals in place (24 ) (5.2 ) (2.9 ) (73 ) Extensions, discoveries and other additions 286 21.7 18.5 527 Production (162 ) (12.2 ) (10.8 ) (300 ) End of year 3,010 365.6 200.0 6,403 Proved developed reserves: Beginning of year 1,661 131.4 113.0 3,127 End of year 2,027 252.4 133.2 4,340 Proved undeveloped reserves: Beginning of year 910 60.1 66.4 1,669 End of year 983 113.2 66.8 2,063 The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents using the ratio of one barrel to six Mcf.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves	Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Company is not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts are not material. See Note 14 for additional information about income taxes. December 31, 2015 2014 2013 (in thousands) Future estimated revenues $ 17,293,943 $ 55,195,268 $ 51,112,346 Future estimated production costs (10,734,979 ) (24,100,468 ) (19,306,728 ) Future estimated development costs (1,107,639 ) (4,032,588 ) (5,110,896 ) Future net cash flows 5,451,325 27,062,212 26,694,722 10% annual discount for estimated timing of cash flows (2,417,780 ) (14,549,921 ) (14,795,393 ) Standardized measure of discounted future net cash flows $ 3,033,545 $ 12,512,291 $ 11,899,329 Representative NYMEX prices: (1) Natural gas (MMBtu) $ 2.59 $ 4.35 $ 3.67 Oil (Bbl) $ 50.16 $ 95.27 $ 96.89 (1) In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow	The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Year Ended December 31, 2015 2014 2013 (in thousands) Sales and transfers of oil, natural gas and NGL produced during the period $ (706,845 ) $ (2,330,944 ) $ (1,433,075 ) Changes in estimated future development costs 1,501,593 156,614 317,064 Net change in sales and transfer prices and production costs related to future production (9,309,151 ) (599,121 ) 203,370 Purchases of minerals in place — 3,021,768 5,113,335 Sales of minerals in place (97,785 ) (1,681,504 ) (139,384 ) Extensions, discoveries and improved recovery 90,090 910,787 801,254 Previously estimated development costs incurred during the period 159,248 819,987 444,861 Net change due to revisions in quantity estimates (1,633,958 ) (672,800 ) (220,224 ) Accretion of discount 1,251,229 1,189,933 607,298 Changes in production rates and other (733,167 ) (201,758 ) 131,849 $ (9,478,746 ) $ 612,962 $ 5,826,348

Supplemental Quarterly Data (42

Supplemental Quarterly Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Quarterly financial data	Quarterly Financial Data Quarters Ended March 31 June 30 September 30 December 31 (in thousands, except per unit amounts) 2015: Oil, natural gas and natural gas liquids sales $ 450,569 $ 496,419 $ 427,245 $ 352,038 Gains (losses) on oil and natural gas derivatives 424,781 (191,188 ) 549,029 273,567 Total revenues and other 916,547 321,828 998,304 646,655 Total expenses (1) 1,136,442 578,586 2,790,081 3,497,486 Gains on sale of assets and other, net (12,287 ) (17,996 ) (166,980 ) (146 ) Net loss (339,160 ) (379,127 ) (1,569,317 ) (2,472,207 ) Net loss per unit: Basic $ (1.03 ) $ (1.12 ) $ (4.47 ) $ (7.05 ) Diluted $ (1.03 ) $ (1.12 ) $ (4.47 ) $ (7.05 ) Quarters Ended March 31 June 30 September 30 December 31 (in thousands, except per unit amounts) 2014: Oil, natural gas and natural gas liquids sales $ 938,877 $ 967,850 $ 937,458 $ 766,354 Gains (losses) on oil and natural gas derivatives (241,493 ) (408,788 ) 451,702 1,404,758 Total revenues and other 733,587 596,951 1,435,115 2,217,650 Total expenses (1) 674,568 664,452 1,320,157 2,533,947 (Gains) losses on sale of assets and other, net 2,586 5,467 (35,803 ) (338,750 ) Net loss (85,337 ) (207,870 ) (4,100 ) (154,502 ) Net loss per unit: Basic $ (0.27 ) $ (0.64 ) $ (0.02 ) $ (0.47 ) Diluted $ (0.27 ) $ (0.64 ) $ (0.02 ) $ (0.47 ) (1) Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.

Basis of Presentation and Sig43

Basis of Presentation and Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 15, 2016	Feb. 29, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Amount of potential debt acceleration	$ 3,600,000,000
Long-term Debt	9,044,743,000	$ 10,295,809,000
Allowance for doubtful accounts	1,000,000	1,000,000
Capitalized interest costs	5,000,000	9,000,000	$ 2,000,000
Natural gas production imbalance payables	11,000,000	13,000,000
Deferred Finance Costs, Current, Net	35,000,000
Net deferred financing fees	36,000,000	129,000,000
Debt issuance fees amortization expense	23,000,000	46,000,000	18,000,000
Write off of Deferred Debt Issuance Cost	10,000,000	8,000,000	0
Gas Balancing Asset (Liability)	13,000,000	17,000,000
Impairment of Leasehold	2,000,000	$ 125,000,000	5,000,000
Restricted Cash and Cash Equivalents Items [Line Items]
Useful lives of other property and equipment (in years)		10 years
Restricted cash	257,363,000	$ 6,225,000
Impairment Of Unproved Oil And Gas Properties	$ 899,084,000	0	$ 0
Minimum [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Useful lives of other property and equipment (in years)	2 years
Maximum [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Useful lives of other property and equipment (in years)	39 years
Restricted Cash for ARO [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 7,000,000	$ 6,000,000
Restricted Cash for Debt Agreement [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	250,000,000
Senior Secured Notes [Member] | Subsequent Event [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Percent of aggregate outstanding debt				25.00%
Senior Notes [Member] | Subsequent Event [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Percent of aggregate outstanding debt				25.00%
Deferred interest payment				$ 60,000,000
Linn Energy, LLC | Credit Facility [Member] | Line of Credit
Restricted Cash and Cash Equivalents Items [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 879,000,000
Linn Energy, LLC | Senior Notes Due September 2021 | Senior Notes [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Linn Energy, LLC | Senior Notes Due September 2021 | Senior Notes [Member] | Subsequent Event [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Deferred interest payment				12,000,000
Linn Energy, LLC | Senior Notes Due February 2021 [Member] | Senior Notes [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.75%
Linn Energy, LLC | Senior Notes Due February 2021 [Member] | Senior Notes [Member] | Subsequent Event [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Deferred interest payment				30,000,000
Berry | Credit Facility [Member] | Line of Credit
Restricted Cash and Cash Equivalents Items [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,000,000
Berry | Credit Facility [Member] | Line of Credit | Subsequent Event [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity					$ 1,000,000
Berry | Senior Notes Due 2022 | Senior Notes [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.375%
Berry | Senior Notes Due 2022 | Senior Notes [Member] | Subsequent Event [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Deferred interest payment				$ 18,000,000

Basis of Presentation and Sig44

Basis of Presentation and Significant Accounting Policies Proved Property Impairment (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties	$ 1,700,000	$ 603,000	$ 4,914,870	$ 2,303,749	$ 828,317
Impairment of Long-Lived Assets to be Disposed of					37,000
Granite Wash formation [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties					791,000
Rockies region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			1,758,939	585,705	0
Hugoton Basin region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			1,667,768	0	0
California region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			537,511	22	0
TexLa region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			430,859	4,836	0
Mid-Continent region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			405,370	244,413	828,317
Permian Basin region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			71,990	1,337,444	0
South Texas region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			$ 42,433	$ 131,329	$ 0

Basis of Presentation and Sig45

Basis of Presentation and Significant Accounting Policies Unproved Property Impairment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment Of Unproved Oil And Gas Properties	$ 899,084	$ 0	$ 0
TexLa region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment Of Unproved Oil And Gas Properties	416,846
Permian Basin region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment Of Unproved Oil And Gas Properties	226,922
Rockies region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment Of Unproved Oil And Gas Properties	184,137
California region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment Of Unproved Oil And Gas Properties	$ 71,179

Divestitures, Exchanges of Pr46

Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding (Divestiture) (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Aug. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Oil and Gas Property		$ 0	$ 85,493	$ 0
XOM II Exchange [Member]
Business Acquisition [Line Items]
Costs Associated With Sale of Oil and Gas Property and Equipment		3,000
Gain (Loss) on Disposition of Oil and Gas Property		20,000
XOM I Exchange [Member]
Business Acquisition [Line Items]
Costs Associated With Sale of Oil and Gas Property and Equipment		3,000
Gain (Loss) on Disposition of Oil and Gas Property		65,000
Granite Wash Assets Sale [Member]
Business Acquisition [Line Items]
Costs Associated With Sale of Oil and Gas Property and Equipment		10,000
Gain (Loss) on Disposition of Oil and Gas Property		294,000
Proceeds from sale of oil and natural gas property		1,800,000
Permian Basin Assets Sale [Member]
Business Acquisition [Line Items]
Costs Associated With Sale of Oil and Gas Property and Equipment		2,000
Gain (Loss) on Disposition of Oil and Gas Property		(28,000)
Proceeds from sale of oil and natural gas property		352,000
STACK acreage divestiture [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Oil and Gas Property		36,000
Proceeds from sale of oil and natural gas property		$ 44,000
Howard County [Member]
Business Acquisition [Line Items]
Costs Associated With Sale of Oil and Gas Property and Equipment	$ 1,000
Gain (Loss) on Disposition of Oil and Gas Property	177,000
Proceeds from sale of oil and natural gas property	$ 276,000

Divestitures, Exchanges of Pr47

Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding (Acquisitions, Joint-Venture Funding) (Details) - USD ($) $ in Millions	Dec. 17, 2013	Apr. 03, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2015	Dec. 16, 2013
Pioneer Assets Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred			$ 328
Devon Assets Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred			2,100
Business Acquisition Anadarko
Business Acquisition [Line Items]
Future funding commitment of joint venture consideration transferred			$ 25	$ 173	$ 202
Future Funding Of Joint Venture Agreement		$ 400
Business Acquisition, Berry
Business Acquisition [Line Items]
Exchange ratio	168.00%
Business Acqusition, Fair Value	$ 4,600
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt							$ 2,300
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents							$ 451
Business Acquisition, Berry | Linn Energy, LLC
Business Acquisition [Line Items]
LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674
Business Acquisition, Berry | LinnCo
Business Acquisition [Line Items]
LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674
Senior Notes [Member] | Senior Notes Due May 2019 | Linn Energy, LLC
Business Acquisition [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						6.50%
Senior Notes [Member] | Senior Notes Due September 2021 | Linn Energy, LLC
Business Acquisition [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						6.50%

