Pressburg (ROAN) 10-K 23 Mar 17 2016 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Feb. 28, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Entity Registrant Name	Linn Energy, Inc.
Entity Central Index Key	1,326,428
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	No
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 20
Entity Common Stock, Shares Outstanding		91,708,500
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents		$ 694,857	$ 1,145
Accounts receivable – trade, net		198,064	179,124
Derivative instruments		0	1,207,012
Other current assets		107,613	74,696
Current assets of discontinued operations		0	81,191
Total current assets		1,000,534	1,543,168
Noncurrent assets:
Oil and natural gas properties (successful efforts method)		13,232,959	13,110,094
Less accumulated depletion and amortization		(9,999,560)	(9,501,327)
Oil and natural gas properties, successful efforts method, net		3,233,399	3,608,767
Other property and equipment		636,487	597,216
Less accumulated depreciation		(224,547)	(183,139)
Other property and equipment, net		411,940	414,077
Derivative instruments		0	566,401
Other noncurrent assets		14,718	24,182
Noncurrent assets of discontinued operations		0	3,780,285
Noncurrent assets, excluding property, total		14,718	4,370,868
Total noncurrent assets		3,660,057	8,393,712
Total assets		4,660,591	9,936,880
Current liabilities:
Accounts payable and accrued expenses		295,077	338,247
Derivative instruments		82,508	0
Current portion of long-term debt, net	[1]	1,937,729	2,841,518
Other accrued liabilities		26,304	102,858
Current liabilities of discontinued operations		0	1,017,899
Total current liabilities		2,341,618	4,300,522
Derivative instruments		11,349	857
Long-term debt, net		0	4,447,308
Other noncurrent liabilities		399,607	399,676
Liabilities subject to compromise		4,305,005	0
Noncurrent liabilities of discontinued operations		0	1,057,418
Commitments and contingencies (Note 11)
Unitholders’ deficit:
352,792,474 units and 355,017,428 units issued and outstanding at December 31, 2016, and December 31, 2015, respectively		5,386,885	5,343,116
Accumulated deficit		(7,783,873)	(5,612,017)
Total unitholders' capital (deficit)		(2,396,988)	(268,901)
Total liabilities and unitholders’ deficit		$ 4,660,591	$ 9,936,880
[1]	Due to existing and anticipated covenant violations, the Company’s Credit Facilities and term loan were classified as current at December 31, 2016, and December 31, 2015. The current portion as of December 31, 2015, also includes approximately $128 million of interest payable on the Second Lien Notes that was due within one year.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Unitholders' capital: Units issued	352,792,474	355,017,428
Unitholders' capital: Units outstanding	352,792,474	355,017,428

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues and other:
Oil, natural gas and natural gas liquids sales	$ 952,132	$ 1,151,240	$ 2,312,137
Gains (losses) on oil and natural gas derivatives	(164,330)	1,027,014	1,127,395
Marketing revenues	36,505	43,876	84,349
Other revenues	93,406	97,883	114,386
Total revenues	917,713	2,320,013	3,638,267
Expenses:
Lease operating expenses	317,046	375,840	443,157
Transportation expenses	161,037	167,561	165,489
Marketing expenses	29,736	35,278	81,210
General and administrative expenses	237,841	285,996	274,006
Exploration costs	4,080	9,473	125,037
Depreciation, depletion and amortization	404,237	554,386	771,549
Impairment of long-lived assets	165,044	4,960,144	2,050,387
Taxes, other than income taxes	74,838	111,302	169,695
(Gains) losses on sale of assets and other, net	15,558	(195,490)	(487,286)
Total expenses	1,409,417	6,304,490	3,593,244
Other income and (expenses):
Interest expense, net of amounts capitalized	(192,862)	(460,635)	(499,890)
Gain on extinguishment of debt	0	708,050	0
Other, net	(1,536)	(13,965)	(15,170)
Total other income and (expenses)	(194,398)	233,450	(515,060)
Reorganization items, net	311,599	0	0
Loss from continuing operations before income taxes	(374,503)	(3,751,027)	(470,037)
Income tax expense (benefit)	11,194	(6,393)	4,368
Loss from continuing operations	(385,697)	(3,744,634)	(474,405)
Income (loss) from discontinued operations, net of income taxes	(1,786,159)	(1,015,177)	22,596
Net loss	$ (2,171,856)	$ (4,759,811)	$ (451,809)
Loss per unit – continuing operations:
Basic (in usd per unit)	$ (1.10)	$ (10.91)	$ (1.47)
Diluted (in usd per unit)	(1.10)	(10.91)	(1.47)
Income (loss) per unit – discontinued operations:
Basic (in usd per unit)	(5.06)	(2.96)	0.07
Diluted (in usd per unit)	(5.06)	(2.96)	0.07
Net loss per unit:
Basic (in usd per unit)	(6.16)	(13.87)	(1.40)
Diluted (in usd per unit)	$ (6.16)	$ (13.87)	$ (1.40)
Weighted average units outstanding:
Basic (in units)	352,653	343,323	328,918
Diluted (in units)	352,653	343,323	328,918
Distributions declared per unit	$ 0	$ 0.938	$ 2.90

CONSOLIDATED STATEMENT OF UNITH

CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (DEFICIT) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Common Units, Outstanding (in units)		355,017,428			355,017,428
Balance Beginning		$ (268,901)		$ 4,543,605	$ (268,901)	$ 4,543,605	$ 5,891,427
Sale of units, net of offering costs of $8,762						224,665
Issuance of units					0	0	13,354
Cancellation of units					0	0
Purchase of units						(672)
Distributions to unitholders					0	(323,878)	(962,048)
Unit-based compensation expenses					44,218	56,136	53,284
Other					(449)
Reclassification of distributions paid on forfeited restricted units						865	602
Excess tax benefit from unit-based compensation and other							347
Excess tax benefit from unit-based compensation and other						(9,811)
Deferred tax on capital contribution							(1,552)
Net loss	$ (834,237)	$ (1,347,746)	$ (2,472,207)	$ (339,160)	(2,171,856)	(4,759,811)	(451,809)
Balance Ending	$ (2,396,988)		$ (268,901)		$ (2,396,988)	$ (268,901)	$ 4,543,605
Common Units, Outstanding (in units)	352,792,474		355,017,428		352,792,474	355,017,428
Units
Common Units, Outstanding (in units)		355,017,000		331,975,000	355,017,000	331,975,000	329,661,000
Sale of units (in units)						19,622,000
Issuance of units (in units)					5,000	3,611,000	2,314,000
Cancellation of units (in units)					(2,230,000)	(191,000)
Common Units, Outstanding (in units)	352,792,000		355,017,000		352,792,000	355,017,000	331,975,000
Unitholders’ Capital
Balance Beginning		$ 5,343,116		$ 5,395,811	$ 5,343,116	$ 5,395,811	$ 6,291,824
Sale of units, net of offering costs of $8,762						224,665
Issuance of units					0	0	13,354
Cancellation of units					0	(672)
Purchase of units						0
Distributions to unitholders						(323,878)	(962,048)
Unit-based compensation expenses					44,218	56,136	53,284
Other					(449)
Reclassification of distributions paid on forfeited restricted units						865	602
Excess tax benefit from unit-based compensation and other							347
Excess tax benefit from unit-based compensation and other						(9,811)
Deferred tax on capital contribution							(1,552)
Net loss					0	0	0
Balance Ending	$ 5,386,885		$ 5,343,116		5,386,885	5,343,116	5,395,811
Accumulated Deficit
Balance Beginning		(5,612,017)		(852,206)	(5,612,017)	(852,206)	(400,397)
Sale of units, net of offering costs of $8,762						0
Issuance of units					0	0	0
Cancellation of units					0	0
Purchase of units						0
Distributions to unitholders						0	0
Unit-based compensation expenses					0	0	0
Other					0
Reclassification of distributions paid on forfeited restricted units						0	0
Excess tax benefit from unit-based compensation and other							0
Excess tax benefit from unit-based compensation and other						0
Deferred tax on capital contribution							0
Net loss					(2,171,856)	(4,759,811)	(451,809)
Balance Ending	(7,783,873)		(5,612,017)		(7,783,873)	(5,612,017)	(852,206)
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					0	672
Purchase of units						(672)
Distributions to unitholders						0	0
Unit-based compensation expenses					0	0	0
Other					0
Reclassification of distributions paid on forfeited restricted units						0	0
Excess tax benefit from unit-based compensation and other							0
Excess tax benefit from unit-based compensation and other						0
Deferred tax on capital contribution							0
Net loss					0	0	0
Balance Ending	$ 0		$ 0		$ 0	$ 0	$ 0

CONSOLIDATED STATEMENT OF UNIT6

CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (DEFICIT) (Parenthetical) $ in Thousands	3 Months Ended
	Mar. 31, 2014USD ($)
Statement of Stockholders' Equity [Abstract]
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$ 8,762

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Cash flow from operating activities:
Net loss	$ (2,171,856)	$ (4,759,811)	$ (451,809)
Adjustments to reconcile net loss to net cash provided by operating activities – continuing operations:
(Income) loss from discontinued operations	1,786,159	1,015,177	(22,596)
Depreciation, depletion and amortization	404,237	554,386	771,549
Impairment of long-lived assets	165,044	4,960,144	2,050,387
Unit-based compensation expenses	44,218	56,136	53,284
Gain on extinguishment of debt	0	(708,050)	0
Amortization and write-off of deferred financing fees	13,356	30,993	55,839
(Gains) losses on sale of assets and other, net	13,007	(188,200)	(372,945)
Deferred income taxes	11,367	4,606	3,874
Reorganization items, net	(365,367)	0	0
Derivatives activities:
Total (gains) losses	164,330	(1,027,014)	(1,127,395)
Cash settlements	503,943	1,130,640	88,776
Cash settlements on canceled derivatives	356,835	4,679	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	(71,059)	211,884	(7,674)
Increase in other assets	(17,733)	(9,142)	(1,875)
Increase (decrease) in accounts payable and accrued expenses	38,468	(98,223)	99,003
Decrease in other liabilities	(515)	(51,266)	(10,008)
Net cash provided by operating activities – continuing operations	874,434	1,126,939	1,128,410
Net cash provided by operating activities – discontinued operations	6,080	122,518	583,480
Net cash provided by operating activities	880,514	1,249,457	1,711,890
Cash flow from investing activities:
Deconsolidation of Berry Petroleum Company, LLC cash	(28,549)	0	0
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired	0	0	(2,475,315)
Development of oil and natural gas properties	(180,313)	(576,256)	(1,061,395)
Purchases of other property and equipment	(45,435)	(48,967)	(63,070)
Investment in discontinued operations	0	132,332	100,921
Proceeds from sale of properties and equipment and other	(4,690)	345,770	2,195,898
Net cash used in investing activities – continuing operations	(258,987)	(411,785)	(1,504,803)
Net cash provided by (used in) investing activities – discontinued operations	23,147	101,368	(516,222)
Net cash used in investing activities	(235,840)	(310,417)	(2,021,025)
Cash flow from financing activities:
Proceeds from sale of units	0	233,427	0
Proceeds from borrowings	978,500	1,445,000	5,940,024
Repayments of debt	(913,209)	(1,828,461)	(4,605,000)
Distributions to unitholders	0	(323,878)	(962,048)
Financing fees and offering costs	(752)	(26,678)	(59,048)
Settlement of advance from discontinued operations	0	(129,217)	0
Excess tax benefit from unit-based compensation	0	(9,467)	766
Other	(14,823)	(74,958)	60,792
Net cash provided by (used in) financing activities – continuing operations	49,716	(714,232)	375,486
Net cash used in financing activities – discontinued operations	(1,701)	(224,449)	(116,713)
Net cash provided by (used in) financing activities	48,015	(938,681)	258,773
Net increase (decrease) in cash and cash equivalents	692,689	359	(50,362)
Cash and cash equivalents:
Beginning	2,168	1,809	52,171
Ending	694,857	2,168	1,809
Less cash and cash equivalents of discontinued operations at end of year	0	(1,023)	(1,586)
Ending – continuing operations	$ 694,857	$ 1,145	$ 223