Divestitures, Exchanges of Pr48

Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding (Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2014	Jun. 27, 2014
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Business acquisition interim financing		$ 2,300,000
Useful lives of other property and equipment (in years)	10 years
Business Acquisition Pro Forma Results of Operations
Total revenues and other	$ 5,335,442
Total operating expenses	(5,039,279)
Net loss	$ (403,415)
Net loss per unit:
Basic	$ (1.25)
Diluted	$ (1.25)

Unitholders' Capital (Deficit)

Unitholders' Capital (Deficit) (Details) - USD ($)	Dec. 17, 2013	Aug. 31, 2015	May. 31, 2015	Sep. 30, 2015	Dec. 31, 2015	Dec. 16, 2013
Schedule of Equity Offerings [Line Items]
Stock Issued During Period, Value, New Issues					$ 224,665,000
Stock Repurchased and Retired During Period, Shares		191,446
Related Party Transaction [Line Items]
Stock Repurchase Program, Authorized Amount					$ 250,000,000
Payments for Repurchase of Common Stock		$ 672,000
Berry
Related Party Transaction [Line Items]
Exchange ratio	168.00%
LinnCo | Berry
Related Party Transaction [Line Items]
LinnCo common shares issued to acquire Berry	93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674
Linn Energy, LLC | Berry
Related Party Transaction [Line Items]
LinnCo common shares issued to acquire Berry	93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674
Value of units issued to acquire Berry						$ 2,800,000,000
At-the-Market Offering Program [Member]
Schedule of Equity Offerings [Line Items]
Equity Offering Program Maximum Value				$ 500,000,000
Sale of units, net of offering costs (in units)					3,621,983
Stock issued during period, sales price per unit					$ 12.37
Stock Issued During Period, Value, New Issues					$ 44,000,000
Investment Banking, Advisory, Brokerage, and Underwriting Fees and Commissions					448,000
Professional Fees					459,000
EquityOfferingProgramRemainingBalance					$ 455,000,000
Public Offering of Units [Member]
Schedule of Equity Offerings [Line Items]
Sale of units, net of offering costs (in units)			16,000,000
Stock issued during period, sales price per unit			$ 11.79
Public Offering Price Per Unit Net			$ 11.32
Stock Issued During Period, Value, New Issues			$ 181,000,000
Investment Banking, Advisory, Brokerage, and Underwriting Fees and Commissions			$ 8,000,000

Significant Customers (Details)

Significant Customers (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Customer 1 [Member] | Sales [Member] | Customer Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)	12.00%	14.00%	12.00%
Credit Risk [Member] | Trade Accounts Receivable [Member]
Concentration Risk [Line Items]
Total number of largest customers represented in sales		1
Credit Risk [Member] | Customer 1 [Member] | Trade Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)		11.00%

Unit-Based Compensation and O51

Unit-Based Compensation and Other Benefit Plans (Details) - USD ($)	1 Months Ended	12 Months Ended
	Jan. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 16, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Berry employee unit-based awards					$ 19,000,000
Number of shares available for grant (in units)		5,400,000
Units authorized for issuance (in units)		5,800,000
Units reserved for future issuance (in units)		5,400,000
Share-based Compensation [Abstract]
Allocated Share Based Compensation		$ 56,136,000	$ 53,284,000	$ 42,703,000
Income tax benefit		$ 20,742,000	$ 19,688,000	$ 15,779,000
Weighted Average Exercise Price Per Unit [Abstract]
Forfeited or expired (in dollars per unit)		$ 33.60
Change in Unit Options and Unit Options Outstanding [Abstract]
Expected volatility			50.88%
Expected volatility			29.65%
Expected distributions				9.84%
Risk-free rate			1.55%
Risk-free rate			0.13%
Defined Contribution Plan [Abstract]
Entity's matching contribution (in hundredths)		100.00%
Participant's eligible contribution, (in hundredths)		6.00%
Defined Contribution Plan, Cost Recognized		$ 11,000,000	$ 10,000,000	$ 7,000,000
General and Administrative Expense [Member]
Share-based Compensation [Abstract]
Allocated Share Based Compensation		47,312,000	45,195,000	37,375,000
Lease Operating Expense [Member]
Share-based Compensation [Abstract]
Allocated Share Based Compensation		$ 8,824,000	$ 8,089,000	$ 5,328,000
Unit Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vesting period (in years)		3 years
Contractual life of unit options (in years)		10 years
Unit Options Activity [Roll Forward]
Outstanding, beginning (in units)		824,711	5,444,417
Forfeited or expired (in units)		(4,619,706)
Outstanding, ending (in units)		824,711	5,444,417
Exercisable (in units)		821,787
Weighted Average Exercise Price Per Unit [Abstract]
Outstanding, beginning (in dollars per unit)		$ 22.72	$ 31.95
Outstanding, ending (in dollars per unit)		22.72	$ 31.95
Exercisable (in dollars per unit)		$ 22.69
Weighted Average Remaining Contractual Life in Years [Abstract]
Outstanding, beginning (in years)		2 years 3 months 7 days	5 years 1 month 12 days
Outstanding, ending (in years)		2 years 3 months 7 days	5 years 1 month 12 days
Exercisable (in years)		2 years 3 months 1 day
Weighted Average Grant Date Fair Value Per Unit [Abstract]
Weighted average grant date fair value of options granted (in dollars per unit)				$ 7.52
Change in Unit Options and Unit Options Outstanding [Abstract]
Weighted average grant date fair value of options granted (in dollars per unit)				$ 7.52
Intrinsic value of options exercised			$ 11,000,000	$ 2,000,000
Intrinsic value of outstanding unit options		$ 0	$ 0
Intrinsic value of exercisable unit options		$ 0
Unit Options [Member] | Nonemployee [Member]
Nonemployee Grants [Abstract]
Unit warrants oustanding (in units)		15,000
Exercise price of unit warrants (in dollars per unit)		$ 25.50
Restricted Unrestricted Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant (in units)		21,000,000
Units reserved for future issuance (in units)		21,000,000
Restricted/Unrestricted Nonvested Units [Roll Forward]
Granted (in dollars per unit)			$ 33.10	$ 30.71
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Share-based Arrangements, Liability Classified, Settlements		$ 0
Deferred Compensation Share-based Arrangements, Liability, Classified, Noncurrent		$ 0
Restricted/Unrestricted Nonvested Units [Roll Forward]
Granted (in units)	567,320
Restricted/Unrestricted Units [Abstract]
Granted (in units)	567,320
Restricted Units [Member]
Restricted/Unrestricted Nonvested Units [Roll Forward]
Nonvested units, beginning (in units)		4,926,572	2,838,973
Granted (in units)		4,576,631
Vested (in units)		(1,870,384)
Forfeited (in units)		(618,648)
Nonvested units, ending (in units)		4,926,572	2,838,973
Outstanding, beginning (in dollars per unit)		$ 16.22	$ 32.70
Granted (in dollars per unit)		10.21
Vested (in dollars per unit)		26.41
Forfeited (in dollars per unit)		16.65
Outstanding, ending (in dollars per unit)		$ 16.22	$ 32.70
Restricted/Unrestricted Units [Abstract]
Fair value of units vested		$ 49,000,000	$ 42,000,000	$ 31,000,000
Unrecognized compensation cost		$ 31,000,000
Unrecognized compensation cost recognition period (in years)		1 year 6 months
Granted (in units)		4,576,631
Change in Unit Options and Unit Options Outstanding [Abstract]
Unrecognized compensation cost		$ 31,000,000
Unrecognized compensation cost recognition period (in years)		1 year 6 months
Minimum [Member]
Change in Unit Options and Unit Options Outstanding [Abstract]
Expected term			5 years
Maximum [Member]
Change in Unit Options and Unit Options Outstanding [Abstract]
Expected term			8 months 5 days
Tranche One | Unit Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vesting period (in years)			2 years
Award vesting rights			50.00%
Tranche Two | Unit Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards vesting period (in years)		3 years	3 years
Award vesting rights			50.00%

Debt (Details)

Debt (Details)	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Jan. 01, 2016USD ($)	Oct. 31, 2015USD ($)	Sep. 30, 2015	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Apr. 30, 2012USD ($)
Debt Instrument [Line Items]
Percent of future net income allowable to increase Berry's restricted payments basket	50.00%
Repayments of debt	$ 2,183,879,000	$ 4,811,124,000	$ 1,404,898,000
Gain (Losses) on Extinguishment of Debt excluding TDR	367,000,000
Increase (decrease) to restricted cash	250,000,000
Extinguishment of Debt, Amount	992,000,000
Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of debt	609,000,000
Linn Energy, LLC | Loans Payable
Debt Instrument [Line Items]
Loans Payable	$ 500,000,000
Linn Energy, LLC | Loans Payable | Credit Facility [Member]
Debt Instrument [Line Items]
Line Of Credit Facility Collateral Coverage Ratio | Pure	2.5
Line Of Credit Facility Portion Of Properties Required To Maintain Mortgages	80.00%
Linn Energy, LLC | Line of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 3,600,000,000
Linn Energy, LLC | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	3,100,000,000								$ 4,000,000,000
Line of Credit Facility, Maximum Borrowing Capacity	4,050,000,000			$ 3,600,000,000	$ 4,050,000,000		$ 4,050,000,000	$ 4,500,000,000
Line of Credit Facility, Remaining Borrowing Capacity	879,000,000
Letters of Credit Outstanding, Amount	6,000,000
Maximum Junior Lien debt exchange	4,000,000,000
Maximum junior lien additional debt	1,000,000,000
Minimum liquidity	$ 500,000,000
Minimum liquidity as a percentage of borrowing base	15.00%
Line Of Credit Facility Collateral Coverage Ratio						2.5
Line Of Credit Facility Portion Of Properties Required To Maintain Mortgages	90.00%					80.00%
Debt Instrument, Change in basis spread on variable rate	0.25%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
Linn Energy, LLC | Senior Secured Notes [Member] | Senior Secured Second Lien Notes Due 2020 [Member]
Debt Instrument [Line Items]
Unsecured debt outstanding required to trigger springing maturity	$ 250,000,000
Springing maturity days prior to unsecured debt maturity	92 days
Debt Instrument, Interest Rate, Stated Percentage	12.00%
Maximum Percentage of Debt Instrument Redeemable	35.00%
Minimum original face value of debt remaining	65.00%
Linn Energy, LLC | Senior Secured Notes [Member] | Senior Secured Second Lien Notes Due 2020 [Member] | Debt Instrument, Redemption, Period Two [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	112.00%
Linn Energy, LLC | Senior Secured Notes [Member] | Senior Secured Second Lien Notes Due 2020 [Member] | Debt Instrument, Redemption, Period One [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	112.00%
Debt Instrument, Redemption price plus make whole premium, percentage	100.00%
Linn Energy, LLC | Senior Secured Notes [Member] | Senior Secured Second Lien Notes Due 2020 [Member] | Debt Instrument, Redemption, Period Three [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	106.00%
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due May 2019
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Extinguishment of Debt, Amount	$ 53,000,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due November 2019
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Extinguishment of Debt, Amount	$ 395,000,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due April 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.625%
Extinguishment of Debt, Amount	$ 295,000,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due February 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.75%
Extinguishment of Debt, Amount	$ 36,000,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Extinguishment of Debt, Amount	$ 148,000,000
Berry | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	900,000,000
Line of Credit Facility, Maximum Borrowing Capacity	900,000,000				$ 900,000,000		$ 1,200,000,000	$ 1,400,000,000
Line of Credit Facility, Remaining Borrowing Capacity	1,000,000
Maximum junior lien additional debt	$ 500,000,000
Line Of Credit Facility Collateral Coverage Ratio						2.5
Line Of Credit Facility Portion Of Properties Required To Maintain Mortgages	90.00%					80.00%
Debt Instrument, Change in basis spread on variable rate	0.25%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
Repayments of debt	$ 300,000,000
Berry | Senior Notes [Member] | Senior Notes Due November 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.75%
Extinguishment of Debt, Amount	$ 39,000,000
Berry | Senior Notes [Member] | Senior Notes Due 2022
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.375%
Extinguishment of Debt, Amount	$ 26,000,000
March 31, 2017 and June 30, 2017 [Member] | Linn Energy, LLC | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line Of Credit Facility Collateral Coverage Ratio	2.25
March 31, 2017 and June 30, 2017 [Member] | Berry | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line Of Credit Facility Collateral Coverage Ratio	2.25
Subsequent to June 30, 2017 [Member] | Linn Energy, LLC | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line Of Credit Facility Collateral Coverage Ratio	2.5
Subsequent to June 30, 2017 [Member] | Berry | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line Of Credit Facility Collateral Coverage Ratio	2.5
December 31, 2015 through December 31, 2016 [Member] | Linn Energy, LLC | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line Of Credit Facility Collateral Coverage Ratio	2
December 31, 2015 through December 31, 2016 [Member] | Berry | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line Of Credit Facility Collateral Coverage Ratio	2
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Linn Energy, LLC | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Berry | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
Minimum [Member] | ABR [Member] | Linn Energy, LLC | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%
Minimum [Member] | ABR [Member] | Berry | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Linn Energy, LLC | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Linn Energy, LLC | Loans Payable | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Berry | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
Maximum [Member] | ABR [Member] | Linn Energy, LLC | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
Maximum [Member] | ABR [Member] | Linn Energy, LLC | Loans Payable | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
Maximum [Member] | ABR [Member] | Berry | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%

Debt Schedule of Long-Term Debt

Debt Schedule of Long-Term Debt (Details) - USD ($)		1 Months Ended
		Nov. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Credit facilities			$ 3,088,175,000	$ 2,968,175,000
Term loan			500,000,000	500,000,000
Senior notes, net			3,848,235,000	6,827,634,000
Senior secured second lien notes			1,000,000,000	0
Interest payable on second lien notes			608,333,000	0
Total debt, net			9,044,743,000	10,295,809,000
Less current portion (5)			(3,716,508,000)	0
Total long-term debt, net			5,328,235,000	10,295,809,000
Par Value of Senior Notes Exchanged		$ 2,000,000,000
Interest Payments on Troubled Debt, Current			128,000,000
Senior Notes [Member]
Debt Instrument [Line Items]
Net unamortized discounts and premiums			8,694,000	21,499,000
Linn Energy, LLC | Line of Credit
Debt Instrument [Line Items]
Credit facilities	[1]		$ 2,215,000,000	$ 1,795,000,000
Linn Energy, LLC | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End			2.66%	1.92%
Linn Energy, LLC | Loans Payable
Debt Instrument [Line Items]
Term loan	[2]		$ 500,000,000	$ 500,000,000
Linn Energy, LLC | Loans Payable | Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End			3.17%	2.66%
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due May 2019
Debt Instrument [Line Items]
Senior notes, net			$ 562,234,000	$ 1,200,000,000
Debt Instrument, Interest Rate, Stated Percentage			6.50%
Par Value of Senior Notes Exchanged		584,422,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due November 2019
Debt Instrument [Line Items]
Senior notes, net			$ 581,402,000	1,800,000,000
Debt Instrument, Interest Rate, Stated Percentage			6.25%
Par Value of Senior Notes Exchanged		824,348,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Senior notes, net			$ 718,596,000	1,300,000,000
Par Value of Senior Notes Exchanged		286,344,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2021
Debt Instrument [Line Items]
Senior notes, net			779,474,000	1,000,000,000
Par Value of Senior Notes Exchanged		184,300,000
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021
Debt Instrument [Line Items]
Senior notes, net			$ 381,423,000	650,000,000
Debt Instrument, Interest Rate, Stated Percentage			6.50%
Par Value of Senior Notes Exchanged		$ 120,586,000
Linn Energy, LLC | Senior Secured Notes [Member] | Senior Secured Second Lien Notes Due 2020 [Member]
Debt Instrument [Line Items]
Senior secured second lien notes	[3]		$ 1,000,000,000	0
Debt Instrument, Face Amount			$ 1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage			12.00%
Linn Energy, LLC | Secured Debt [Member] | Senior Secured Second Lien Notes Due 2020 [Member]
Debt Instrument [Line Items]
Interest payable on second lien notes			$ 608,333,000	0
Berry | Line of Credit
Debt Instrument [Line Items]
Credit facilities	[4]		$ 873,175,000	$ 1,173,175,000
Berry | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End			3.17%	2.67%
Berry | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Senior notes, net			$ 261,100,000	$ 299,970,000
Berry | Senior Notes [Member] | Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes, net			$ 572,700,000	$ 599,163,000
Debt Instrument, Interest Rate, Stated Percentage			6.375%
[1]	Variable interest rates of 2.66% and 1.92% at December 31, 2015, and December 31, 2014, respectively.
[2]	Variable interest rates of 3.17% and 2.66% at December 31, 2015 and December 31, 2014, respectively.
[3]	In November 2015, the Company issued $1.0 billion in aggregate principal amount of new 12.00% senior secured second lien notes due December 2020 in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes. See below for additional details.(5) Due to existing and anticipated covenant violations, the Company’s Credit Facilities and term loan were classified as current at December 31, 2015. The current portion also includes approximately $128 million of interest payable on the Second Lien Notes due within one year.
[4]	Variable interest rates of 3.17% and 2.67% at December 31, 2015, and December 31, 2014, respectively.

Debt Debt Fair Value Disclosure

Debt Debt Fair Value Disclosure (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Carrying Value
Credit facilities	$ 3,088,175	$ 2,968,175
Term loan	500,000	500,000
Senior secured second lien notes	1,000,000	0
Interest payable on second lien notes	608,333	0
Senior notes, net	3,848,235	6,827,634
Total debt, net	9,044,743	10,295,809
Fair Value
Credit facilities	3,088,175	2,968,175
Term loan	500,000	500,000
Senior secured second lien notes	501,250	0
Interest payable on second lien notes	608,333	0
Senior notes, net	662,179	5,703,649
Total debt, net	$ 5,359,937	$ 9,171,824

Debt Debt Exchange (Details)

Debt Debt Exchange (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	12 Months Ended
	Nov. 30, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	$ 2,000,000
Gains (Losses) on Restructuring of Debt		$ 352,000
Troubled Debt Restructuring, Debtor, Current Period, Gain (Loss) on Restructuring, Per Share, Net		$ 1.03
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due September 2021
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	120,586
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2021
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	184,300
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	286,344
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due November 2019
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	824,348
Linn Energy, LLC | Senior Notes [Member] | Senior Notes Due May 2019
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	$ 584,422

Derivatives (Commodity Derivati

Derivatives (Commodity Derivatives) (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2015USD ($)$ / MMBTU$ / bblMBblsMMMBTU	Dec. 31, 2014USD ($)$ / MMBTU$ / bblMBblsMMMBTU	Dec. 31, 2013USD ($)$ / MMBTU$ / bblMBblsMMMBTU
Derivative [Line Items]
Cash settlements on canceled derivatives | $		$ 4,679	$ 12,281	$ 0
Volumes of natural gas production on settled derivatives (in MMMbtu) | MMMBTU		189,895	177,029	173,488
Average contract price per MMBtu on settled derivatives | $ / MMBTU		5.12	5.14	5.29
Volumes of oil production on settled derivatives (in MBbls) | MBbls		18,884	24,988	15,590
Average contract price per barrel on settled derivatives | $ / bbl		89.28	92.39	95.35
2016 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU		121,841
Average Fixed Price (in usd per energy unit) | $ / MMBTU		4.20
2016 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU		76,269
Average Price (in usd per energy unit) | $ / MMBTU		5
2016 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	[1]	11,465
Average Fixed Price (in usd per energy unit) | $ / bbl	[1]	90.56
2016 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls		3,271
Average Price (in usd per energy unit) | $ / bbl		90
2016 | Natural Gas Basis Differential Positions | Panhandle basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	59,954
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.32)
2016 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	65,794
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.24)
2016 | Natural Gas Basis Differential Positions | MichCon basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	7,768
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	0.05
2016 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	34,364
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.02)
2016 | Natural Gas Basis Differential Positions | Permian basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	2,975
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.20)
2016 | Natural Gas Basis Differential Positions | SoCal basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[3],[4]	32,940
Hedged Differential (in usd per energy unit) | $ / MMBTU	[3],[4]	(0.03)
2016 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	[5]	2,652
Hedged Differential (in usd per energy unit) | $ / bbl	[5]	0.25
2017 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU		120,122
Average Fixed Price (in usd per energy unit) | $ / MMBTU		4.26
2017 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU		66,886
Average Price (in usd per energy unit) | $ / MMBTU		4.88
2017 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	[1]	4,755
Average Fixed Price (in usd per energy unit) | $ / bbl	[1]	89.02
2017 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls		384
Average Price (in usd per energy unit) | $ / bbl		90
2017 | Natural Gas Basis Differential Positions | Panhandle basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	59,138
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.33)
2017 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	38,880
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.19)
2017 | Natural Gas Basis Differential Positions | MichCon basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	7,437
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	0.05
2017 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	36,730
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.02)
2017 | Natural Gas Basis Differential Positions | Permian basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	2,629
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.20)
2017 | Natural Gas Basis Differential Positions | SoCal basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[3],[4]	0
Hedged Differential (in usd per energy unit) | $ / MMBTU	[3],[4]	0
2017 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	[5]	2,654
Hedged Differential (in usd per energy unit) | $ / bbl	[5]	0.25
2018 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU		36,500
Average Fixed Price (in usd per energy unit) | $ / MMBTU		5
2018 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU		0
Average Price (in usd per energy unit) | $ / MMBTU		0
2018 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	[1]	0
Average Fixed Price (in usd per energy unit) | $ / bbl	[1]	0
2018 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls		0
Average Price (in usd per energy unit) | $ / bbl		0
2018 | Oil Derivative Instruments | Extendible Fixed Price Swaps
Derivative [Line Items]
Average Fixed Price (in usd per energy unit) | $ / bbl		100
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls) | MBbls		5,384
2018 | Natural Gas Basis Differential Positions | Panhandle basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	16,425
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.33)
2018 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	10,804
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.19)
2018 | Natural Gas Basis Differential Positions | MichCon basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	2,044
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	0.05
2018 | Natural Gas Basis Differential Positions | Houston Ship Channel basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	986
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.08)
2018 | Natural Gas Basis Differential Positions | Permian basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[2],[3]	1,314
Hedged Differential (in usd per energy unit) | $ / MMBTU	[2],[3]	(0.20)
2018 | Natural Gas Basis Differential Positions | SoCal basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	[3],[4]	0
Hedged Differential (in usd per energy unit) | $ / MMBTU	[3],[4]	0
2018 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	[5]	0
Hedged Differential (in usd per energy unit) | $ / bbl	[5]	0
2019 | Oil Derivative Instruments | Extendible Fixed Price Swaps
Derivative [Line Items]
Average Fixed Price (in usd per energy unit) | $ / bbl		90
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls) | MBbls		5,384
[1]	Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for the year ending December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, at counterparty election on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.
[2]	For positions which hedge exposure to differentials in producing areas, the Company receives the NYMEX Henry Hub natural gas price plus the respective spread and pays the specified index price. Cash settlements are made on a net basis.
[3]	Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.
[4]	For positions which hedge exposure to differentials in consuming areas, the Company pays the NYMEX Henry Hub natural gas price plus the respective spread and receives the specified index price. Cash settlements are made on a net basis.
[5]	The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