Basis of Presentation and Signi

Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Significant Accounting Policies	Basis of Presentation and Significant Accounting Policies When referring to Linn Energy, Inc. (formerly known as Linn Energy, LLC) (“Successor,” “Reorganized LINN,” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a newly formed Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Linn Energy, Inc. is a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When referring to the “Predecessor” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to Linn Energy, LLC, the predecessor that will be dissolved following the effective date of the Plan (as defined below) and resolution of all outstanding claims, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiary of LINN Energy through February 28, 2017. Berry was deconsolidated effective December 3, 2016 (see Note 3). The reference to “LinnCo” herein refers to LinnCo, LLC, which is an affiliate of the Predecessor. Nature of Business LINN Energy is an independent oil and natural gas company that was formed on February 14, 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16‑60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017. On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry. As a result of its loss of control of Berry, LINN Energy concluded that it was appropriate to deconsolidate Berry effective on the aforementioned date. The results of operations of Berry are reported as discontinued operations for all periods presented. 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) and North Dakota (Williston Basin); Mid-Continent, which includes properties located in the Anadarko and Arkoma basins in Oklahoma, as well as waterfloods in the Central Oklahoma Platform; TexLa, which includes properties located in east Texas and north Louisiana; Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; California, which includes properties located in the San Joaquin Valley and Los Angeles basins; Permian Basin, which includes properties located in west Texas and southeast New Mexico; and South Texas. 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. In addition, the Company has classified the assets and liabilities, results of operations and cash flows of Berry as discontinued operations in its consolidated financial statements for all periods presented. Such reclassifications have no impact on previously reported net income (loss), unitholders’ capital (deficit) or cash flows. Bankruptcy Accounting The consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on the Company’s consolidated balance sheet at December 31, 2016 . These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less. The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the consolidated financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on unitholders’ deficit accounts of any changes that may be made to the Company’s capitalization; or (iv) the effect on operations of any changes that may be made to the Company’s business. 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 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements and related disclosures. The adoption of this ASU is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the consolidated balance sheets to cash, cash equivalents and restricted cash on the consolidated statements of cash flows. In March 2016, the FASB issued an ASU that is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Components of this ASU will be applied either prospectively, retrospectively or under a modified retrospective basis (as applicable for the respective provision) as of the date of adoption and is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company is currently evaluating the impact of the adoption of this ASU. For periods following adoption, the Company will recognize excess tax benefits as income tax expense in the consolidated statements of operations and as operating activities in the consolidated statements of cash flows. The Company does not expect this standard to have a material impact on its consolidated financial statements or related disclosures. In February 2016, the FASB issued an ASU that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2018, and interim periods within those years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements and related disclosures. The Company expects the adoption of this ASU to impact its consolidated balance sheets resulting from an increase in both assets and liabilities related to the Company’s leasing activities. In November 2015, the FASB issued an ASU that is intended to simplify the presentation of deferred taxes by requiring that all deferred taxes be classified as noncurrent, presented as a single noncurrent amount for each tax-paying component of an entity. The ASU is effective for fiscal years beginning after December 15, 2016; however, the Company early adopted it on January 1, 2016, on a retrospective basis. The adoption of this ASU resulted in the reclassification of previously-classified net current deferred taxes of approximately $22 million from “other current assets,” as well as previously-classified net noncurrent deferred tax liabilities of approximately $11 million from “other noncurrent liabilities,” to “other noncurrent assets” resulting in net noncurrent deferred taxes of approximately $11 million on the Company’s consolidated balance sheet at December 31, 2015 . There was 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 on the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The Company adopted this ASU on January 1, 2016, on a retrospective basis. The adoption of this ASU resulted in the reclassification of approximately $37 million of unamortized deferred financing fees (which excludes deferred financing fees associated with the Company’s Credit Facilities, as defined in Note 6, which were not reclassified) from an asset to a direct deduction from the carrying amount of the associated debt liability on the consolidated balance sheet at December 31, 2015 . There was 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 the annual periods and interim periods thereafter, and the Company adopted this ASU on December 31, 2016 . The adoption of this ASU had no impact on the Company’s consolidated 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 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 does not plan on early adopting this ASU. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements and related disclosures. The Company expects to use the cumulative-effect transition method, has completed an initial review of its contracts and is developing accounting policies to address the provisions of the ASU, but has not finalized any estimates of the potential impacts. 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 $8 million and $1 million at December 31, 2016 , and December 31, 2015 , respectively. 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 $257,000 , $3 million and $4 million for the years ended December 31, 2016 , December 31, 2015 , and December 31, 2014 , 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 associated with proved oil and natural gas properties: Year Ended December 31, 2016 2015 2014 (in thousands) Mid-Continent region $ 141,902 $ 405,370 $ 244,413 Rockies region 23,142 1,592,256 332,365 Hugoton Basin region — 1,667,768 — TexLa region — 352,422 4,836 Permian Basin region — 71,990 1,337,444 South Texas region — 42,433 131,329 $ 165,044 $ 4,132,239 $ 2,050,387 The impairment charges in 2016 and 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 $1.4 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 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. 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 evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past. Based on the analysis described above, the Company recorded the following noncash impairment charges 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 $ 827,905 The Company recorded no impairment charges associated with unproved properties for the years ended December 31, 2016, or December 31, 2014 . The impairment charges in 2015 were based primarily on no future plans to develop properties in certain operating areas as a result of declines in commodity prices. 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 statements of operations. Exploration Costs Exploratory 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 no leasehold impairment expenses related to unproved properties during the year ended December 31, 2016 . The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $2 million and $125 million for the years ended December 31, 2015 , and December 31, 2014 , 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, furniture and office equipment, buildings, vehicles, information technology equipment, software and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from three to 39 years for the individual asset or group of assets. Restricted Cash Restricted cash of approximately $8 million and $7 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2016 , and December 31, 2015 , respectively, and represents cash deposited by the Company into a separate account designated for asset retirement obligations in accordance with contractual agreements. Derivative Instruments Historically, 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. 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 has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials. The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars 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. 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. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. 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. 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 and public bond yield 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. 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, 2016 , and December 31, 2015 , the Company had natural gas production imbalance receivables of approximately $8 million and $13 million , respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets. At December 31, 2016 , and December 31, 2015 , the Company had natural gas production imbalance payables of approximately $6 million and $11 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. 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. Deferred Financing Fees The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2016 , net deferred financing fees of approximately $17 million are included in “other current assets” and approximately $1 million are included in “current portion of long-term debt, net” on the consolidated balance sheet. At December 31, 2015 , net deferred financing fees of approximately $25 million are included in “other current assets,” approximately $2 million are included in “current portion of long-term debt, net” and approximately $35 million are included in “long-term debt, net” 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, 2016 , December 31, 2015 , and December 31, 2014 , amortization expense of approximately $10 million , $20 million and $43 million , respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations. For the year ended December 31, 2016 , approximately $33 million were written off to expense and included in “reorganization items, net” on the consolidated statement of operations in connection with the filing of the Bankruptcy Petitions. For the years ended December 31, 2016 , and December 31, 2015 , approximately $1 million and $7 million , respectively, were written off to expense and included in “other, net” on the consolidated statements of operations related to amendments of the Credit Facilities. 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. 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, 2016 , and December 31, 2015 . 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 Prior to the consummation of the LINN Plan, as defined below, the Company was 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 Predecessor is not a taxable entity. The Predecessor 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 Predecessor. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets a