Derivatives (Balance Sheet Pres

Derivatives (Balance Sheet Presentation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Assets:
Commodity derivatives	$ 1,812,375	$ 2,014,815
Liabilities:
Commodity derivatives	28,842	$ 90,260
Maximum Loss Upon All Counterparties Failing To Perform	$ 1,800,000

Derivatives Gains (Losses) on D

Derivatives Gains (Losses) on Derivatives (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Gains on oil and natural gas derivatives		$ 273,567	$ 549,029	$ (191,188)	$ 424,781	$ 1,404,758	$ 451,702	$ (408,788)	$ (241,493)	$ 1,063,082	$ 1,206,179	$ 177,857
Cash Settlements On Derivatives including canceled derivatives										1,200,000	108,000	249,000
Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gains on oil and natural gas derivatives										1,056,189	1,206,179	177,857
Lease Operating Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gains on oil and natural gas derivatives	[1]									$ 6,893	$ 0	$ 0
[1]	Consists of gains and (losses) on derivatives used to hedge exposure to differentials in consuming areas, which were entered into in March 2015.

Fair Value Measurements on a 59

Fair Value Measurements on a Recurring Basis (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Assets:
Commodity derivatives		$ 1,812,375	$ 2,014,815
Commodity derivatives	[1]	(25,744)	(89,576)
Commodity derivatives		1,786,631	1,925,239
Liabilities:
Commodity derivatives		28,842	90,260
Commodity derivatives	[1]	(25,744)	(89,576)
Commodity derivatives		$ 3,098	$ 684
[1]	Represents counterparty netting under agreements governing such derivatives.

Other Property and Equipment (D

Other Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 708,711	$ 669,149
Less accumulated depreciation	(195,661)	(144,282)
Other property and equipment, net	513,050	524,867
Gas Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	480,161	479,754
Building and Building Improvements [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	72,976	49,046
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	37,641	36,534
Upstream Equipment [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	7,934	6,994
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	106,462	88,893
Land [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 3,537	$ 7,928

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Future inflation factor used in the calculation of the asset retirement obligations	2.00%	2.00%	2.00%
Credit adjusted risk-free interest rate for the calculation of the asset retirement obligations	5.50%	5.30%	6.20%
Asset retirement obligations rollforward
Asset retirement obligations at beginning of year	$ 497,570	$ 289,321
Liabilities added from acquisitions	0	176,538
Liabilities added from drilling	3,574	10,476
Liabilities associated with assets divested	(3,306)	(25,656)
Current year accretion expense	30,016	22,164
Settlements	(6,336)	(12,620)
Revision of estimates	2,023	37,347
Asset retirement obligations at end of year	$ 523,541	$ 497,570	$ 289,321

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended	12 Months Ended			48 Months Ended
	Mar. 31, 2011	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015
Loss Contingency, Estimate [Abstract]
Litigation Settlement, Amount	$ 51
Proceeds from Legal Settlements			$ 4	$ 7	$ 11	$ 50
Payments for Legal Settlements		$ 0

Operating Leases (Details)

Operating Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Leases, Operating [Abstract]
Operating lease expense	$ 21,000	$ 14,000	$ 7,000
Future Minimum Lease Payments [Abstract]
2,016	10,647
2,017	8,887
2,018	7,521
2,019	7,865
2,020	7,721
Thereafter	27,336
Operating Leases, Future Minimum Payments Due, Total	$ 69,977

Earnings Per Unit (Details)

Earnings Per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Net loss	$ (4,759,811)	$ (451,809)	$ (691,337)
Allocated to participating securities	(3,039)	(7,117)	(5,935)
Net loss attributable to common unitholders	$ (4,762,850)	$ (458,926)	$ (697,272)
Earnings per share reconciliation
Basic net loss per unit	$ (13.87)	$ (1.40)	$ (2.94)
Diluted net loss per unit	$ (13.87)	$ (1.40)	$ (2.94)
Weighted average units outstanding
Basic weighted average units outstanding	343,323	328,918	237,544
Dilutive effect of unit equivalents	0	0	0
Diluted weighted average units outstanding	343,323	328,918	237,544
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	6,000	4,000

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current taxes:
Federal	$ (12,021)	$ 473	$ 144
State	1,022	21	198
Deferred taxes:
Federal	8,237	(104)	(2,805)
State	(3,699)	4,047	264
Income tax expense (benefit)	(6,461)	4,437	$ (2,199)
Operating Loss Carryforwards [Line Items]
Material Uncertain Tax Position	$ 0	$ 0
Effective income tax rate reconciliation [Abstract]
Federal statutory rate	35.00%	35.00%	35.00%
State, net of federal tax benefit	0.10%	(0.90%)	(0.10%)
Loss excluded from nontaxable entities	(34.80%)	(34.60%)	(34.60%)
Other	(0.20%)	(0.50%)	0.00%
Effective rate	0.10%	(1.00%)	0.30%
Deferred tax assets:
Net operating loss carryforwards	$ 370	$ 0
Unit-based compensation	18,214	22,105
Valuation allowance	(2,159)	0
Other	7,300	6,857
Total deferred tax assets	23,725	28,962
Deferred tax liabilities:
Property and equipment principally due to differences in depreciation	(12,534)	(10,991)
Other	8	(6,370)
Total deferred tax liabilities	(12,526)	(17,361)
Net deferred tax assets	11,199	11,601
Net deferred tax assets and liabilities classified in consolidated balance sheets [Abstract]
Deferred tax assets	23,188	28,442
Deferred tax liabilities	(675)	(2,964)
Other current assets	22,513	25,478
Deferred tax assets	537	520
Deferred tax liabilities	(11,314)	(13,877)
Deferred Tax Liabilities, Gross, Noncurrent	11,851	$ 14,397
Federal [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 1,000
Net operating loss carryforwards, expiration dates	Dec. 31, 2036

Supplemental Disclosures to t66

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Balance Sheets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 257,363	$ 6,225
Accrued interest	63,957	105,310
Accrued compensation	37,061	44,875
Asset retirement obligations	14,234	16,187
Other	4,341	1,364
Other accrued liabilities	119,593	167,736
Net Outstanding Checks	21,000	95,000
Restricted Cash for Debt Agreement [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	250,000
Restricted Cash for ARO [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 7,000	$ 6,000

Supplemental Disclosures to t67

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Cash Flows) (Details) - USD ($)	1 Months Ended	12 Months Ended
	Nov. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	$ 2,000,000,000
Cash payments for interest, net of amounts capitalized		$ 562,303,000	$ 542,775,000	$ 392,607,000
Cash payments for income taxes		643,000	0	14,000
Joint-venture funding			25,000,000	170,000,000
In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follow:
Fair value of assets acquired		0	2,679,547,000	5,726,681,000
Cash paid, net of cash acquired		0	(2,395,339,000)	(109,350,000)
Units issued in connection with the Berry acquisition		0	0	(2,781,888,000)
Noncash gains on exchanges of properties		0	(85,493,000)	0
Receivables from sellers		0	16,213,000	(93,000)
Payables to sellers		0	(3,515,000)	(6,854,000)
Liabilities assumed		0	211,413,000	2,828,496,000
Accrued capital expenditures		81,656,000	$ 240,331,000	$ 334,542,000
Senior Secured Second Lien Notes Due 2020 [Member] | Linn Energy, LLC | Senior Secured Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 1,000,000,000

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	Dec. 17, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 16, 2013
Related Party Transaction [Line Items]
General and administrative expenses		$ 296,887	$ 293,073	$ 236,271
Share-based compensation expense		56,136	53,284	42,703
Distributions to unitholders		$ 323,878	962,048	682,241
LinnCo
Related Party Transaction [Line Items]
Ownership percentage		37.00%
General and administrative expenses		$ 3,000	3,000	42,000
Third party transaction costs related to the pending acquisition of Berry				40,000
Share-based compensation expense				9,000
Distributions to unitholders		121,000	373,000	101,000
Related party transaction, amounts of transaction		2,000	2,000	2,000
Berry
Related Party Transaction [Line Items]
Exchange ratio	168.00%
Director
Related Party Transaction [Line Items]
Related party transaction, amounts of transaction		$ 9,000	21,000	$ 26,000
Linn Energy, LLC | Berry
Related Party Transaction [Line Items]
LinnCo common shares issued to acquire Berry	93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674
Value of units issued to acquire Berry					$ 2,800,000
LinnCo | Berry
Related Party Transaction [Line Items]
LinnCo common shares issued to acquire Berry	93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674
FY 2013 [Member] | LinnCo
Related Party Transaction [Line Items]
General and administrative expenses paid on behalf of related party			$ 11,000
Business Acquisition, Berry
Related Party Transaction [Line Items]
Exchange ratio	168.00%
Business Acquisition, Berry | Linn Energy, LLC
Related Party Transaction [Line Items]
LinnCo common shares issued to acquire Berry	93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674
Business Acquisition, Berry | LinnCo
Related Party Transaction [Line Items]
LinnCo common shares issued to acquire Berry	93,756,674
LINN Energy units issued to LinnCo for LinnCo common shares issued	93,756,674

Subsidiary Guarantors Condensed

Subsidiary Guarantors Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 2,168	$ 1,809	$ 52,171	$ 1,243
Accounts receivable – trade, net	216,556	471,684
Accounts receivable – affiliates	0	0
Derivative instruments	1,220,230	1,077,142
Other current assets	119,921	155,955
Total current assets	1,558,875	1,706,590
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	18,121,155	18,068,900
Less accumulated depletion and amortization	(11,097,492)	(4,867,682)
Oil and natural gas properties, successful efforts method, net	7,023,663	13,201,218
Other property and equipment	708,711	669,149
Less accumulated depreciation	(195,661)	(144,282)
Other property and equipment, net	513,050	524,867
Derivative instruments	566,401	848,097
Restricted cash	257,363	6,225
Notes receivable – affiliates	0	0
Advance to affiliate		0
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	57,594	136,512
Noncurrent assets, excluding property, total	881,358	990,834
Total noncurrent assets	8,418,071	14,716,919
Total assets	9,976,946	16,423,509
Current liabilities:
Accounts payable and accrued expenses	455,374	814,809
Accounts payable – affiliates	0	0
Advance from affiliate		0
Derivative instruments	2,241	0
Other accrued liabilities	119,593	167,736
Current portion of long-term debt	3,716,508	0
Total current liabilities	4,293,716	982,545
Noncurrent liabilities:
Notes payable – affiliates	0	0
Derivative instruments	857	684
Total long-term debt, net	5,328,235	10,295,809
Other noncurrent liabilities	623,039	600,866
Total noncurrent liabilities	5,952,131	10,897,359
355,017,428 units and 331,974,913 units issued and outstanding at December 31, 2015, and December 31, 2014, respectively	5,343,116	5,395,811
Unitholders’ capital (deficit):
Accumulated income (deficit)	(5,612,017)	(852,206)
Total unitholders' capital (deficit)	(268,901)	4,543,605	5,891,427	4,427,180
Total liabilities and unitholders’ capital (deficit)	9,976,946	16,423,509
Eliminations
Current assets:
Cash and cash equivalents	0	0	0	0
Accounts receivable – trade, net	0	0
Accounts receivable – affiliates	(2,928,703)	(4,042,095)
Derivative instruments	0	0
Other current assets	(1)	0
Total current assets	(2,928,704)	(4,042,095)
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	0	0
Less accumulated depletion and amortization	55,956	0
Oil and natural gas properties, successful efforts method, net	55,956	0
Other property and equipment	0	0
Less accumulated depreciation	0	0
Other property and equipment, net	0	0
Derivative instruments	0	0
Restricted cash	0	0
Notes receivable – affiliates	(175,100)	(130,500)
Advance to affiliate		(293,627)
Investments in consolidated subsidiaries	(3,940,444)	(8,562,608)
Other noncurrent assets	0	0
Noncurrent assets, excluding property, total	(4,115,544)	(8,986,735)
Total noncurrent assets	(4,059,588)	(8,986,735)
Total assets	(6,988,292)	(13,028,830)
Current liabilities:
Accounts payable and accrued expenses	0	0
Accounts payable – affiliates	(2,928,703)	(4,042,095)
Advance from affiliate		(293,627)
Derivative instruments	0
Other accrued liabilities	(1)	0
Current portion of long-term debt	0
Total current liabilities	(2,928,704)	(4,335,722)
Noncurrent liabilities:
Notes payable – affiliates	(175,100)	(130,500)
Derivative instruments	0	0
Total long-term debt, net	0	0
Other noncurrent liabilities	0	0
Total noncurrent liabilities	(175,100)	(130,500)
355,017,428 units and 331,974,913 units issued and outstanding at December 31, 2015, and December 31, 2014, respectively	(7,621,189)	(7,240,658)
Unitholders’ capital (deficit):
Accumulated income (deficit)	3,736,701	(1,321,950)
Total unitholders' capital (deficit)	(3,884,488)	(8,562,608)
Total liabilities and unitholders’ capital (deficit)	(6,988,292)	(13,028,830)
Linn Energy, LLC | Reportable Legal Entities
Current assets:
Cash and cash equivalents	1,073	38	52	107
Accounts receivable – trade, net	0	0
Accounts receivable – affiliates	2,920,082	4,028,890
Derivative instruments	0	0
Other current assets	26,905	18
Total current assets	2,948,060	4,028,946
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	0	0
Less accumulated depletion and amortization	0	0
Oil and natural gas properties, successful efforts method, net	0	0
Other property and equipment	0	0
Less accumulated depreciation	0	0
Other property and equipment, net	0	0
Derivative instruments	0	0
Restricted cash	0	0
Notes receivable – affiliates	175,100	130,500
Advance to affiliate		0
Investments in consolidated subsidiaries	3,940,444	8,562,608
Other noncurrent assets	35,559	116,637
Noncurrent assets, excluding property, total	4,151,103	8,809,745
Total noncurrent assets	4,151,103	8,809,745
Total assets	7,099,163	12,838,691
Current liabilities:
Accounts payable and accrued expenses	1,285	3,784
Accounts payable – affiliates	0	0
Advance from affiliate		0
Derivative instruments	0
Other accrued liabilities	49,861	89,507
Current portion of long-term debt	2,843,333
Total current liabilities	2,894,479	93,291
Noncurrent liabilities:
Notes payable – affiliates	0	0
Derivative instruments	0	0
Total long-term debt, net	4,482,867	8,208,857
Other noncurrent liabilities	0	0
Total noncurrent liabilities	4,482,867	8,208,857
355,017,428 units and 331,974,913 units issued and outstanding at December 31, 2015, and December 31, 2014, respectively	5,333,834	5,388,749
Unitholders’ capital (deficit):
Accumulated income (deficit)	(5,612,017)	(852,206)
Total unitholders' capital (deficit)	(278,183)	4,536,543
Total liabilities and unitholders’ capital (deficit)	7,099,163	12,838,691
Guarantor Subsidiaries | Reportable Legal Entities
Current assets:
Cash and cash equivalents	72	185	1,078	1,136
Accounts receivable – trade, net	170,503	371,325
Accounts receivable – affiliates	8,621	13,205
Derivative instruments	1,207,012	1,033,448
Other current assets	72,120	96,678
Total current assets	1,458,328	1,514,841
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	13,110,094	13,196,841
Less accumulated depletion and amortization	(9,557,283)	(4,342,675)
Oil and natural gas properties, successful efforts method, net	3,552,811	8,854,166
Other property and equipment	597,216	553,150
Less accumulated depreciation	(183,139)	(135,830)
Other property and equipment, net	414,077	417,320
Derivative instruments	566,401	848,097
Restricted cash	7,004	6,100
Notes receivable – affiliates	0	0
Advance to affiliate		0
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	5,978	5,716
Noncurrent assets, excluding property, total	579,383	859,913
Total noncurrent assets	4,546,271	10,131,399
Total assets	6,004,599	11,646,240
Current liabilities:
Accounts payable and accrued expenses	336,962	581,880
Accounts payable – affiliates	2,920,082	4,028,890
Advance from affiliate		293,627
Derivative instruments	0
Other accrued liabilities	52,997	59,142
Current portion of long-term debt	0
Total current liabilities	3,310,041	4,963,539
Noncurrent liabilities:
Notes payable – affiliates	175,100	130,500
Derivative instruments	857	684
Total long-term debt, net	0	0
Other noncurrent liabilities	410,990	400,851
Total noncurrent liabilities	586,947	532,035
355,017,428 units and 331,974,913 units issued and outstanding at December 31, 2015, and December 31, 2014, respectively	4,831,758	4,831,339
Unitholders’ capital (deficit):
Accumulated income (deficit)	(2,724,147)	1,319,327
Total unitholders' capital (deficit)	2,107,611	6,150,666
Total liabilities and unitholders’ capital (deficit)	6,004,599	11,646,240
Non-Guarantor Subsidiary | Reportable Legal Entities
Current assets:
Cash and cash equivalents	1,023	1,586	$ 51,041	$ 0
Accounts receivable – trade, net	46,053	100,359
Accounts receivable – affiliates	0	0
Derivative instruments	13,218	43,694
Other current assets	20,897	59,259
Total current assets	81,191	204,898
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	5,011,061	4,872,059
Less accumulated depletion and amortization	(1,596,165)	(525,007)
Oil and natural gas properties, successful efforts method, net	3,414,896	4,347,052
Other property and equipment	111,495	115,999
Less accumulated depreciation	(12,522)	(8,452)
Other property and equipment, net	98,973	107,547
Derivative instruments	0	0
Restricted cash	250,359	125
Notes receivable – affiliates	0	0
Advance to affiliate		293,627
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	16,057	14,159
Noncurrent assets, excluding property, total	266,416	307,911
Total noncurrent assets	3,780,285	4,762,510
Total assets	3,861,476	4,967,408
Current liabilities:
Accounts payable and accrued expenses	117,127	229,145
Accounts payable – affiliates	8,621	13,205
Advance from affiliate		0
Derivative instruments	2,241
Other accrued liabilities	16,736	19,087
Current portion of long-term debt	873,175
Total current liabilities	1,017,900	261,437
Noncurrent liabilities:
Notes payable – affiliates	0	0
Derivative instruments	0	0
Total long-term debt, net	845,368	2,086,952
Other noncurrent liabilities	212,049	200,015
Total noncurrent liabilities	1,057,417	2,286,967
355,017,428 units and 331,974,913 units issued and outstanding at December 31, 2015, and December 31, 2014, respectively	2,798,713	2,416,381
Unitholders’ capital (deficit):
Accumulated income (deficit)	(1,012,554)	2,623
Total unitholders' capital (deficit)	1,786,159	2,419,004
Total liabilities and unitholders’ capital (deficit)	$ 3,861,476	$ 4,967,408