Chapter 11 Proceedings and Cove

Chapter 11 Proceedings and Covenant Violations (Notes)	12 Months Ended
	Dec. 31, 2016
Reorganizations [Abstract]
Chapter 11 Proceedings and Covenant Violations	Chapter 11 Proceedings and Covenant Violations Chapter 11 Proceedings On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16‑60040. On October 21, 2016, the Debtors filed the Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates (the “Original Plan”). On December 3, 2016, the Debtors split the Original Plan and pursued separate plans of reorganization for the LINN Debtors, on the one hand, and Linn Acquisition Company, LLC (“LAC”) and Berry, on the other hand. Accordingly, on December 3, 2016, the LINN Debtors filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “LINN Plan”). The LINN Debtors subsequently filed amended versions of the LINN Plan with the Bankruptcy Court. On December 13, 2016, LAC and Berry filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Berry Plan” and together with the LINN Plan, the “Plans”). LAC and Berry subsequently filed amended versions of the Berry Plan with the Bankruptcy Court. On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plans (the “Confirmation Order”). On February 28, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the respective Plans, the Plans became effective in accordance with their respective terms and LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. Plans of Reorganization In accordance with the LINN Plan, on the Effective Date: • The Predecessor transferred all of its assets, including equity interests in its subsidiaries, other than LAC and Berry, to Linn Energy Holdco II LLC (“Holdco II”), a newly formed subsidiary of the Predecessor and the borrower under the Credit Agreement (“Exit Facility”) entered into in connection with the reorganization, in exchange for 100% of the equity of Holdco II and the issuance of interests in the Exit Facility to certain of the Predecessor’s creditors in partial satisfaction of their claims (the “Contribution”). Immediately following the Contribution, the Predecessor transferred 100% of the equity interests in Holdco II to the Successor in exchange for approximately $530 million in cash and an amount of equity securities in the Successor not to exceed 49.90% of the outstanding equity interests of the Successor (the “Disposition”), which the Predecessor distributed to certain of its creditors in satisfaction of their claims. Contemporaneously with the reorganization transactions and pursuant to the LINN Plan, (i) LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, (ii) all of the equity interests in LAC and the Predecessor were canceled and (iii) LAC and the Predecessor commenced liquidation, which is expected to be completed following the resolution of the respective companies’ outstanding claims. • The holders of claims under the Predecessor’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) received a full recovery, consisting of a cash paydown and their pro rata share of the $1.7 billion Exit Facility. As a result, all outstanding obligations under the LINN Credit Facility were canceled. • Holdco II, as borrower, entered into the Exit Facility with the holders of claims under the LINN Credit Facility, as lenders, and Wells Fargo Bank, National Association, as administrative agent, providing for a new reserve-based revolving loan (the “Revolving Loan”) with up to $1.4 billion in borrowing commitments and a new term loan (the “Term Loan”) in an original principal amount of $300 million . For additional information about the Exit Facility, see “Financing Activities” in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” • The holders of the Company’s 12.00% senior secured second lien notes due December 2020 (the “Second Lien Notes”) received their pro rata share of (i) 17,678,889 shares of Class A common stock; (ii) certain rights to purchase shares of Class A common stock in the rights offering, as described below; and (iii) $30 million in cash. The holders of the Company’s 6.50% senior notes due May 2019, 6.25% senior notes due November 2019, 8.625% senior notes due 2020, 7.75% senior notes due February 2021 and 6.50% senior notes due September 2021 (collectively, the “Unsecured Notes”) received their pro rata share of (i) 26,724,396 shares of Class A common stock; and (ii) certain rights to purchase shares of Class A common stock in the rights offering (as described below). As a result, all outstanding obligations under the Second Lien Notes and the Unsecured Notes and the indentures governing such obligations were canceled. • The holders of general unsecured claims (other than claims relating to the Second Lien Notes and the Unsecured Notes) against the LINN Debtors (the “LINN Unsecured Claims”) received their pro rata share of cash from two cash distribution pools totaling $40 million , as divided between a $2.3 million cash distribution pool for the payment in full of allowed LINN Unsecured Claims in an amount equal to $2,500 or less (and larger claims for which the holders irrevocably agreed to reduce such claims to $2,500 ), and a $37.7 million cash distribution pool for pro rata distributions to all remaining allowed general LINN Unsecured Claims. As a result, all outstanding LINN Unsecured Claims were fully satisfied, settled, released and discharged as of the Effective Date. • All units that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery. On the Effective Date, the Reorganized LINN issued in the aggregate 91,708,500 shares of Class A common stock. No cash was raised from the issuance of the Class A common stock on account of claims held by the Predecessor’s creditors. • The Reorganized LINN entered into a registration rights agreement with certain parties to the Backstop Commitment Agreement and other recipients of shares of Class A common stock who own at least 10% of the shares of Class A common stock or are otherwise deemed to be an affiliate of the Reorganized LINN, pursuant to which the Company agreed to, among other things, file a registration statement with the Securities and Exchange Commission within 60 days of the Effective Date covering the offer and resale of “Registrable Securities” (as defined therein). • By operation of the LINN Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. The Reorganized LINN formed a new board of directors, consisting of the Chief Executive Officer of the Predecessor, one director selected by the Reorganized LINN and five directors selected by a six-person selection committee. In accordance with the Berry Plan, on the Effective Date: • LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, and Berry became a wholly owned subsidiary of Berry Petroleum Corporation. All of the equity interests in LAC that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery. Subsequently, LAC commenced liquidation, which is expected to be completed following the resolution of the outstanding claims. As a result, Berry Petroleum Corporation became a stand-alone company, separate from the Company and the LINN Debtors. • The holders of claims under Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) received a full recovery, consisting of a cash paydown and their pro rata share of the new Berry credit facility (“Berry Exit Facility”). As a result, all outstanding obligations under the Berry Credit Facility were canceled. • Berry, as borrower, entered into the Berry Exit Facility with the holders of claims under the Berry Credit Facility, as lenders, and Wells Fargo Bank, National Association, as administrative agent, providing for a new reserve-based revolving loan with up to $550 million in borrowing commitments. • The holders of Berry’s 6.75% senior notes due 2020 and 6.375% senior notes due 2022 (collectively, the “Berry Unsecured Notes”) received their pro rata share of either (i) shares of common stock in Berry Petroleum Corporation or, for those non-accredited investors holding the Berry Unsecured Notes that irrevocably elected to receive a cash recovery, cash distributions from a $35 million cash distribution pool (the “Berry Cash Distribution Pool”), and (ii) certain rights to purchase shares of preferred stock in Berry Petroleum Corporation. • The holders of unsecured claims against Berry (other than the Berry Unsecured Notes) (the “Berry Unsecured Claims”) received their pro rata share of either (i) shares of common stock in Berry Petroleum Corporation or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Berry Cash Distribution Pool. As a result, all outstanding obligations under the Berry Unsecured Notes and the indentures governing such obligations were canceled and all outstanding Berry Unsecured Claims were fully satisfied, settled, released and discharged as of the Effective Date. • Berry and LAC settled all intercompany claims against the LINN Debtors pursuant to a settlement agreement approved as part of the Berry Plan and the Confirmation Order, which settlement provided Berry and LAC with a $25 million general unsecured claim against the Company. Bank RSA Prior to the Petition Date, on May 10, 2016, the Debtors entered into a restructuring support agreement (“Bank RSA”) with certain holders (“Consenting Bank Creditors”) collectively holding or controlling at least 66.67% by aggregate outstanding principal amounts under (i) the LINN Credit Facility and (ii) the Berry Credit Facility. The Bank RSA set forth, subject to certain conditions, the commitment of the Consenting Bank Creditors to support a comprehensive restructuring of the Debtors’ long-term debt. The Bank RSA provided that the Consenting Bank Creditors would support the use of the LINN Debtors’ and Berry’s cash collateral under specified terms and conditions, including adequate protection terms. The Bank RSA required the Debtors and the Consenting Bank Creditors to, among other things, support and not interfere with consummation of the restructuring transactions contemplated by the Bank RSA and, as to the Consenting Bank Creditors, vote their claims in favor of the plan of reorganization. Restructuring Support Agreement On October 7, 2016, the LINN Debtors entered into a restructuring support agreement (“Original LINN RSA”) with (i) certain holders of the Second Lien Notes (such holders, the “Consenting Second Lien Noteholders”) and (ii) certain holders of the Unsecured Notes (such holders of the Unsecured Notes, the “Consenting Unsecured Noteholders,” and together such Consenting Unsecured Noteholders with the Consenting Second Lien Noteholders, the “Consenting Noteholders”). On October 21, 2016, the LINN Debtors entered into the First Amended and Restated Restructuring Support Agreement (“LINN RSA”) with (i) certain Consenting Second Lien Noteholders, (ii) certain Consenting Unsecured Noteholders and (iii) certain lenders (together with the Consenting Noteholders, the “Consenting LINN Creditors”) under the LINN Credit Facility. The LINN RSA amended and restated the Original LINN RSA and replaced the Bank RSA with respect to the terms of the restructuring of the LINN Debtors. At that time, the Bank RSA remained in full force and effect with respect to the restructuring of Berry and LAC. The LINN RSA set forth, subject to certain conditions, the commitment of the LINN Debtors and the Consenting LINN Creditors to support a comprehensive restructuring of the LINN Debtors’ long-term debt (the “Restructuring”). The LINN RSA required the LINN Debtors and the Consenting LINN Creditors to, among other things, support and not interfere with consummation of the Restructuring and, as to the Consenting LINN Creditors, vote their claims in favor of the LINN Plan. The restructuring contemplated by the LINN RSA was effectuated through the LINN Plan and the Confirmation Order and took effect on the Effective Date. Liabilities Subject to Compromise The Company’s consolidated balance sheet includes amounts classified as “liabilities subject to compromise,” which represent prepetition liabilities that have been allowed, or that the Company anticipates will be allowed, as claims in its Chapter 11 cases. The amounts represent the Company’s current estimate of known or potential obligations to be resolved in connection with the Chapter 11 proceedings. The differences between the liabilities the Company has estimated and the claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. The Company will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material. The following table summarizes the components of liabilities subject to compromise included on the consolidated balance sheet: December 31, 2016 (in thousands) Accounts payable and accrued expenses $ 137,692 Accrued interest payable 144,184 Debt 4,023,129 Liabilities subject to compromise $ 4,305,005 Reorganization Items, Net The Company has incurred and is expected to continue to incur significant costs associated with the reorganization. These costs, which are expensed as incurred, are expected to significantly affect the Company’s results of operations. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined. The following table summarizes the components of reorganization items included on the consolidated statement of operations: Year Ended December 31, 2016 (in thousands) Legal and other professional advisory fees $ (56,656 ) Unamortized deferred financing fees, discounts and premiums (52,045 ) Gain related to interest payable on the 12.00% senior secured second lien notes due December 2020 (1) 551,000 Terminated contracts (66,052 ) Other (64,648 ) Reorganization items, net $ 311,599 (1) Represents a noncash gain on the write-off of postpetition contractual interest through maturity , recorded to reflect the carrying value of the liability subject to compromise at its estimated allowed claim amount. Effect of Filing on Creditors and Unitholders Subject to certain exceptions, under the Bankruptcy Code, the filing of Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ prepetition liabilities are subject to settlement under the Bankruptcy Code. Although the filing of Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors were stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. The Company did not record interest expense on its Second Lien Notes or senior notes for the period from May 12, 2016, through December 31, 2016 . For that period, unrecorded contractual interest was approximately $219 million . Under the Bankruptcy Code, unless creditors agree otherwise, prepetition liabilities and postpetition liabilities must be satisfied in full before the holders of the Company’s existing common units are entitled to receive any settlement or retain any property under a plan of reorganization. Pursuant to the terms of the LINN Plan, all of the equity interests in the Predecessor were canceled and the Predecessor commenced liquidation, which is expected to be completed following the resolution of all outstanding claims. Covenant Violations The Company’s filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under its Credit Facilities, its Second Lien Notes and its senior notes. Additionally, other events of default, including cross-defaults, have occurred, including the failure to make interest payments on the Company’s Second Lien Notes and senior notes, as well as the receipt of a going concern explanatory paragraph from the Company’s independent registered public accounting firm on the Company’s consolidated financial statements for the year ended December 31, 2015. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of an event of default. See Note 6 for additional details about the Company’s debt. Credit Facilities The Company’s Credit Facilities contained a requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception. Consequently, the filing of the Company’s 2015 Annual Report on Form 10-K which included such explanatory paragraph resulted in a default under the LINN Credit Facility as of the filing date, March 15, 2016, subject to a 30 day grace period. On April 12, 2016, the Company entered into amendments to both the LINN Credit Facility and the Berry Credit Facility. The amendments provided for, among other things, an agreement that (i) certain events would not become defaults or events of default until May 11, 2016, (ii) the borrowing bases would remain constant until May 11, 2016, unless reduced as a result of swap agreement terminations or collateral sales and (iii) the Company, the administrative agent and the lenders would negotiate in good faith the terms of a restructuring support agreement in furtherance of a restructuring of the capital structure of the Company and its subsidiaries. In addition, the amendment to the Berry Credit Facility provided Berry with access to previously restricted cash of $45 million in order to fund ordinary course operations. As a condition to closing the amendments, in April 2016, (a) the Company made a $100 million permanent repayment of a portion of the borrowings outstanding under the LINN Credit Facility and (b) the Company and certain of its subsidiaries provided control agreements over certain deposit accounts. Pursuant to the terms of the amendment to the LINN Credit Facility and as a result of the execution of the Bank RSA, in May 2016, the Company made a $350 million permanent repayment of a portion of the borrowings outstanding under the LINN Credit Facility. The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the Credit Facilities. However, under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of the default. Second Lien Notes 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, which resulted in the Company being in default under the Second Lien Indenture. On April 4, 2016, the Company entered into a settlement agreement with certain holders of the Second Lien Notes and agreed to deliver, and make arrangements for recordation of, the mortgages. The Company has since delivered and made arrangements for recordation of the mortgages. The settlement agreement required the parties to commence good faith negotiations with each other regarding the terms of a potential comprehensive and consensual restructuring, including a potential restructuring under a Chapter 11 plan of reorganization. The settlement agreement provided that in the event the parties were unable to reach agreement on the terms of a consensual restructuring on or before the commencement of such Chapter 11 proceedings (or such later date as mutually agreed to by the parties), the parties would support entry by the Bankruptcy Court of a settlement order that, among other things, (i) approves the issuance of additional notes, in the principal amount of $1.0 billion plus certain accrued interest, on a proportionate basis to existing holders of the Second Lien Notes and (ii) releases the mortgages and other collateral upon the issuance of the additional notes (the “Settlement Order”). The settlement agreement will terminate upon, among other events, entry by the Bankruptcy Court of a final, non-appealable order denying the Company’s motion seeking entry of the Settlement Order. The Company also failed to make interest payments on its Second Lien Notes during 2016. The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the Second Lien Indenture. However, under the Bankruptcy Code, holders of the Second Lien Notes were stayed from taking any action against the Company as a result of the default. Senior Notes The Company deferred 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 6.375% senior notes due September 2022, which resulted in the Company being in default under these senior notes. The indentures governing each of the applicable series of notes provided the Company a 30 day grace period to make the interest payments. On April 14, 2016, within the 30 day interest payment grace period provided for in the indentures governing the notes, the Company and Berry made interest payments of approximately $60 million in satisfaction of their respective obligations. The Company failed to make interest payments due on its senior notes subsequent to April 14, 2016. The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the indentures governing the senior notes. However, under the Bankruptcy Code, holders of the senior notes were stayed from taking any action against the Company as a result of the default.

Discontinued Operations, Divest

Discontinued Operations, Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Discontinued Operations, Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding	Discontinued Operations, Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding Discontinued Operations – 2016 On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry. As a result of its loss of control of Berry, LINN Energy concluded that it was appropriate to deconsolidate Berry effective on the aforementioned date. The Company has classified the assets and liabilities, results of operations and cash flows of Berry as discontinued operations in its consolidated financial statements for all periods presented. The following table presents summarized financial results of the Company’s discontinued operations on the consolidated statements of operations: Year Ended December 31, 2016 (1) 2015 2014 (in thousands) Revenues and other $ 387,706 $ 641,654 $ 1,431,289 Expenses 1,524,296 1,579,029 1,319,633 Other income and (expenses) (57,030 ) (77,870 ) (88,991 ) Reorganization items, net (46,127 ) — — Income (loss) from discontinued operations before income taxes (1,239,747 ) (1,015,245 ) 22,665 Income tax expense (benefit) 196 (68 ) 69 Income (loss) from discontinued operations, net of income taxes $ (1,239,943 ) $ (1,015,177 ) $ 22,596 (1) Results of discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016. In addition, for the year ended December 31, 2016 , the Company recognized a noncash loss on the deconsolidation of Berry of approximately $546 million . The loss is included in “income (loss) from discontinued operations, net of income taxes” on the consolidated statement of operations. The following table presents carrying amounts of the assets and liabilities of the Company’s discontinued operations on the consolidated balance sheet: December 31, 2015 (in thousands) ASSETS Current assets: Cash and cash equivalents $ 1,023 Accounts receivable – trade, net 46,053 Other 34,115 Current assets of discontinued operations $ 81,191 Noncurrent assets: Oil and natural gas properties (successful efforts method), net $ 3,414,896 Restricted cash 250,359 Other 115,030 Noncurrent assets of discontinued operations $ 3,780,285 LIABILITIES Current liabilities: Accounts payable and accrued expenses $ 125,748 Current portion of long-term debt 873,175 Other 18,976 Current liabilities of discontinued operations $ 1,017,899 Noncurrent liabilities: Long-term debt, net $ 845,368 Other 212,050 Noncurrent liabilities of discontinued operations $ 1,057,418 Divestiture – 2015 On August 31, 2015, the Company 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 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 on divestitures in 2014 are included in “(gains) losses on 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 a 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 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 $50 million , including costs to sell of approximately $3 million . On August 15, 2014, the Company 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 $99 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 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. 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. As of February 2014, the Company had fully funded the total commitment of $400 million .

Unitholders' Capital (Deficit)

Unitholders' Capital (Deficit)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Unitholders' Capital (Deficit)	Unitholders’ Capital (Deficit) Cancellation of Awards In December 2016, the Company canceled all of its then-outstanding nonvested restricted units without consideration given to the employees, decreasing the Company’s units issued and outstanding by 2,230,182 . Delisting from Stock Exchange As a result of the Company’s failure to comply with the NASDAQ Global Select Market (“NASDAQ”) continued listing requirements, on May 24, 2016, the Company’s units began trading over the counter on the OTC Markets Group Inc.’s Pink marketplace under the trading symbol “LINEQ.” At-the-Market Offering Program The Company’s Board of Directors had authorized the sale of up to $500 million of units under an at-the-market offering program, with sales of units, if any, to be made under an equity distribution agreement. No sales were made under the equity distribution agreement during the year ended December 31, 2016 . 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). 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 . Distributions Under the Predecessor’s limited liability company agreement, unitholders were entitled to receive a distribution of available cash, which included cash on hand plus borrowings less any reserves established by the Predecessor’s Board of Directors to provide for the proper conduct of the Predecessor’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. Monthly distributions were paid by the Company through September 2015. Distributions paid by the Company during 2015 and 2014 are presented on the consolidated statements of unitholders’ capital (deficit) and the consolidated statements of cash flows. In October 2015, the Predecessor’s Board of Directors determined to suspend payment of the Predecessor’s distribution. The Successor currently has no intention of paying cash dividends and any future payment of cash dividends would be subject to the restrictions in the Exit Facility. Unit Repurchase Plan The Company’s Board of Directors had 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 Company did not repurchase any units during the years ended December 31, 2016 , December 31, 2015 , or December 31, 2014 .

Unit-Based Compensation and Oth

Unit-Based Compensation and Other Benefit Plans	12 Months Ended
	Dec. 31, 2016
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 “LTIP”), was effective from December 2005 through February 28, 2017. The LTIP limits the number of units that may be delivered pursuant to awards to 21 million . The LTIP, which was 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 LTIP. 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. 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 LTIP 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 LTIP to serve as a means of incentive compensation for performance. Therefore, LTIP participants do not pay any consideration for the units they receive. 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 LTIP to serve as a means of incentive compensation for performance. Therefore, LTIP participants do not pay any consideration for the units they receive. 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. 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 LTIP to serve as a means of incentive compensation for performance. Therefore, LTIP participants do not pay any consideration for the units they receive. 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. Cancellation of Awards In December 2016, the Company canceled all of its then-outstanding nonvested restricted units, phantom units and performance unit awards, as well as its then-outstanding unit options, without consideration given to the employees. As a result, the Company recognized unit-based compensation expenses of approximately $14 million for the year ended December 31, 2016 , associated with previously unrecognized compensation costs for awards that were canceled before the completion of the requisite service period. There were no awards outstanding under the LTIP as of December 31, 2016 . 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 on the consolidated statements of operations is presented below: Year Ended December 31, 2016 2015 2014 (in thousands) General and administrative expenses $ 34,268 $ 47,312 $ 45,195 Lease operating expenses 9,950 8,824 8,089 Total unit-based compensation expenses $ 44,218 $ 56,136 $ 53,284 Income tax benefit $ 16,339 $ 20,742 $ 19,688 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, 2016 , 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, 2015 4,926,572 $ 16.22 Vested (2,069,004 ) $ 19.66 Forfeited (349,243 ) $ 14.29 Canceled (2,508,325 ) $ 13.95 Nonvested units at December 31, 2016 — $ — No restricted units, phantom units or unrestricted units were granted during the year ended December 31, 2016 . The weighted average grant-date fair value of restricted units, phantom units and unrestricted units granted was $10.21 per unit and $33.10 per unit during the years ended December 31, 2015 , and December 31, 2014 , respectively. The total fair value of units that vested was approximately $41 million , $49 million and $42 million for the years ended December 31, 2016 , December 31, 2015 , and December 31, 2014 , respectively. There were no unrecognized compensation costs as of December 31, 2016 . 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 were to vest three years from the award date, with vesting 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 was to be paid in cash. To date, no performance units have vested and no amounts have been paid to settle any such awards. In December 2016, the Company canceled all of its then-outstanding nonvested performance unit awards. There were no awards outstanding under the LTIP as of December 31, 2016 . Unit Options The following provides information related to unit option activity for the year ended December 31, 2016 : 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, 2015 824,711 $ 22.72 2.27 $ — Forfeited or expired (184,498 ) $ 25.80 Canceled (640,213 ) $ 21.83 Outstanding at December 31, 2016 — $ — — $ — Exercisable at December 31, 2016 — $ — — $ — No unit options were granted during the years ended December 31, 2016 , December 31, 2015 or December 31, 2014 . There were no unit options exercised during the years ended December 31, 2016 , or December 31, 2015 . During the year ended December 31, 2014 , the total intrinsic value of unit options exercised was approximately $11 million . There were no unrecognized compensation costs as of December 31, 2016 . Defined Contribution Plan The Company sponsors a 401(k) defined contribution plan for eligible employees. For the years 2014 through 2016, Company contributions to the 401(k) plan consisted 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 $9 million , $11 million and $10 million during the years ended December 31, 2016 , December 31, 2015 , and December 31, 2014 , 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, 2016
Debt Disclosure [Abstract]
Debt	Debt The following summarizes the Company’s outstanding debt: December 31, 2016 2015 (in thousands, except percentages) LINN credit facility (1) $ 1,654,745 $ 2,215,000 Berry credit facility (2) — 873,175 Term loan (2) 284,241 500,000 6.50% senior notes due May 2019 562,234 562,234 6.25% senior notes due November 2019 581,402 581,402 8.625% senior notes due April 2020 718,596 718,596 6.75% Berry senior notes due November 2020 — 261,100 12.00% senior secured second lien notes due December 2020 (3) 1,000,000 1,000,000 Interest payable on senior secured second lien notes due December 2020 (3) — 608,333 7.75% senior notes due February 2021 779,474 779,474 6.50% senior notes due September 2021 381,423 381,423 6.375% Berry senior notes due September 2022 — 572,700 Net unamortized discounts and premiums (4) — (8,694 ) Net unamortized deferred financing fees (4) (1,257 ) (37,374 ) Total debt, net 5,960,858 9,007,369 Less current portion, net (5) (1,937,729 ) (2,841,518 ) Less liabilities subject to compromise (6) (4,023,129 ) — Less debt and unamortized premiums of discontinued operations — (1,718,543 ) Long-term debt, net $ — $ 4,447,308 (1) Variable interest rates of 5.50% and 2.66% at December 31, 2016 , and December 31, 2015 , respectively. (2) Variable interest rates of 5.50% and 3.17% at December 31, 2016 , and December 31, 2015 , respectively. (3) The issuance of the Second Lien Notes was accounted for as a troubled debt restructuring which requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. During the year ended December 31, 2016, $551 million was written off to reorganization items in connection with the filing of the Bankruptcy Petitions. The remaining amount of approximately $57 million was classified as liabilities subject to compromise at December 31, 2016 . (4) Approximately $52 million in net discounts, premiums and deferred financing fees were written off to reorganization items in connection with the filing of the Bankruptcy Petitions. (5) Due to existing and anticipated covenant violations, the Company’s Credit Facilities and term loan were classified as current at December 31, 2016 , and December 31, 2015 . The current portion as of December 31, 2015 , also includes approximately $128 million of interest payable on the Second Lien Notes that was due within one year. (6) The Company’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016 . As described in Note 3, the Company deconsolidated Berry effective December 3, 2016. Therefore, the Company reports no debt for Berry as of December 31, 2016. Fair Value The Company’s debt is recorded at the carrying amount on 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, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (in thousands) Senior secured second lien notes $ 1,000,000 $ 863,750 $ 1,000,000 $ 501,250 Senior notes, net 3,023,129 1,179,224 2,967,308 461,930 Credit Facilities LINN Credit Facility The Predecessor’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) provides for (1) a senior secured revolving credit facility and (2) a senior secured term loan, in aggregate subject to the then-effective borrowing base. The maturity date is April 2019, subject to a “springing maturity” based on the maturity of any outstanding LINN Energy junior lien debt. At December 31, 2016 , the Company had approximately $1.7 billion in total borrowings outstanding (including outstanding letters of credit) under the revolving credit facility and approximately $284 million under the term loan, and there was no remaining availability. See Note 2 for details of the amendment to the LINN Credit Facility entered into on April 12, 2016. 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. The Company’s obligations under the LINN Credit Facility are secured by mortgages on certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in the Company’s direct and indirect material subsidiaries. The Company is required to maintain: 1) mortgages on properties representing at least 90% of the total value of oil and natural gas properties included on its most recent reserve report; 2) 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; and 3) an EBITDA to Interest Expense ratio of at least 2.0 to 1.0 currently, 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and 2.5 to 1.0 thereafter. 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 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 monthly 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 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 monthly 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”) provides for a senior secured revolving credit facility, subject to the then-effective borrowing base. The maturity date is April 2019. 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. Berry’s obligations under the Berry Credit Facility are secured by mortgages on its oil and natural gas properties and other personal property. Berry is required to maintain: 1) mortgages on properties representing at least 90% of the present value of oil and natural gas properties included on its most recent reserve report, and 2) an EBITDAX to Interest Expense ratio of at least 2.0 to 1.0 currently, 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and 2.5 to 1.0 thereafter. In accordance with the amendment described in Note 2, the lenders had agreed that the failure to maintain the EBITDAX to Interest Expense ratio would not result in a default or event of default until May 11, 2016. At Berry’s election, interest on borrowings under the Berry Credit Facility is determined by reference to either the LIBOR plus an applicable margin between 1.75% 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 monthly 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 0.50% 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.” The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the Credit Facilities. However, under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of the default. 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: Par Value of Senior Notes Exchanged (in thousands) 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 for the year ended December 31, 2015 , and included in “gain 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. Repurchases of Senior Notes The Company made no repurchases of its senior notes during the year ended December 31, 2016 . During the year ended December 31, 2015 , the Company repurchased, through privately negotiated transactions and on the open market, approximately $927 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 ; • 7.75% senior notes due February 2021 – $36 million ; and • 6.50% senior notes due September 2021 – $148 million . In connection with the repurchases, the Company paid approximately $553 million in cash and recorded a gain on extinguishment of debt of approximately $356 million for the year ended December 31, 2015 . Notes Covenants The Second Lien Indenture contains covenants that, among other things, may 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. 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. 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. In addition, any cash generated by Berry is currently being used by Berry to fund its activities. Historically, to the extent that Berry generated cash in excess of its needs and determined to distribute such amounts to LINN Energy, the indentures governing Berry’s senior notes limited the amount it could distribute to LINN Energy to the amount available under a “restricted payments basket,” and Berry could 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. During the pendency of the bankruptcy proceedings, Berry did not distribute cash to LINN Energy using the restricted payments basket. The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the Second Lien Indenture and the senior notes. However, under the Bankruptcy Code, holders of the Second Lien Notes and the senior notes were stayed from taking any action against the Company as a result of the default. Covenant Violations The Company’s filing of the Bankruptcy Petitions described in Note 2 constituted an event of default that accelerated the Company’s obligations under its Credit Facilities, its Second Lien Notes and its senior notes. Additionally, other events of default, including cross-defaults, have occurred, including the failure to make interest payments on the Company’s Second Lien Notes and senior notes, as well as the receipt of a going concern explanatory paragraph from the Company’s independent registered public accounting firm on the Company’s consolidated financial statements for the year ended December 31, 2015 . Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of an event of default.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives Commodity Derivatives Historically, 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. 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 has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials. The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars 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. 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, 2016 : 2017 2018 2019 Natural gas positions: Fixed price swaps (NYMEX Henry Hub): Hedged volume (MMMBtu) 135,050 40,150 3,650 Average price ($/MMBtu) $ 3.17 $ 3.02 $ 3.08 Oil positions: Fixed price swaps (NYMEX WTI): Hedged volume (MBbls) 4,380 — — Average price ($/Bbl) $ 52.13 $ — $ — Collars (NYMEX WTI): Hedged volume (MBbls) — 1,825 1,825 Average floor price ($/Bbl) $ — $ 50.00 $ 50.00 Average ceiling price ($/Bbl) $ — $ 55.50 $ 55.50 In accordance with a Bankruptcy Court order dated August 16, 2016, the Company was authorized to enter into postpetition hedging arrangements. During the year ended December 31, 2016 , LINN Energy entered into commodity derivative contracts consisting of natural gas swaps for October 2016 through December 2019, oil swaps for November 2016 through December 2017, and oil collars for January 2018 through December 2019. In April 2016 and May 2016, in connection with the Company’s restructuring efforts, LINN Energy canceled (prior to the contract settlement dates) all of its then-outstanding derivative contracts for net proceeds of approximately $1.2 billion . The net proceeds were used to make permanent repayments of a portion of the borrowings outstanding under the LINN Credit Facility. 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. 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, 2016 2015 (in thousands) Assets: Commodity derivatives $ 19,369 $ 1,798,568 Liabilities: Commodity derivatives $ 113,226 $ 26,012 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 the LINN Credit Facility and the Exit Facility. The LINN Credit Facility was secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company was 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 $19 million at December 31, 2016 . The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated. Gains (Losses) on Derivatives Gains and losses on derivatives were net losses of approximately $164 million for the year ended December 31, 2016 , and net gains of approximately $1.0 billion and $1.1 billion for the years ended December 31, 2015 , and December 31, 2014 , respectively, and are reported on the consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.” For the years ended December 31, 2016 , December 31, 2015 , and December 31, 2014 , the Company received net cash settlements of approximately $861 million , $1.1 billion and $89 million , respectively. In addition, during the year ended December 31, 2016 , approximately $841 million in settlements (primarily in connection with the April 2016 and May 2016 commodity derivative cancellations) were paid directly by the counterparties to the lenders under the LINN Credit Facility as repayments of a portion of the borrowings outstanding.