Subsidiary Guarantors Condens70

Subsidiary Guarantors Condensed Consolidating Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues and other:
Oil, natural gas and natural gas liquids sales	$ 352,038	$ 427,245	$ 496,419	$ 450,569	$ 766,354	$ 937,458	$ 967,850	$ 938,877	$ 1,726,271	$ 3,610,539	$ 2,073,240
Gains on oil and natural gas derivatives									1,056,189	1,206,179	177,857
Marketing revenues									74,129	135,260	54,171
Other revenues									26,745	31,325	26,387
Total revenues	646,655	998,304	321,828	916,547	2,217,650	1,435,115	596,951	733,587	2,883,334	4,983,303	2,331,655
Expenses:
Lease operating expenses									617,764	805,164	372,523
Transportation expenses									219,721	207,331	128,440
Marketing expenses									57,144	117,465	37,892
General and administrative expenses									296,887	293,073	236,271
Exploration costs									9,473	125,037	5,251
Depreciation, depletion and amortization									805,757	1,073,902	829,311
Impairment of long-lived assets									5,813,954	2,303,749	828,317
Taxes, other than income taxes									181,895	267,403	138,631
(Gains) losses on sale of assets and other, net	(146)	(166,980)	(17,996)	(12,287)	(338,750)	(35,803)	5,467	2,586	(197,409)	(366,500)	13,637
Total expenses									7,805,186	4,826,624	2,590,273
Other income and (expenses):
Interest expense, net of amounts capitalized									(546,453)	(587,838)	(421,137)
Interest expense – affiliates									0	0	0
Interest income – affiliates									0	0	0
Gain (loss) on extinguishment of debt									719,259	0	(5,304)
Equity in earnings from consolidated subsidiaries									0	0	0
Other, net									(17,226)	(16,213)	(8,477)
Total other income and (expenses)									155,580	(604,051)	(434,918)
Loss before income taxes									(4,766,272)	(447,372)	(693,536)
Income tax expense (benefit)									(6,461)	4,437	(2,199)
Net loss	$ (2,472,207)	$ (1,569,317)	$ (379,127)	$ (339,160)	$ (154,502)	$ (4,100)	$ (207,870)	$ (85,337)	(4,759,811)	(451,809)	(691,337)
Eliminations
Revenues and other:
Oil, natural gas and natural gas liquids sales									0	0	0
Gains on oil and natural gas derivatives									0	0	0
Marketing revenues									0	0	0
Other revenues									0	0	0
Total revenues									0	0	0
Expenses:
Lease operating expenses									0	0	0
Transportation expenses									0	0	0
Marketing expenses									0	0	0
General and administrative expenses									0	0	0
Exploration costs									0	0	0
Depreciation, depletion and amortization									6,711	0	0
Impairment of long-lived assets									(64,800)	0	0
Taxes, other than income taxes									0	0	0
(Gains) losses on sale of assets and other, net									0	0	0
Total expenses									(58,089)	0	0
Other income and (expenses):
Interest expense, net of amounts capitalized									0	0	0
Interest expense – affiliates									12,123	7,954	5,543
Interest income – affiliates									(12,123)	(7,954)	(5,543)
Gain (loss) on extinguishment of debt									0		0
Equity in earnings from consolidated subsidiaries									5,002,695	(28,397)	266,899
Other, net									0	0	0
Total other income and (expenses)									5,002,695	(28,397)	266,899
Loss before income taxes									5,060,784	(28,397)	266,899
Income tax expense (benefit)									0	0	0
Net loss									5,060,784	(28,397)	266,899
Linn Energy, LLC | Reportable Legal Entities
Revenues and other:
Oil, natural gas and natural gas liquids sales									0	0	0
Gains on oil and natural gas derivatives									0	0	0
Marketing revenues									0	0	0
Other revenues									0	0	0
Total revenues									0	0	0
Expenses:
Lease operating expenses									0	0	0
Transportation expenses									0	0	0
Marketing expenses									0	0	0
General and administrative expenses									0	0	0
Exploration costs									0	0	0
Depreciation, depletion and amortization									0	0	0
Impairment of long-lived assets									0	0	0
Taxes, other than income taxes									2	40	0
(Gains) losses on sale of assets and other, net									0	0	724
Total expenses									2	40	724
Other income and (expenses):
Interest expense, net of amounts capitalized									(463,168)	(480,259)	(415,670)
Interest expense – affiliates									0	0	0
Interest income – affiliates									12,123	7,954	5,543
Gain (loss) on extinguishment of debt									708,050		(5,304)
Equity in earnings from consolidated subsidiaries									(5,002,695)	28,397	(266,899)
Other, net									(13,804)	(7,861)	(8,283)
Total other income and (expenses)									(4,759,494)	(451,769)	(690,613)
Loss before income taxes									(4,759,496)	(451,809)	(691,337)
Income tax expense (benefit)									315	0	0
Net loss									(4,759,811)	(451,809)	(691,337)
Guarantor Subsidiaries | Reportable Legal Entities
Revenues and other:
Oil, natural gas and natural gas liquids sales									1,151,240	2,312,137	2,022,916
Gains on oil and natural gas derivatives									1,027,014	1,127,395	182,906
Marketing revenues									43,876	84,349	52,328
Other revenues									19,550	28,133	26,387
Total revenues									2,241,680	3,552,014	2,284,537
Expenses:
Lease operating expenses									372,609	440,624	357,113
Transportation expenses									167,561	165,489	125,864
Marketing expenses									35,278	81,210	36,259
General and administrative expenses									210,894	190,286	215,973
Exploration costs									9,473	125,037	5,251
Depreciation, depletion and amortization									547,675	771,549	818,466
Impairment of long-lived assets									5,024,944	2,050,387	828,317
Taxes, other than income taxes									111,300	169,655	136,501
(Gains) losses on sale of assets and other, net									(195,490)	(487,286)	2,705
Total expenses									6,284,244	3,506,951	2,526,449
Other income and (expenses):
Interest expense, net of amounts capitalized									2,533	(19,631)	(1,504)
Interest expense – affiliates									(12,123)	(7,954)	(5,543)
Interest income – affiliates									0	0	0
Gain (loss) on extinguishment of debt									0		0
Equity in earnings from consolidated subsidiaries									0	0	0
Other, net									(161)	(7,309)	(166)
Total other income and (expenses)									(9,751)	(34,894)	(7,213)
Loss before income taxes									(4,052,315)	10,169	(249,125)
Income tax expense (benefit)									(6,708)	4,368	(2,199)
Net loss									(4,045,607)	5,801	(246,926)
Non-Guarantor Subsidiary | Reportable Legal Entities
Revenues and other:
Oil, natural gas and natural gas liquids sales									575,031	1,298,402	50,324
Gains on oil and natural gas derivatives									29,175	78,784	(5,049)
Marketing revenues									30,253	50,911	1,843
Other revenues									7,195	3,192	0
Total revenues									641,654	1,431,289	47,118
Expenses:
Lease operating expenses									245,155	364,540	15,410
Transportation expenses									52,160	41,842	2,576
Marketing expenses									21,866	36,255	1,633
General and administrative expenses									85,993	102,787	20,298
Exploration costs									0	0	0
Depreciation, depletion and amortization									251,371	302,353	10,845
Impairment of long-lived assets									853,810	253,362	0
Taxes, other than income taxes									70,593	97,708	2,130
(Gains) losses on sale of assets and other, net									(1,919)	120,786	10,208
Total expenses									1,579,029	1,319,633	63,100
Other income and (expenses):
Interest expense, net of amounts capitalized									(85,818)	(87,948)	(3,963)
Interest expense – affiliates									0	0	0
Interest income – affiliates									0	0	0
Gain (loss) on extinguishment of debt									11,209		0
Equity in earnings from consolidated subsidiaries									0	0	0
Other, net									(3,261)	(1,043)	(28)
Total other income and (expenses)									(77,870)	(88,991)	(3,991)
Loss before income taxes									(1,015,245)	22,665	(19,973)
Income tax expense (benefit)									(68)	69	0
Net loss									$ (1,015,177)	$ 22,596	$ (19,973)