Fair Value Measurements on a Re

Fair Value Measurements on a Recurring Basis	12 Months Ended
	Dec. 31, 2016
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 and public bond yield 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, 2016 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 19,369 $ (19,369 ) $ — Liabilities: Commodity derivatives $ 113,226 $ (19,369 ) $ 93,857 December 31, 2015 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 1,798,568 $ (25,155 ) $ 1,773,413 Liabilities: Commodity derivatives $ 26,012 $ (25,155 ) $ 857 (1) Represents counterparty netting under agreements governing such derivatives.

Other Property and Equipment

Other Property and Equipment	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Other Property and Equipment	Other Property and Equipment Other property and equipment consists of the following: December 31, 2016 2015 (in thousands) Natural gas plant and pipeline $ 421,806 $ 480,161 Furniture and office equipment 105,353 106,462 Buildings and leasehold improvements 66,014 72,976 Vehicles 31,496 37,641 Drilling and other equipment 8,082 7,934 Land 3,736 3,537 636,487 708,711 Less accumulated depreciation (224,547 ) (195,661 ) Less other property and equipment, net – discontinued operations — (98,973 ) $ 411,940 $ 414,077

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
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; ); and (iv) a credit-adjusted risk-free interest rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The following table presents a reconciliation of the Company’s asset retirement obligations: December 31, 2016 2015 (in thousands) Asset retirement obligations at beginning of year $ 523,541 $ 497,570 Liabilities added from drilling 546 3,574 Liabilities added from acquisitions 1,416 — Liabilities associated with assets divested — (3,306 ) Deconsolidation of Berry Petroleum Company, LLC asset retirement obligations (141,612 ) — Current year accretion expense 30,498 30,016 Settlements (12,823 ) (6,336 ) Revision of estimates 596 2,023 402,162 523,541 Less asset retirement obligations of discontinued operations — (137,563 ) Asset retirement obligations at end of year $ 402,162 $ 385,978

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies On May 11, 2016, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16‑60040. On January 27, 2017, the Bankruptcy Court entered the Confirmation Order. Consummation of the LINN Plan was subject to certain conditions set forth in the LINN Plan. On the Effective Date, all of the conditions were satisfied or waived and the LINN Plan became effective and was implemented in accordance with its terms. The LINN Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates. For certain statewide class action royalty payment disputes, the Company filed notices advising that it had filed for bankruptcy protection and seeking a stay, which was granted. However, the Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings. 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, 2016 , December 31, 2015 , and December 31, 2014 , 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.

Operating Leases

Operating Leases	12 Months Ended
	Dec. 31, 2016
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 $9 million , $15 million and $7 million for the years ended December 31, 2016 , December 31, 2015 , and December 31, 2014 , respectively. As of December 31, 2016 , future minimum lease payments were as follows (in thousands): 2017 $ 3,627 2018 2,852 2019 2,008 2020 468 2021 4 Thereafter 60 $ 9,019

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Earnings Per Unit	Earnings Per Unit Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect. The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net income (loss): Year Ended December 31, 2016 2015 2014 (in thousands, except per unit data) Loss from continuing operations $ (385,697 ) $ (3,744,634 ) $ (474,405 ) Allocated to participating securities — (3,039 ) (7,117 ) $ (385,697 ) $ (3,747,673 ) $ (481,522 ) Income (loss) from discontinued operations, net of income taxes $ (1,786,159 ) $ (1,015,177 ) $ 22,596 Net loss $ (2,171,856 ) $ (4,759,811 ) $ (451,809 ) Allocated to participating securities — (3,039 ) (7,117 ) $ (2,171,856 ) $ (4,762,850 ) $ (458,926 ) Basic loss per unit – continuing operations $ (1.10 ) $ (10.91 ) $ (1.47 ) Diluted loss per unit – continuing operations $ (1.10 ) $ (10.91 ) $ (1.47 ) Basic income (loss) per unit – discontinued operations $ (5.06 ) $ (2.96 ) $ 0.07 Diluted income (loss) per unit – discontinued operations $ (5.06 ) $ (2.96 ) $ 0.07 Basic net loss per unit $ (6.16 ) $ (13.87 ) $ (1.40 ) Diluted net loss per unit $ (6.16 ) $ (13.87 ) $ (1.40 ) Basic weighted average units outstanding 352,653 343,323 328,918 Dilutive effect of unit equivalents — — — Diluted weighted average units outstanding 352,653 343,323 328,918 Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 1 million , 4 million and 6 million unit options and warrants for the years ended December 31, 2016 , December 31, 2015 , and December 31, 2014 , respectively. All equivalent units were antidilutive for each of the years ended December 31, 2016 , December 31, 2015 , and December 31, 2014 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Prior to the consummation of the LINN Plan, the Company was 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 Predecessor is not a taxable entity. The Predecessor 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 Predecessor, 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, 2016 2015 2014 (in thousands) Current taxes: Federal $ (494 ) $ (12,021 ) $ 473 State 321 1,022 21 Deferred taxes: Federal 11,582 8,237 (104 ) State (215 ) (3,631 ) 3,978 $ 11,194 $ (6,393 ) $ 4,368 As of December 31, 2016 , the Company’s taxable entities had approximately $5 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, 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State, net of federal tax benefit 0.7 0.1 (0.9 ) Loss excluded from nontaxable entities (24.7 ) (34.7 ) (34.5 ) Other (14.0 ) (0.2 ) (0.5 ) Effective rate (3.0 )% 0.2 % (0.9 )% Significant components of the deferred tax assets and liabilities were as follows: December 31, 2016 2015 (in thousands) Deferred tax assets: Net operating loss carryforwards $ 1,730 $ 370 Reorganization items 14,932 — Unit-based compensation — 18,214 Valuation allowance (19,558 ) (2,159 ) Other 10,030 7,300 Total deferred tax assets 7,134 23,725 Deferred tax liabilities: Property and equipment principally due to differences in depreciation (7,021 ) (12,534 ) Other (279 ) 10 Total deferred tax liabilities (7,300 ) (12,524 ) Net deferred tax assets (liabilities) $ (166 ) $ 11,201 The net deferred tax liabilities are recorded in “other noncurrent liabilities” and the net deferred tax assets are recorded in “other noncurrent assets” on the consolidated balance sheets at December 31, 2016 , and December 31, 2015 , respectively. 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, 2016 , based on projections of future taxable income for the periods in which the deferred tax assets are deductible, valuation allowances of approximately $20 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. 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, 2016 , or December 31, 2015 . The tax years 2013 through 2016 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, 2016
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 current assets” reported on the balance sheets include the following: December 31, 2016 2015 (in thousands) Prepaid expenses $ 70,116 $ 29,237 Inventories 15,798 19,184 Deferred financing fees 16,809 25,090 Other 4,890 1,185 Other current assets $ 107,613 $ 74,696 Supplemental disclosures to the consolidated statements of cash flows are presented below: Year Ended December 31, 2016 2015 2014 (in thousands) Cash payments for interest, net of amounts capitalized $ 143,305 $ 476,077 $ 446,860 Cash payments for income taxes $ 4,427 $ 643 $ — Cash payments for reorganization items, net $ 37,748 $ — $ — Noncash investing activities: In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follow: Fair value of assets acquired $ — $ — $ 2,733,814 Cash paid, net of cash acquired — — (2,398,763 ) Noncash gains on exchanges of properties — — (149,195 ) Receivables from sellers — — 10,369 Liabilities assumed $ — $ — $ 196,225 Accrued capital expenditures $ 31,128 $ 71,105 $ 180,447 For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $8 million and $7 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2016 , and December 31, 2015 , respectively, and represents cash deposited by the Company into a separate account designated for asset retirement obligations in accordance with contractual agreements. During the year ended December 31, 2016 , approximately $841 million in commodity derivative settlements (primarily in connection with the April 2016 and May 2016 commodity derivative cancellations) were paid directly by the counterparties to the lenders under the LINN Credit Facility as repayments of a portion of the borrowings outstanding, and are reflected as noncash transactions by the Company. At December 31, 2016 , and December 31, 2015 , net outstanding checks of approximately $6 million and $21 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. Included in “acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired” on the consolidated statement of cash flows for the year ended December 31, 2014 , is approximately $25 million paid by the Company towards the future funding commitment related to the joint-venture agreement entered into with Anadarko (see Note 3). 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 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 completed a noncash exchange of a portion of its Permian Basin properties to Exxon XTO for properties in the Hugoton Basin.

Significant Customers

Significant Customers	12 Months Ended
	Dec. 31, 2016
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, 2016 , December 31, 2015 , and December 31, 2014 , no individual customer exceeded 10% of the Company’s sales. At December 31, 2016 , no individual customer exceeded 10% of the Company’s receivables. At December 31, 2015 , trade accounts receivable from one customer represented approximately 12% of the Company’s receivables.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Berry Petroleum Company, LLC Berry, a former subsidiary of LINN Energy, was deconsolidated effective December 3, 2016 (see Note 3). The employees of Linn Operating, Inc. (“LOI”), a subsidiary of LINN Energy, provided services and support to Berry in accordance with an agency agreement and power of attorney between Berry and LOI. Upon deconsolidation, transactions between the Company and Berry are no longer eliminated in consolidation and are treated as related party transactions. These transactions include, but are not limited to, management fees paid to the Company by Berry. For the years ended December 31, 2016 , December 31, 2015 , and December 31, 2014 , Berry incurred management fees to the Company of approximately $69 million , $78 million and $86 million , respectively, for services provided by LOI. The Company also had accounts payable due to Berry of approximately $3 million included in “accounts payable and accrued expenses” and accounts receivable due from Berry of approximately $9 million included in “accounts receivable – trade, net” on the consolidated balance sheets at December 31, 2016 , and December 31, 2015 , respectively. In addition, $25 million due to Berry was included in “liabilities subject to compromise” on the Company’s consolidated balance sheet at December 31, 2016 . The Company made no capital contributions to Berry during the year ended December 31, 2016 . During the year ended December 31, 2015 , the Company made capital contributions of approximately $471 million to Berry, including $250 million which was deposited on Berry’s behalf and posted as restricted cash with Berry’s lenders in connection with the reduction of its borrowing base in May 2015. During the second quarter of 2014, the Company made a cash capital contribution of approximately $220 million to Berry which was used to pay in full the remaining outstanding principal amount of Berry’s approximate $205 million 10.25% senior notes due June 2014 plus accrued interest. The Company received no cash distributions from Berry during the year ended December 31, 2016 . During the years ended December 31, 2015 , and December 31, 2014 , the Company received cash distributions of approximately $89 million and $119 million , respectively, from Berry. In addition, in 2014, Berry advanced approximately $352 million to the Company. The Company was required to use the cash from the advance on capital expenditures in respect of Berry’s operations, to repay Berry’s indebtedness or as otherwise permitted under the terms of Berry’s indentures and credit facility. During the twelve months ended September 30, 2015, the Company spent approximately $223 million , including approximately $58 million in 2014, on capital expenditures in respect of Berry’s operations. On September 30, 2015, the Company repaid in full the remaining advance of approximately $129 million to Berry. LinnCo, LLC LinnCo, an affiliate of the Predecessor, was formed on April 30, 2012. LinnCo’s initial sole purpose was to own units in LINN Energy. In connection with the 2013 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 were held by the public. As of December 31, 2016 , LinnCo had no significant assets or operations other than those related to its interest in LINN Energy and owned approximately 71% of LINN Energy’s outstanding units. In March 2016, LinnCo filed a Registration Statement on Form S‑4 related to an offer to exchange each outstanding unit representing limited liability company interests of LINN Energy for one common share representing limited liability company interests of LinnCo. The initial offer expired on April 25, 2016, and on April 26, 2016, LinnCo commenced a subsequent offering period that expired on August 1, 2016. During the exchange period, 123,100,715 LINN Energy units were exchanged for an equal number of LinnCo shares. As a result of the exchanges of LINN Energy units for LinnCo shares, LinnCo’s ownership of LINN Energy’s outstanding units increased from approximately 37% at December 31, 2015 , to approximately 71% at December 31, 2016 . 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, 2016 , LinnCo incurred total general and administrative expenses, reorganization expenses and offering costs of approximately $6.1 million , including approximately $2.4 million related to services provided by LINN Energy. Of the expenses and costs incurred during 2016, approximately $5.9 million had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2016 . For the year ended December 31, 2015 , LinnCo incurred total general and administrative expenses and certain offering costs of approximately $3.4 million , including approximately $2.0 million related to services provided by LINN Energy. All of the expenses and costs incurred during 2015 had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2015 . For the year ended December 31, 2014 , LinnCo incurred total general and administrative expenses and offering costs of approximately $2.9 million , including approximately $1.9 million related to services provided by LINN Energy. All of the expenses and costs incurred during 2014 had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2014. 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. The Company did not pay any distributions to LinnCo during the year ended December 31, 2016 . During the years ended December 31, 2015 , and December 31, 2014 , the Company paid approximately $121 million and $373 million , respectively, in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy. Other One of the Company’s former 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, 2016 , December 31, 2015 , and December 31, 2014 , the Company incurred expenditures of approximately $5 million , $8 million and $21 million , respectively, related to services rendered by Superior and its subsidiaries.

Subsidiary Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2016
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Subsidiary Guarantors	Subsidiary Guarantors Linn Energy, LLC’s senior notes due May 2019, senior notes due November 2019, senior notes due April 2020, Second Lien Notes, senior notes due February 2021 and senior notes due September 2021 are guaranteed by all of the Company’s material subsidiaries, other than Berry, which was an indirect 100% wholly owned subsidiary of the Company. As a result of the Chapter 11 proceedings, LINN Energy deconsolidated Berry effective December 3, 2016. The Company is a holding company and has no independent assets or operations of its own, the guarantees under each series of notes are full and unconditional and joint and several, and any consolidated subsidiaries of the Company other than the subsidiary guarantors are minor. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.

Supplemental Oil and Natural Ga

Supplemental Oil and Natural Gas Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 (in thousands) Property acquisition costs: (1) Proved $ — $ — $ 2,306,541 Unproved — — 793,742 Exploration costs 40,074 19,929 644 Development costs 86,053 298,028 925,750 Asset retirement costs 419 4,152 14,855 Total costs incurred – continuing operations $ 126,546 $ 322,109 $ 4,041,532 Total costs incurred – discontinued operations $ 11,147 $ 132,427 $ 1,040,152 (1) See Note 3 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, 2016 2015 (in thousands) Proved properties $ 12,234,099 $ 16,337,814 Unproved properties 998,860 1,783,341 13,232,959 18,121,155 Less accumulated depletion and amortization (9,999,560 ) (11,097,492 ) 3,233,399 7,023,663 Less oil and natural gas capitalized costs, net – discontinued operations — (3,414,896 ) $ 3,233,399 $ 3,608,767 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, 2016 2015 2014 (in thousands) Revenues and other: Oil, natural gas and natural gas liquids sales $ 952,132 $ 1,151,240 $ 2,312,137 Gains (losses) on oil and natural gas derivatives (164,330 ) 1,027,014 1,127,395 787,802 2,178,254 3,439,532 Production costs: Lease operating expenses 317,046 375,840 443,157 Transportation expenses 161,037 167,561 165,489 Severance taxes, ad valorem taxes and California carbon allowances 73,806 111,350 169,417 551,889 654,751 778,063 Other costs: Exploration costs 4,080 9,473 125,037 Depletion and amortization 356,825 504,493 726,567 Impairment of long-lived assets 165,044 4,960,144 2,050,387 (Gains) losses on sale of assets and other, net 417 (199,296 ) (501,036 ) Texas margin tax expense (benefit) (649 ) (2,721 ) 3,984 525,717 5,272,093 2,404,939 Results of operations – continuing operations $ (289,804 ) $ (3,748,590 ) $ 256,530 Results of operations – discontinued operations (1) $ (1,066,634 ) $ (858,833 ) $ 213,280 (1) The results of discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016. 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 Securities and Exchange Commission (“SEC”) regulations, reserves at December 31, 2016 , December 31, 2015 , and December 31, 2014 , 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, 2016 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 2,231 103.4 97.3 3,435 1,053 4,488 Revisions of previous estimates (9 ) (4.3 ) 0.9 (29 ) (179 ) (208 ) Extensions, discoveries and other additions 265 10.1 15.2 417 11 428 Production (187 ) (10.0 ) (9.3 ) (303 ) (81 ) (384 ) Deconsolidation of Berry Petroleum Company, LLC proved reserves — — — — (804 ) (804 ) End of year 2,300 99.2 104.1 3,520 — 3,520 Proved developed reserves: Beginning of year 2,231 103.4 97.3 3,435 1,053 4,488 End of year 2,128 93.3 94.4 3,254 — 3,254 Proved undeveloped reserves: Beginning of year — — — — — — End of year 172 5.9 9.7 266 — 266 Year Ended December 31, 2015 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 3,568 197.4 146.3 5,631 1,673 7,304 Revisions of previous estimates (1,134 ) (81.9 ) (38.4 ) (1,855 ) (524 ) (2,379 ) Sales of minerals in place (13 ) (4.1 ) (2.0 ) (50 ) — (50 ) Extensions, discoveries and other additions 10 3.8 0.8 37 10 47 Production (200 ) (11.8 ) (9.4 ) (328 ) (106 ) (434 ) End of year 2,231 103.4 97.3 3,435 1,053 4,488 Proved developed reserves: Beginning of year 2,997 141.7 117.5 4,552 1,266 5,818 End of year 2,231 103.4 97.3 3,435 1,053 4,488 Proved undeveloped reserves: Beginning of year 571 55.7 28.8 1,079 407 1,486 End of year — — — — — — Year Ended December 31, 2014 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 2,730 194.7 183.5 4,999 1,404 6,403 Revisions of previous estimates 54 (13.0 ) (45.3 ) (297 ) (21 ) (318 ) Purchases of minerals in place 1,354 45.0 54.4 1,951 544 2,495 Sales of minerals in place (426 ) (22.8 ) (37.2 ) (786 ) (298 ) (1,084 ) Extensions, discoveries and other additions 36 6.7 2.5 92 158 250 Production (180 ) (13.2 ) (11.6 ) (328 ) (114 ) (442 ) End of year 3,568 197.4 146.3 5,631 1,673 7,304 Proved developed reserves: Beginning of year 1,824 138.7 125.2 3,407 933 4,340 End of year 2,997 141.7 117.5 4,552 1,266 5,818 Proved undeveloped reserves: Beginning of year 906 56.0 58.3 1,592 471 2,063 End of year 571 55.7 28.8 1,079 407 1,486 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. Berry was deconsolidated effective December 3, 2016, and its reserves are reported as discontinued operations for all periods presented. Proved reserves from continuing operations increased by approximately 85 Bcfe to approximately 3,520 Bcfe for the year ended December 31, 2016 , from 3,435 Bcfe for the year ended December 31, 2015 . The year ended December 31, 2016 , includes approximately 29 Bcfe of negative revisions of previous estimates ( 107 Bcfe due to lower commodity prices partially offset by 78 Bcfe of positive revisions due to asset performance). In addition, extensions and discoveries, primarily from 211 productive wells drilled during the year, contributed approximately 417 Bcfe to the increase in proved reserves. Proved reserves from continuing operations decreased by approximately 2,196 Bcfe to approximately 3,435 Bcfe for the year ended December 31, 2015 , from 5,631 Bcfe for the year ended December 31, 2014 . The year ended December 31, 2015 , includes approximately 1,855 Bcfe of negative revisions of previous estimates ( 1,348 Bcfe due to lower commodity prices, 258 Bcfe due to uncertainty regarding the Company’s future commitment to capital, 237 Bcfe due to the SEC five-year development limitation on PUDs and 12 Bcfe of negative 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 388 productive wells drilled during the year, contributed approximately 37 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 at December 31, 2015 . Proved reserves from continuing operations increased by approximately 632 Bcfe to approximately 5,631 Bcfe for the year ended December 31, 2014 , from 4,999 Bcfe for the year ended December 31, 2013. The year ended December 31, 2014 , includes approximately 297 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, 129 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs and 22 Bcfe of negative revisions due to asset performance, partially offset by 28 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 1,951 Bcfe and the 2014 divestitures and properties relinquished in the two exchanges with Exxon XTO and ExxonMobil decreased proved reserves by approximately 786 Bcfe. In addition, extensions and discoveries, primarily from 506 productive wells drilled during the year, contributed approximately 92 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 Predecessor was 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, 2016 2015 2014 (in thousands) Future estimated revenues $ 10,876,241 $ 11,810,044 $ 38,350,590 Future estimated production costs (6,286,264 ) (7,276,564 ) (16,358,433 ) Future estimated development costs (971,055 ) (775,328 ) (2,899,781 ) Future net cash flows 3,618,922 3,758,152 19,092,376 10% annual discount for estimated timing of cash flows (1,690,224 ) (1,719,979 ) (10,910,462 ) Standardized measure of discounted future net cash flows – continuing operations $ 1,928,698 $ 2,038,173 $ 8,181,914 Standardized measure of discounted future net cash flows – discontinued operations $ — $ 995,372 $ 4,330,377 Representative NYMEX prices: (1) Natural gas (MMBtu) $ 2.48 $ 2.59 $ 4.35 Oil (Bbl) $ 42.64 $ 50.16 $ 95.27 (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, 2016 2015 2014 (in thousands) Sales and transfers of oil, natural gas and NGL produced during the period $ (400,243 ) $ (496,489 ) $ (1,534,074 ) Changes in estimated future development costs 18,843 1,069,971 88,324 Net change in sales and transfer prices and production costs related to future production (162,460 ) (6,105,531 ) 421,484 Purchases of minerals in place — — 2,473,512 Sales of minerals in place — (97,785 ) (1,194,601 ) Extensions, discoveries and improved recovery 221,765 69,745 236,395 Previously estimated development costs incurred during the period — 91,719 550,514 Net change due to revisions in quantity estimates (9,291 ) (1,089,624 ) (606,104 ) Accretion of discount 203,817 818,191 726,400 Changes in production rates and other 18,094 (403,938 ) (243,933 ) Change – continuing operations $ (109,475 ) $ (6,143,741 ) $ 917,917 Change – discontinued operations $ (995,372 ) $ (3,335,005 ) $ (304,955 ) 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, 2016
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) 2016: Oil, natural gas and natural gas liquids sales $ 199,849 $ 216,426 $ 257,902 $ 277,955 Gains (losses) on oil and natural gas derivatives 109,453 (183,794 ) 166 (90,155 ) Total revenues and other 346,699 64,851 286,913 219,250 Total expenses (1) 472,912 296,824 331,929 292,194 Losses on sale of assets and other, net 1,269 2,517 2,310 9,462 Reorganization items, net — 485,798 (28,361 ) (145,838 ) Income (loss) from continuing operations (222,927 ) 201,652 (99,927 ) (264,495 ) Income (loss) from discontinued operations, net of income taxes (1,124,819 ) 6,840 (98,438 ) (569,742 ) Net income (loss) (1,347,746 ) 208,492 (198,365 ) (834,237 ) Income (loss) per unit – continuing operations: Basic $ (0.64 ) $ 0.57 $ (0.28 ) $ (0.75 ) Diluted $ (0.64 ) $ 0.57 $ (0.28 ) $ (0.75 ) Income (loss) per unit – discontinued operations: Basic $ (3.19 ) $ 0.02 $ (0.28 ) $ (1.61 ) Diluted $ (3.19 ) $ 0.02 $ (0.28 ) $ (1.61 ) Net income (loss) per unit: Basic $ (3.83 ) $ 0.59 $ (0.56 ) $ (2.36 ) Diluted $ (3.83 ) $ 0.59 $ (0.56 ) $ (2.36 ) (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. 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 $ 293,983 $ 323,038 $ 286,993 $ 247,226 Gains (losses) on oil and natural gas derivatives 421,514 (186,714 ) 521,365 270,849 Total revenues and other 766,984 177,068 839,441 536,520 Total expenses (1) 681,222 420,494 2,113,892 3,284,372 Gains on sale of assets and other, net (7,814 ) (17,185 ) (169,613 ) (878 ) Loss from continuing operations (16,435 ) (350,295 ) (1,032,159 ) (2,345,745 ) Loss from discontinued operations, net of income taxes (322,725 ) (28,832 ) (537,158 ) (126,462 ) Net loss (339,160 ) (379,127 ) (1,569,317 ) (2,472,207 ) Loss per unit – continuing operations: Basic $ (0.05 ) $ (1.04 ) $ (2.94 ) $ (6.69 ) Diluted $ (0.05 ) $ (1.04 ) $ (2.94 ) $ (6.69 ) Loss per unit – discontinued operations: Basic $ (0.98 ) $ (0.08 ) $ (1.53 ) $ (0.36 ) Diluted $ (0.98 ) $ (0.08 ) $ (1.53 ) $ (0.36 ) Net loss per unit: Basic $ (1.03 ) $ (1.12 ) $ (4.47 ) $ (7.05 ) Diluted $ (1.03 ) $ (1.12 ) $ (4.47 ) $ (7.05 ) (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 Sig28