Subsidiary Guarantors Condens71

Subsidiary Guarantors Condensed Consolidating Statements of Cash Flow (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flow from operating activities:
Net loss	$ (2,472,207)	$ (1,569,317)	$ (379,127)	$ (339,160)	$ (154,502)	$ (4,100)	$ (207,870)	$ (85,337)	$ (4,759,811)	$ (451,809)	$ (691,337)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization									805,757	1,073,902	829,311
Impairment of long-lived assets									5,813,954	2,303,749	828,317
Unit-based compensation expenses									56,136	53,284	42,703
Amortization and write-off of deferred financing fees									34,743	50,926	21,507
Gain loss on sale of assets and other, net									(189,161)	(261,571)	37,232
(Gain) loss on extinguishment of debt									(719,259)	0	5,304
Equity in earnings from consolidated subsidiaries									0	0	0
Deferred Income Tax Expense (Benefit)									4,538	3,943	(2,541)
Derivatives activities:
Total gains	(273,567)	$ (549,029)	$ 191,188	(424,781)	(1,404,758)	$ (451,702)	$ 408,788	241,493	(1,063,082)	(1,206,179)	(177,857)
Cash settlements									1,199,410	95,514	248,862
Cash settlements on canceled derivatives									4,679	12,281	0
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net									267,241	5,064	89,188
Increase in accounts receivable – affiliates									0	0	0
(Increase) decrease in other assets									9,582	(17,824)	16,179
Increase (decrease) in accounts payable and accrued expenses									(156,394)	99,029	(76,993)
Decrease in accounts payable and accrued expenses – affiliates									0	0	0
Increase in accounts payable and accrued expenses – affiliates									0	0	0
Decrease in other liabilities									(58,876)	(48,419)	(3,663)
Net cash provided by operating activities									1,249,457	1,711,890	1,166,212
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired									0	(2,479,252)	(279,213)
Development of oil and natural gas properties									(608,889)	(1,569,877)	(1,078,025)
Purchases of other property and equipment									(66,708)	(74,540)	(92,352)
Investment in affiliates									0	0	0
Change in notes receivable with affiliate									0	0	0
Repayment of Notes Receivable from Related Parties									0
Proceeds from sale of properties and equipment and other									368,295	2,203,565	196,273
Net cash used in investing activities									(307,302)	(1,920,104)	(1,253,317)
Proceeds from sale of units									233,427	0	0
Cash flow from financing activities:
Proceeds from borrowings									1,445,000	5,940,024	2,230,000
Repayments of Long-term Debt									(2,183,879)	(4,811,124)	(1,404,898)
Distributions to unitholders									(323,878)	(962,048)	(682,241)
Payment of Financing and Stock Issuance Costs									(28,055)	(69,694)	(16,033)
Change in note payable with affiliate									0	0	0
Proceeds from Contributions from Parent									0	0
Payments of Distributions to Affiliates											0
Proceeds from (Repayments of) Related Party Debt									0
Excess tax benefit from unit-based compensation										766	160
Excess tax benefit from unit-based compensation									(9,467)
Other									(74,944)	59,928	11,045
Net cash provided by (used in) financing activities									(941,796)	157,852	138,033
Net increase (decrease) in cash and cash equivalents									359	(50,362)	50,928
Cash and cash equivalents:
Beginning				1,809				52,171	1,809	52,171	1,243
Ending	2,168				1,809				2,168	1,809	52,171
Eliminations
Cash flow from operating activities:
Net loss									5,060,784	(28,397)	266,899
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization									6,711	0	0
Impairment of long-lived assets									(64,800)	0	0
Unit-based compensation expenses									0	0	0
Amortization and write-off of deferred financing fees									0	0	0
Gain loss on sale of assets and other, net									0	0	0
(Gain) loss on extinguishment of debt									0		0
Equity in earnings from consolidated subsidiaries									(5,002,695)	28,397	(266,899)
Deferred Income Tax Expense (Benefit)									0	0	0
Derivatives activities:
Total gains									0	0	0
Cash settlements									0	0	0
Cash settlements on canceled derivatives									0	0
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net									0	0	0
Increase in accounts receivable – affiliates									(1,172,407)	(274,435)	137,917
(Increase) decrease in other assets									0	0	0
Increase (decrease) in accounts payable and accrued expenses									0	0	0
Decrease in accounts payable and accrued expenses – affiliates									1,172,407	274,435	(137,917)
Increase in accounts payable and accrued expenses – affiliates									1,172,407	274,435	(137,917)
Decrease in other liabilities									0	0	0
Net cash provided by operating activities									0	0	0
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired										0	0
Development of oil and natural gas properties									0	0	0
Purchases of other property and equipment									0	0	0
Investment in affiliates									(132,332)	(100,921)	435,000
Change in notes receivable with affiliate									44,600	44,300	26,700
Repayment of Notes Receivable from Related Parties									(129,217)
Proceeds from sale of properties and equipment and other									0	0	0
Net cash used in investing activities									47,715	145,221	(408,300)
Proceeds from sale of units									0
Cash flow from financing activities:
Proceeds from borrowings									0	0	0
Repayments of Long-term Debt									0	0	0
Distributions to unitholders									0	0	0
Payment of Financing and Stock Issuance Costs									0	0	0
Change in note payable with affiliate									(44,600)	(44,300)	(26,700)
Proceeds from Contributions from Parent									(132,332)	(100,921)
Payments of Distributions to Affiliates											435,000
Proceeds from (Repayments of) Related Party Debt									129,217
Excess tax benefit from unit-based compensation										0	0
Excess tax benefit from unit-based compensation									0
Other									0	0	0
Net cash provided by (used in) financing activities									(47,715)	(145,221)	408,300
Net increase (decrease) in cash and cash equivalents									0	0	0
Cash and cash equivalents:
Beginning				0				0	0	0	0
Ending	0				0				0	0	0
Linn Energy, LLC | Reportable Legal Entities
Cash flow from operating activities:
Net loss									(4,759,811)	(451,809)	(691,337)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization									0	0	0
Impairment of long-lived assets									0	0	0
Unit-based compensation expenses									0	0	0
Amortization and write-off of deferred financing fees									30,993	38,785	22,122
Gain loss on sale of assets and other, net									0	0	0
(Gain) loss on extinguishment of debt									(708,050)		5,304
Equity in earnings from consolidated subsidiaries									5,002,695	(28,397)	266,899
Deferred Income Tax Expense (Benefit)									0	0	0
Derivatives activities:
Total gains									0	0	0
Cash settlements									0	0	0
Cash settlements on canceled derivatives									0	0
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net									0	0	0
Increase in accounts receivable – affiliates									1,167,823	257,485	(120,967)
(Increase) decrease in other assets									0	312	(330)
Increase (decrease) in accounts payable and accrued expenses									(14)	0	178
Decrease in accounts payable and accrued expenses – affiliates									0	0	0
Increase in accounts payable and accrued expenses – affiliates									0	0	0
Decrease in other liabilities									(39,646)	14,465	2,092
Net cash provided by operating activities									693,990	(169,159)	(516,039)
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired										0	0
Development of oil and natural gas properties									0	0	0
Purchases of other property and equipment									0	0	0
Investment in affiliates									132,332	100,921	(435,000)
Change in notes receivable with affiliate									(44,600)	(44,300)	(26,700)
Repayment of Notes Receivable from Related Parties									0
Proceeds from sale of properties and equipment and other									(3,430)	(14,117)	(22,039)
Net cash used in investing activities									(180,362)	(159,338)	386,261
Proceeds from sale of units									233,427
Cash flow from financing activities:
Proceeds from borrowings									1,445,000	4,640,024	2,230,000
Repayments of Long-term Debt									(1,828,461)	(3,305,000)	(1,404,898)
Distributions to unitholders									(323,878)	(962,048)	(682,241)
Payment of Financing and Stock Issuance Costs									(26,678)	(59,048)	(16,033)
Change in note payable with affiliate									0	0	0
Proceeds from Contributions from Parent									0	0
Payments of Distributions to Affiliates											0
Proceeds from (Repayments of) Related Party Debt									0
Excess tax benefit from unit-based compensation										810	0
Excess tax benefit from unit-based compensation									(9,467)
Other									(2,536)	13,745	2,895
Net cash provided by (used in) financing activities									(512,593)	328,483	129,723
Net increase (decrease) in cash and cash equivalents									1,035	(14)	(55)
Cash and cash equivalents:
Beginning				38				52	38	52	107
Ending	1,073				38				1,073	38	52
Guarantor Subsidiaries | Reportable Legal Entities
Cash flow from operating activities:
Net loss									(4,045,607)	5,801	(246,926)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization									547,675	771,549	818,466
Impairment of long-lived assets									5,024,944	2,050,387	828,317
Unit-based compensation expenses									56,136	53,284	42,703
Amortization and write-off of deferred financing fees									0	17,054	0
Gain loss on sale of assets and other, net									(188,200)	(372,945)	37,232
(Gain) loss on extinguishment of debt									0		0
Equity in earnings from consolidated subsidiaries									0	0	0
Deferred Income Tax Expense (Benefit)									4,606	3,874	(2,541)
Derivatives activities:
Total gains									(1,027,014)	(1,127,395)	(182,906)
Cash settlements									1,130,640	88,776	248,862
Cash settlements on canceled derivatives									4,679	0
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net									207,300	(11,419)	17,754
Increase in accounts receivable – affiliates									4,584	16,950	(16,950)
(Increase) decrease in other assets									(9,142)	(2,187)	5,896
Increase (decrease) in accounts payable and accrued expenses									(98,209)	99,003	(52,143)
Decrease in accounts payable and accrued expenses – affiliates									(1,167,823)	(270,690)	120,967
Increase in accounts payable and accrued expenses – affiliates									(1,167,823)	(270,690)	120,967
Decrease in other liabilities									(11,620)	(24,473)	6,842
Net cash provided by operating activities									432,949	1,297,569	1,625,573
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired										(2,475,315)	(730,326)
Development of oil and natural gas properties									(576,256)	(1,061,395)	(1,060,547)
Purchases of other property and equipment									(48,967)	(63,070)	(92,352)
Investment in affiliates									0	0	0
Change in notes receivable with affiliate									0	0	0
Repayment of Notes Receivable from Related Parties									0
Proceeds from sale of properties and equipment and other									349,200	2,210,015	218,312
Net cash used in investing activities									(276,023)	(1,389,765)	(1,664,913)
Proceeds from sale of units									0
Cash flow from financing activities:
Proceeds from borrowings									0	1,300,000	0
Repayments of Long-term Debt									0	(1,300,000)	0
Distributions to unitholders									0	0	0
Payment of Financing and Stock Issuance Costs									0	0	0
Change in note payable with affiliate									44,600	44,300	26,700
Proceeds from Contributions from Parent									0	0
Payments of Distributions to Affiliates											0
Proceeds from (Repayments of) Related Party Debt									(129,217)
Excess tax benefit from unit-based compensation										(44)	160
Excess tax benefit from unit-based compensation									0
Other									(72,422)	47,047	12,422
Net cash provided by (used in) financing activities									(157,039)	91,303	39,282
Net increase (decrease) in cash and cash equivalents									(113)	(893)	(58)
Cash and cash equivalents:
Beginning				185				1,078	185	1,078	1,136
Ending	72				185				72	185	1,078
Non-Guarantor Subsidiary | Reportable Legal Entities
Cash flow from operating activities:
Net loss									(1,015,177)	22,596	(19,973)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization									251,371	302,353	10,845
Impairment of long-lived assets									853,810	253,362	0
Unit-based compensation expenses									0	0	0
Amortization and write-off of deferred financing fees									3,750	(4,913)	(615)
Gain loss on sale of assets and other, net									(961)	111,374	0
(Gain) loss on extinguishment of debt									(11,209)		0
Equity in earnings from consolidated subsidiaries									0	0	0
Deferred Income Tax Expense (Benefit)									(68)	69	0
Derivatives activities:
Total gains									(36,068)	(78,784)	5,049
Cash settlements									68,770	6,738	0
Cash settlements on canceled derivatives									0	12,281
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net									59,941	16,483	71,434
Increase in accounts receivable – affiliates									0	0	0
(Increase) decrease in other assets									18,724	(15,949)	10,613
Increase (decrease) in accounts payable and accrued expenses									(58,171)	26	(25,028)
Decrease in accounts payable and accrued expenses – affiliates									(4,584)	(3,745)	16,950
Increase in accounts payable and accrued expenses – affiliates									(4,584)	(3,745)	16,950
Decrease in other liabilities									(7,610)	(38,411)	(12,597)
Net cash provided by operating activities									122,518	583,480	56,678
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired										(3,937)	451,113
Development of oil and natural gas properties									(32,633)	(508,482)	(17,478)
Purchases of other property and equipment									(17,741)	(11,470)	0
Investment in affiliates									0	0	0
Change in notes receivable with affiliate									0	0	0
Repayment of Notes Receivable from Related Parties									129,217
Proceeds from sale of properties and equipment and other									22,525	7,667	0
Net cash used in investing activities									101,368	(516,222)	433,635
Proceeds from sale of units									0
Cash flow from financing activities:
Proceeds from borrowings									0	0	0
Repayments of Long-term Debt									(355,418)	(206,124)	0
Distributions to unitholders									0	0	0
Payment of Financing and Stock Issuance Costs									(1,377)	(10,646)	0
Change in note payable with affiliate									0	0	0
Proceeds from Contributions from Parent									132,332	100,921
Payments of Distributions to Affiliates											(435,000)
Proceeds from (Repayments of) Related Party Debt									0
Excess tax benefit from unit-based compensation										0	0
Excess tax benefit from unit-based compensation									0
Other									14	(864)	(4,272)
Net cash provided by (used in) financing activities									(224,449)	(116,713)	(439,272)
Net increase (decrease) in cash and cash equivalents									(563)	(49,455)	51,041
Cash and cash equivalents:
Beginning				$ 1,586				$ 51,041	1,586	51,041	0
Ending	$ 1,023				$ 1,586				$ 1,023	$ 1,586	$ 51,041