Basis of Presentation and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Business	Nature of Business LINN Energy is an independent oil and natural gas company that was formed on February 14, 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16‑60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017. On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry. As a result of its loss of control of Berry, LINN Energy concluded that it was appropriate to deconsolidate Berry effective on the aforementioned date. The results of operations of Berry are reported as discontinued operations for all periods presented. 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) and North Dakota (Williston Basin); Mid-Continent, which includes properties located in the Anadarko and Arkoma basins in Oklahoma, as well as waterfloods in the Central Oklahoma Platform; TexLa, which includes properties located in east Texas and north Louisiana; Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; California, which includes properties located in the San Joaquin Valley and Los Angeles basins; Permian Basin, which includes properties located in west Texas and southeast New Mexico; and South Texas.
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. In addition, the Company has classified the assets and liabilities, results of operations and cash flows of Berry as discontinued operations in its consolidated financial statements for all periods presented. 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 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements and related disclosures. The adoption of this ASU is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the consolidated balance sheets to cash, cash equivalents and restricted cash on the consolidated statements of cash flows. In March 2016, the FASB issued an ASU that is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Components of this ASU will be applied either prospectively, retrospectively or under a modified retrospective basis (as applicable for the respective provision) as of the date of adoption and is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company is currently evaluating the impact of the adoption of this ASU. For periods following adoption, the Company will recognize excess tax benefits as income tax expense in the consolidated statements of operations and as operating activities in the consolidated statements of cash flows. The Company does not expect this standard to have a material impact on its consolidated financial statements or related disclosures. In February 2016, the FASB issued an ASU that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2018, and interim periods within those years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements and related disclosures. The Company expects the adoption of this ASU to impact its consolidated balance sheets resulting from an increase in both assets and liabilities related to the Company’s leasing activities. In November 2015, the FASB issued an ASU that is intended to simplify the presentation of deferred taxes by requiring that all deferred taxes be classified as noncurrent, presented as a single noncurrent amount for each tax-paying component of an entity. The ASU is effective for fiscal years beginning after December 15, 2016; however, the Company early adopted it on January 1, 2016, on a retrospective basis. The adoption of this ASU resulted in the reclassification of previously-classified net current deferred taxes of approximately $22 million from “other current assets,” as well as previously-classified net noncurrent deferred tax liabilities of approximately $11 million from “other noncurrent liabilities,” to “other noncurrent assets” resulting in net noncurrent deferred taxes of approximately $11 million on the Company’s consolidated balance sheet at December 31, 2015 . There was 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 on the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The Company adopted this ASU on January 1, 2016, on a retrospective basis. The adoption of this ASU resulted in the reclassification of approximately $37 million of unamortized deferred financing fees (which excludes deferred financing fees associated with the Company’s Credit Facilities, as defined in Note 6, which were not reclassified) from an asset to a direct deduction from the carrying amount of the associated debt liability on the consolidated balance sheet at December 31, 2015 . There was 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 the annual periods and interim periods thereafter, and the Company adopted this ASU on December 31, 2016 . The adoption of this ASU had no impact on the Company’s consolidated 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 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 does not plan on early adopting this ASU. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements and related disclosures. The Company expects to use the cumulative-effect transition method, has completed an initial review of its contracts and is developing accounting policies to address the provisions of the ASU, but has not finalized any estimates of the potential impacts.
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 $8 million and $1 million at December 31, 2016 , and December 31, 2015 , respectively.
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 $257,000 , $3 million and $4 million for the years ended December 31, 2016 , December 31, 2015 , and December 31, 2014 , 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 associated with proved oil and natural gas properties: Year Ended December 31, 2016 2015 2014 (in thousands) Mid-Continent region $ 141,902 $ 405,370 $ 244,413 Rockies region 23,142 1,592,256 332,365 Hugoton Basin region — 1,667,768 — TexLa region — 352,422 4,836 Permian Basin region — 71,990 1,337,444 South Texas region — 42,433 131,329 $ 165,044 $ 4,132,239 $ 2,050,387 The impairment charges in 2016 and 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 $1.4 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 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. 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 evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past. Based on the analysis described above, the Company recorded the following noncash impairment charges 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 $ 827,905 The Company recorded no impairment charges associated with unproved properties for the years ended December 31, 2016, or December 31, 2014 . The impairment charges in 2015 were based primarily on no future plans to develop properties in certain operating areas as a result of declines in commodity prices. 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 statements of operations. Exploration Costs Exploratory 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 no leasehold impairment expenses related to unproved properties during the year ended December 31, 2016 . The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $2 million and $125 million for the years ended December 31, 2015 , and December 31, 2014 , 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 $257,000 , $3 million and $4 million for the years ended December 31, 2016 , December 31, 2015 , and December 31, 2014 , 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 associated with proved oil and natural gas properties: Year Ended December 31, 2016 2015 2014 (in thousands) Mid-Continent region $ 141,902 $ 405,370 $ 244,413 Rockies region 23,142 1,592,256 332,365 Hugoton Basin region — 1,667,768 — TexLa region — 352,422 4,836 Permian Basin region — 71,990 1,337,444 South Texas region — 42,433 131,329 $ 165,044 $ 4,132,239 $ 2,050,387 The impairment charges in 2016 and 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 $1.4 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 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. 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 evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past. Based on the analysis described above, the Company recorded the following noncash impairment charges 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 $ 827,905 The Company recorded no impairment charges associated with unproved properties for the years ended December 31, 2016, or December 31, 2014 . The impairment charges in 2015 were based primarily on no future plans to develop properties in certain operating areas as a result of declines in commodity prices. 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 statements of operations.
Unproved Properties	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 evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past. Based on the analysis described above, the Company recorded the following noncash impairment charges 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 $ 827,905 The Company recorded no impairment charges associated with unproved properties for the years ended December 31, 2016, or December 31, 2014 . The impairment charges in 2015 were based primarily on no future plans to develop properties in certain operating areas as a result of declines in commodity prices. 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 statements of operations.
Other Property and Equipment	Other Property and Equipment Other property and equipment includes natural gas gathering systems, pipelines, furniture and office equipment, buildings, vehicles, information technology equipment, software and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from three to 39 years for the individual asset or group of assets.
Revenue Recognition	Revenue Recognition Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. 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, 2016 , and December 31, 2015 , the Company had natural gas production imbalance receivables of approximately $8 million and $13 million , respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets. At December 31, 2016 , and December 31, 2015 , the Company had natural gas production imbalance payables of approximately $6 million and $11 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.
Restricted Cash	Restricted Cash Restricted cash of approximately $8 million and $7 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2016 , and December 31, 2015 , respectively, and represents cash deposited by the Company into a separate account designated for asset retirement obligations in accordance with contractual agreements.
Derivative Instruments	Derivative Instruments Historically, 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. 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 has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials. The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars 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. 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. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. 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. 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 and public bond yield 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.
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.
Deferred Financing Fees	Deferred Financing Fees The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2016 , net deferred financing fees of approximately $17 million are included in “other current assets” and approximately $1 million are included in “current portion of long-term debt, net” on the consolidated balance sheet. At December 31, 2015 , net deferred financing fees of approximately $25 million are included in “other current assets,” approximately $2 million are included in “current portion of long-term debt, net” and approximately $35 million are included in “long-term debt, net” 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, 2016 , December 31, 2015 , and December 31, 2014 , amortization expense of approximately $10 million , $20 million and $43 million , respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations. For the year ended December 31, 2016 , approximately $33 million were written off to expense and included in “reorganization items, net” on the consolidated statement of operations in connection with the filing of the Bankruptcy Petitions. For the years ended December 31, 2016 , and December 31, 2015 , approximately $1 million and $7 million , respectively, were written off to expense and included in “other, net” on the consolidated statements of operations related to amendments of the Credit Facilities.
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, 2016 , and December 31, 2015 . 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 Prior to the consummation of the LINN Plan, as defined below, the Company was 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 Predecessor is not a taxable entity. The Predecessor 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 Predecessor. 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 Sig29

Basis of Presentation and Significant Accounting Policies Tables (Tables)	12 Months Ended
	Dec. 31, 2016
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 associated with proved oil and natural gas properties: Year Ended December 31, 2016 2015 2014 (in thousands) Mid-Continent region $ 141,902 $ 405,370 $ 244,413 Rockies region 23,142 1,592,256 332,365 Hugoton Basin region — 1,667,768 — TexLa region — 352,422 4,836 Permian Basin region — 71,990 1,337,444 South Texas region — 42,433 131,329 $ 165,044 $ 4,132,239 $ 2,050,387
Impairment of Unproved Oil and Natural Gas Properties	Based on the analysis described above, the Company recorded the following noncash impairment charges 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 $ 827,905

Chapter 11 Proceedings and Co30

Chapter 11 Proceedings and Covenant Violations (Tables)	12 Months Ended
	Dec. 31, 2016
Reorganizations [Abstract]
Schedule of liabilities subject to compromise [Table Text Block]	The following table summarizes the components of liabilities subject to compromise included on the consolidated balance sheet: December 31, 2016 (in thousands) Accounts payable and accrued expenses $ 137,692 Accrued interest payable 144,184 Debt 4,023,129 Liabilities subject to compromise $ 4,305,005
Schedule of Reorganization Items [Table Text Block]	The following table summarizes the components of reorganization items included on the consolidated statement of operations: Year Ended December 31, 2016 (in thousands) Legal and other professional advisory fees $ (56,656 ) Unamortized deferred financing fees, discounts and premiums (52,045 ) Gain related to interest payable on the 12.00% senior secured second lien notes due December 2020 (1) 551,000 Terminated contracts (66,052 ) Other (64,648 ) Reorganization items, net $ 311,599 (1) Represents a noncash gain on the write-off of postpetition contractual interest through maturity , recorded to reflect the carrying value of the liability subject to compromise at its estimated allowed claim amount.

Discontinued Operations, Dive31

Discontinued Operations, Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding (Tables)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Discontinued operations, summarized statements of operations [Table Text Block]	The following table presents summarized financial results of the Company’s discontinued operations on the consolidated statements of operations: Year Ended December 31, 2016 (1) 2015 2014 (in thousands) Revenues and other $ 387,706 $ 641,654 $ 1,431,289 Expenses 1,524,296 1,579,029 1,319,633 Other income and (expenses) (57,030 ) (77,870 ) (88,991 ) Reorganization items, net (46,127 ) — — Income (loss) from discontinued operations before income taxes (1,239,747 ) (1,015,245 ) 22,665 Income tax expense (benefit) 196 (68 ) 69 Income (loss) from discontinued operations, net of income taxes $ (1,239,943 ) $ (1,015,177 ) $ 22,596 (1) Results of discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016.
Discontinued operations, summarized balance sheets [Table Text Block]	The following table presents carrying amounts of the assets and liabilities of the Company’s discontinued operations on the consolidated balance sheet: December 31, 2015 (in thousands) ASSETS Current assets: Cash and cash equivalents $ 1,023 Accounts receivable – trade, net 46,053 Other 34,115 Current assets of discontinued operations $ 81,191 Noncurrent assets: Oil and natural gas properties (successful efforts method), net $ 3,414,896 Restricted cash 250,359 Other 115,030 Noncurrent assets of discontinued operations $ 3,780,285 LIABILITIES Current liabilities: Accounts payable and accrued expenses $ 125,748 Current portion of long-term debt 873,175 Other 18,976 Current liabilities of discontinued operations $ 1,017,899 Noncurrent liabilities: Long-term debt, net $ 845,368 Other 212,050 Noncurrent liabilities of discontinued operations $ 1,057,418

Unit-Based Compensation and O32

Unit-Based Compensation and Other Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2016
Unit Based Compensation and Other Benefit Plans [Abstract]
Employee Service Share-Based Compensation Expense	A summary of unit-based compensation expenses included on the consolidated statements of operations is presented below: Year Ended December 31, 2016 2015 2014 (in thousands) General and administrative expenses $ 34,268 $ 47,312 $ 45,195 Lease operating expenses 9,950 8,824 8,089 Total unit-based compensation expenses $ 44,218 $ 56,136 $ 53,284 Income tax benefit $ 16,339 $ 20,742 $ 19,688
Nonvested Units	As of December 31, 2016 , 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, 2015 4,926,572 $ 16.22 Vested (2,069,004 ) $ 19.66 Forfeited (349,243 ) $ 14.29 Canceled (2,508,325 ) $ 13.95 Nonvested units at December 31, 2016 — $ —
Unit Options Activity	The following provides information related to unit option activity for the year ended December 31, 2016 : 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, 2015 824,711 $ 22.72 2.27 $ — Forfeited or expired (184,498 ) $ 25.80 Canceled (640,213 ) $ 21.83 Outstanding at December 31, 2016 — $ — — $ — Exercisable at December 31, 2016 — $ — — $ —