Subsidiary Guarantors Details (

Subsidiary Guarantors Details (Details)	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions	100.00%

Supplemental Oil and Natural 73

Supplemental Oil and Natural Gas Data (Unaudited) (Details) $ in Thousands, Mcfe in Millions, Mcf in Millions		12 Months Ended
		Dec. 31, 2015USD ($)Mcfe$ / MMBTU$ / bblMMBblsMcf	Dec. 31, 2014USD ($)Mcfe$ / MMBTU$ / bblMMBblsMcf	Dec. 31, 2013USD ($)Mcfe$ / MMBTU$ / bblMMBblsMcf
Property acquisition costs: (1)
Proved	[1]	$ 0	$ 2,784,852	$ 3,740,379
Unproved	[1]	0	788,682	1,638,302
Exploration costs		19,929	792	13,096
Development costs		430,357	1,487,204	1,153,770
Asset retirement costs		6,303	20,919	7,351
Total costs incurred		456,589	5,082,449	6,552,898
Proved properties:
Leasehold acquisition		13,361,171	13,362,642
Development		2,976,643	2,830,841
Unproved properties		1,783,341	1,875,417
Capitalized cost, oil and gas producing activities		18,121,155	18,068,900
Less accumulated depletion and amortization		(11,097,492)	(4,867,682)
Capitalized costs, oil and gas producing activities, net		7,023,663	13,201,218
Revenues and other:
Oil, natural gas and natural gas liquids sales		1,726,271	3,610,539	2,073,240
Gains on oil and natural gas derivatives		1,056,189	1,206,179	177,857
Results of Operations, Revenue from Oil and Gas Producing Activities		2,782,460	4,816,718	2,251,097
Production costs:
Lease operating expenses		617,764	805,164	372,523
Transportation expenses		219,721	207,331	128,440
Severance taxes, ad valorem taxes and California carbon allowances		181,941	267,100	139,202
Results of Operations, Expense from Oil and Gas Producing Activities		1,019,426	1,279,595	640,165
Other costs:
Exploration costs		9,473	125,037	5,251
Depletion and amortization		745,512	1,020,674	790,320
Impairment of long-lived assets		5,813,954	2,303,749	828,317
Gains on sale of assets and other, net		(198,924)	(388,733)	(138)
Texas margin tax expense (benefit)		(2,789)	4,053	458
Total other costs		6,367,226	3,064,780	1,624,208
Results of operations		$ (4,604,192)	$ 472,343	$ (13,276)
Proved developed and undeveloped reserves:
Beginning of year | Mcfe		7,304	6,403	4,796
Revisions of previous estimates | Mcfe		(2,379)	(318)	(157)
Purchases of minerals in place | Mcfe			2,495	1,610
Sales of minerals in place | Mcfe		(50)	(1,084)	(73)
Extensions, discoveries and other additions | Mcfe		47	250	527
Production | Mcfe		(434)	(442)	(300)
End of year | Mcfe		4,488	7,304	6,403
Proved developed reserves:
Beginning of year | Mcfe		5,818	4,340	3,127
End of year | Mcfe		4,488	5,818	4,340
Proved undeveloped reserves:
Beginning of year | Mcfe		1,486	2,063	1,669
End of year | Mcfe		0	1,486	2,063
Conversion rate between oil and NGL volumes to natural gas		6
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | Mcfe		(2,816)	901	1,607
Change in proved reserves due to change in commodity prices (in Mcfe) | Mcfe		(1,776)	45	52
Change in proved reserves due to the uncertainty of future capital commitments | Mcfe		(349)
Change in proved reserves due to the SEC five-year development limitation on PUDs | Mcfe		(302)	146	109
Change in proved reserves due to asset performance (in Mcfe) | Mcfe		(48)	43	100
Productive wells drilled		584	0	0
Change in proved reserves due to ethane rejection | Mcfe			(174)
Standardized Measure of Discounted Future Net Cash Flows
Future estimated revenues		$ 17,293,943	$ 55,195,268	$ 51,112,346
Future estimated production costs		(10,734,979)	(24,100,468)	(19,306,728)
Future estimated development costs		(1,107,639)	(4,032,588)	(5,110,896)
Future net cash flows		5,451,325	27,062,212	26,694,722
10% annual discount for estimated timing of cash flows		(2,417,780)	(14,549,921)	(14,795,393)
Standardized measure of discounted future net cash flows		$ 3,033,545	$ 12,512,291	$ 11,899,329
Representative NYMEX prices: (1)
Natural gas (MMBtu) | $ / MMBTU	[2]	2.59	4.35	3.67
Oil (Bbl) | $ / bbl	[2]	50.16	95.27	96.89
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Sales and transfers of oil, natural gas and NGL produced during the period		$ (706,845)	$ (2,330,944)	$ (1,433,075)
Changes in estimated future development costs		1,501,593	156,614	317,064
Net change in sales and transfer prices and production costs related to future production		(9,309,151)	(599,121)	203,370
Purchases of minerals in place		0	3,021,768	5,113,335
Sales of minerals in place		(97,785)	(1,681,504)	(139,384)
Extensions, discoveries and improved recovery		90,090	910,787	801,254
Previously estimated development costs incurred during the period		159,248	819,987	444,861
Net change due to revisions in quantity estimates		(1,633,958)	(672,800)	(220,224)
Accretion of discount		1,251,229	1,189,933	607,298
Changes in production rates and other		(733,167)	(201,758)	131,849
Change in the standardized measure of discounted future net cash flows		$ (9,478,746)	$ 612,962	$ 5,826,348
Natural Gas (Bcf)
Proved developed and undeveloped reserves:
Beginning of year | Mcf		4,255	3,010	2,571
Revisions of previous estimates | Mcf		(1,404)	96	(17)
Purchases of minerals in place | Mcf			1,763	356
Sales of minerals in place | Mcf		(13)	(477)	(24)
Extensions, discoveries and other additions | Mcf		15	72	286
Production | Mcf		(234)	(209)	(162)
End of year | Mcf		2,619	4,255	3,010
Proved developed reserves:
Beginning of year | Mcf		3,549	2,027	1,661
End of year | Mcf		2,619	3,549	2,027
Proved undeveloped reserves:
Beginning of year | Mcf		706	983	910
End of year | Mcf		0	706	983
Oil (MMBbls)
Proved developed and undeveloped reserves:
Beginning of year | MMBbls		341.8	365.6	191.5
Revisions of previous estimates | MMBbls		(122.2)	(22.3)	(21.3)
Purchases of minerals in place | MMBbls			50	191.1
Sales of minerals in place | MMBbls		(4.1)	(51.7)	(5.2)
Extensions, discoveries and other additions | MMBbls		4.6	26.8	21.7
Production | MMBbls		(22.8)	(26.6)	(12.2)
End of year | MMBbls		197.3	341.8	365.6
Proved developed reserves:
Beginning of year | MMBbls		246	252.4	131.4
End of year | MMBbls		197.3	246	252.4
Proved undeveloped reserves:
Beginning of year | MMBbls		95.8	113.2	60.1
End of year | MMBbls		0	95.8	113.2
NGL (MMBbls)
Proved developed and undeveloped reserves:
Beginning of year | MMBbls		166.3	200	179.4
Revisions of previous estimates | MMBbls		(40.4)	(46.8)	(2)
Purchases of minerals in place | MMBbls			71.9	17.8
Sales of minerals in place | MMBbls		(2)	(49.5)	(2.9)
Extensions, discoveries and other additions | MMBbls		0.8	2.9	18.5
Production | MMBbls		(10.4)	(12.2)	(10.8)
End of year | MMBbls		114.3	166.3	200
Proved developed reserves:
Beginning of year | MMBbls		132.2	133.2	113
End of year | MMBbls		114.3	132.2	133.2
Proved undeveloped reserves:
Beginning of year | MMBbls		34.1	66.8	66.4
End of year | MMBbls		0	34.1	66.8
[1]	See Note 2 for details about the Company’s acquisitions.
[2]	In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.

Supplemental Quarterly Data (74

Supplemental Quarterly Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Data [Abstract]
Oil, natural gas and natural gas liquids sales		$ 352,038	$ 427,245	$ 496,419	$ 450,569	$ 766,354	$ 937,458	$ 967,850	$ 938,877	$ 1,726,271	$ 3,610,539	$ 2,073,240
Gains (losses) on oil and natural gas derivatives		273,567	549,029	(191,188)	424,781	1,404,758	451,702	(408,788)	(241,493)	1,063,082	1,206,179	177,857
Total revenues and other		646,655	998,304	321,828	916,547	2,217,650	1,435,115	596,951	733,587	2,883,334	4,983,303	2,331,655
Total expenses (1)	[1]	3,497,486	2,790,081	578,586	1,136,442	2,533,947	1,320,157	664,452	674,568
(Gains) losses on sale of assets and other, net		(146)	(166,980)	(17,996)	(12,287)	(338,750)	(35,803)	5,467	2,586	(197,409)	(366,500)	13,637
Net loss		$ (2,472,207)	$ (1,569,317)	$ (379,127)	$ (339,160)	$ (154,502)	$ (4,100)	$ (207,870)	$ (85,337)	$ (4,759,811)	$ (451,809)	$ (691,337)
Net loss per unit:
Basic		$ (7.05)	$ (4.47)	$ (1.12)	$ (1.03)	$ (0.47)	$ (0.02)	$ (0.64)	$ (0.27)	$ (13.87)	$ (1.40)	$ (2.94)
Diluted		$ (7.05)	$ (4.47)	$ (1.12)	$ (1.03)	$ (0.47)	$ (0.02)	$ (0.64)	$ (0.27)	$ (13.87)	$ (1.40)	$ (2.94)
[1]	Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.