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Summary of Outstanding Debt	The following summarizes the Company’s outstanding debt: December 31, 2016 2015 (in thousands, except percentages) LINN credit facility (1) $ 1,654,745 $ 2,215,000 Berry credit facility (2) — 873,175 Term loan (2) 284,241 500,000 6.50% senior notes due May 2019 562,234 562,234 6.25% senior notes due November 2019 581,402 581,402 8.625% senior notes due April 2020 718,596 718,596 6.75% Berry senior notes due November 2020 — 261,100 12.00% senior secured second lien notes due December 2020 (3) 1,000,000 1,000,000 Interest payable on senior secured second lien notes due December 2020 (3) — 608,333 7.75% senior notes due February 2021 779,474 779,474 6.50% senior notes due September 2021 381,423 381,423 6.375% Berry senior notes due September 2022 — 572,700 Net unamortized discounts and premiums (4) — (8,694 ) Net unamortized deferred financing fees (4) (1,257 ) (37,374 ) Total debt, net 5,960,858 9,007,369 Less current portion, net (5) (1,937,729 ) (2,841,518 ) Less liabilities subject to compromise (6) (4,023,129 ) — Less debt and unamortized premiums of discontinued operations — (1,718,543 ) Long-term debt, net $ — $ 4,447,308 (1) Variable interest rates of 5.50% and 2.66% at December 31, 2016 , and December 31, 2015 , respectively. (2) Variable interest rates of 5.50% and 3.17% at December 31, 2016 , and December 31, 2015 , respectively. (3) The issuance of the Second Lien Notes was accounted for as a troubled debt restructuring which requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. During the year ended December 31, 2016, $551 million was written off to reorganization items in connection with the filing of the Bankruptcy Petitions. The remaining amount of approximately $57 million was classified as liabilities subject to compromise at December 31, 2016 . (4) Approximately $52 million in net discounts, premiums and deferred financing fees were written off to reorganization items in connection with the filing of the Bankruptcy Petitions. (5) Due to existing and anticipated covenant violations, the Company’s Credit Facilities and term loan were classified as current at December 31, 2016 , and December 31, 2015 . The current portion as of December 31, 2015 , also includes approximately $128 million of interest payable on the Second Lien Notes that was due within one year. (6) The Company’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016 .
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	December 31, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (in thousands) Senior secured second lien notes $ 1,000,000 $ 863,750 $ 1,000,000 $ 501,250 Senior notes, net 3,023,129 1,179,224 2,967,308 461,930
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: Par Value of Senior Notes Exchanged (in thousands) 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

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 : 2017 2018 2019 Natural gas positions: Fixed price swaps (NYMEX Henry Hub): Hedged volume (MMMBtu) 135,050 40,150 3,650 Average price ($/MMBtu) $ 3.17 $ 3.02 $ 3.08 Oil positions: Fixed price swaps (NYMEX WTI): Hedged volume (MBbls) 4,380 — — Average price ($/Bbl) $ 52.13 $ — $ — Collars (NYMEX WTI): Hedged volume (MBbls) — 1,825 1,825 Average floor price ($/Bbl) $ — $ 50.00 $ 50.00 Average ceiling price ($/Bbl) $ — $ 55.50 $ 55.50
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, 2016 2015 (in thousands) Assets: Commodity derivatives $ 19,369 $ 1,798,568 Liabilities: Commodity derivatives $ 113,226 $ 26,012

Fair Value Measurements on a 35

Fair Value Measurements on a Recurring Basis (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 19,369 $ (19,369 ) $ — Liabilities: Commodity derivatives $ 113,226 $ (19,369 ) $ 93,857 December 31, 2015 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 1,798,568 $ (25,155 ) $ 1,773,413 Liabilities: Commodity derivatives $ 26,012 $ (25,155 ) $ 857 (1) Represents counterparty netting under agreements governing such derivatives.

Other Property and Equipment (T

Other Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Other Property and Equipment	Other property and equipment consists of the following: December 31, 2016 2015 (in thousands) Natural gas plant and pipeline $ 421,806 $ 480,161 Furniture and office equipment 105,353 106,462 Buildings and leasehold improvements 66,014 72,976 Vehicles 31,496 37,641 Drilling and other equipment 8,082 7,934 Land 3,736 3,537 636,487 708,711 Less accumulated depreciation (224,547 ) (195,661 ) Less other property and equipment, net – discontinued operations — (98,973 ) $ 411,940 $ 414,077

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations Reconciliation	The following table presents a reconciliation of the Company’s asset retirement obligations: December 31, 2016 2015 (in thousands) Asset retirement obligations at beginning of year $ 523,541 $ 497,570 Liabilities added from drilling 546 3,574 Liabilities added from acquisitions 1,416 — Liabilities associated with assets divested — (3,306 ) Deconsolidation of Berry Petroleum Company, LLC asset retirement obligations (141,612 ) — Current year accretion expense 30,498 30,016 Settlements (12,823 ) (6,336 ) Revision of estimates 596 2,023 402,162 523,541 Less asset retirement obligations of discontinued operations — (137,563 ) Asset retirement obligations at end of year $ 402,162 $ 385,978

Operating Leases (Tables)

Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2016
Leases, Operating [Abstract]
Future Minimum Lease Payments	As of December 31, 2016 , future minimum lease payments were as follows (in thousands): 2017 $ 3,627 2018 2,852 2019 2,008 2020 468 2021 4 Thereafter 60 $ 9,019

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation	The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net income (loss): Year Ended December 31, 2016 2015 2014 (in thousands, except per unit data) Loss from continuing operations $ (385,697 ) $ (3,744,634 ) $ (474,405 ) Allocated to participating securities — (3,039 ) (7,117 ) $ (385,697 ) $ (3,747,673 ) $ (481,522 ) Income (loss) from discontinued operations, net of income taxes $ (1,786,159 ) $ (1,015,177 ) $ 22,596 Net loss $ (2,171,856 ) $ (4,759,811 ) $ (451,809 ) Allocated to participating securities — (3,039 ) (7,117 ) $ (2,171,856 ) $ (4,762,850 ) $ (458,926 ) Basic loss per unit – continuing operations $ (1.10 ) $ (10.91 ) $ (1.47 ) Diluted loss per unit – continuing operations $ (1.10 ) $ (10.91 ) $ (1.47 ) Basic income (loss) per unit – discontinued operations $ (5.06 ) $ (2.96 ) $ 0.07 Diluted income (loss) per unit – discontinued operations $ (5.06 ) $ (2.96 ) $ 0.07 Basic net loss per unit $ (6.16 ) $ (13.87 ) $ (1.40 ) Diluted net loss per unit $ (6.16 ) $ (13.87 ) $ (1.40 ) Basic weighted average units outstanding 352,653 343,323 328,918 Dilutive effect of unit equivalents — — — Diluted weighted average units outstanding 352,653 343,323 328,918

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 (in thousands) Current taxes: Federal $ (494 ) $ (12,021 ) $ 473 State 321 1,022 21 Deferred taxes: Federal 11,582 8,237 (104 ) State (215 ) (3,631 ) 3,978 $ 11,194 $ (6,393 ) $ 4,368
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, 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % State, net of federal tax benefit 0.7 0.1 (0.9 ) Loss excluded from nontaxable entities (24.7 ) (34.7 ) (34.5 ) Other (14.0 ) (0.2 ) (0.5 ) Effective rate (3.0 )% 0.2 % (0.9 )%
Significant components of the deferred tax assets and liabilities	Significant components of the deferred tax assets and liabilities were as follows: December 31, 2016 2015 (in thousands) Deferred tax assets: Net operating loss carryforwards $ 1,730 $ 370 Reorganization items 14,932 — Unit-based compensation — 18,214 Valuation allowance (19,558 ) (2,159 ) Other 10,030 7,300 Total deferred tax assets 7,134 23,725 Deferred tax liabilities: Property and equipment principally due to differences in depreciation (7,021 ) (12,534 ) Other (279 ) 10 Total deferred tax liabilities (7,300 ) (12,524 ) Net deferred tax assets (liabilities) $ (166 ) $ 11,201

Supplemental Disclosures to t41

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2016
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Schedule of Other Current Assets [Table Text Block]	“Other current assets” reported on the balance sheets include the following: December 31, 2016 2015 (in thousands) Prepaid expenses $ 70,116 $ 29,237 Inventories 15,798 19,184 Deferred financing fees 16,809 25,090 Other 4,890 1,185 Other current assets $ 107,613 $ 74,696
Supplemental Cash Flow Disclosures	Supplemental disclosures to the consolidated statements of cash flows are presented below: Year Ended December 31, 2016 2015 2014 (in thousands) Cash payments for interest, net of amounts capitalized $ 143,305 $ 476,077 $ 446,860 Cash payments for income taxes $ 4,427 $ 643 $ — Cash payments for reorganization items, net $ 37,748 $ — $ — Noncash investing activities: In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follow: Fair value of assets acquired $ — $ — $ 2,733,814 Cash paid, net of cash acquired — — (2,398,763 ) Noncash gains on exchanges of properties — — (149,195 ) Receivables from sellers — — 10,369 Liabilities assumed $ — $ — $ 196,225 Accrued capital expenditures $ 31,128 $ 71,105 $ 180,447

Supplemental Oil and Natural 42

Supplemental Oil and Natural Gas Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 (in thousands) Property acquisition costs: (1) Proved $ — $ — $ 2,306,541 Unproved — — 793,742 Exploration costs 40,074 19,929 644 Development costs 86,053 298,028 925,750 Asset retirement costs 419 4,152 14,855 Total costs incurred – continuing operations $ 126,546 $ 322,109 $ 4,041,532 Total costs incurred – discontinued operations $ 11,147 $ 132,427 $ 1,040,152 (1) See Note 3 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, 2016 2015 (in thousands) Proved properties $ 12,234,099 $ 16,337,814 Unproved properties 998,860 1,783,341 13,232,959 18,121,155 Less accumulated depletion and amortization (9,999,560 ) (11,097,492 ) 3,233,399 7,023,663 Less oil and natural gas capitalized costs, net – discontinued operations — (3,414,896 ) $ 3,233,399 $ 3,608,767
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, 2016 2015 2014 (in thousands) Revenues and other: Oil, natural gas and natural gas liquids sales $ 952,132 $ 1,151,240 $ 2,312,137 Gains (losses) on oil and natural gas derivatives (164,330 ) 1,027,014 1,127,395 787,802 2,178,254 3,439,532 Production costs: Lease operating expenses 317,046 375,840 443,157 Transportation expenses 161,037 167,561 165,489 Severance taxes, ad valorem taxes and California carbon allowances 73,806 111,350 169,417 551,889 654,751 778,063 Other costs: Exploration costs 4,080 9,473 125,037 Depletion and amortization 356,825 504,493 726,567 Impairment of long-lived assets 165,044 4,960,144 2,050,387 (Gains) losses on sale of assets and other, net 417 (199,296 ) (501,036 ) Texas margin tax expense (benefit) (649 ) (2,721 ) 3,984 525,717 5,272,093 2,404,939 Results of operations – continuing operations $ (289,804 ) $ (3,748,590 ) $ 256,530 Results of operations – discontinued operations (1) $ (1,066,634 ) $ (858,833 ) $ 213,280 (1) The results of discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016. 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, 2016 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 2,231 103.4 97.3 3,435 1,053 4,488 Revisions of previous estimates (9 ) (4.3 ) 0.9 (29 ) (179 ) (208 ) Extensions, discoveries and other additions 265 10.1 15.2 417 11 428 Production (187 ) (10.0 ) (9.3 ) (303 ) (81 ) (384 ) Deconsolidation of Berry Petroleum Company, LLC proved reserves — — — — (804 ) (804 ) End of year 2,300 99.2 104.1 3,520 — 3,520 Proved developed reserves: Beginning of year 2,231 103.4 97.3 3,435 1,053 4,488 End of year 2,128 93.3 94.4 3,254 — 3,254 Proved undeveloped reserves: Beginning of year — — — — — — End of year 172 5.9 9.7 266 — 266 Year Ended December 31, 2015 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 3,568 197.4 146.3 5,631 1,673 7,304 Revisions of previous estimates (1,134 ) (81.9 ) (38.4 ) (1,855 ) (524 ) (2,379 ) Sales of minerals in place (13 ) (4.1 ) (2.0 ) (50 ) — (50 ) Extensions, discoveries and other additions 10 3.8 0.8 37 10 47 Production (200 ) (11.8 ) (9.4 ) (328 ) (106 ) (434 ) End of year 2,231 103.4 97.3 3,435 1,053 4,488 Proved developed reserves: Beginning of year 2,997 141.7 117.5 4,552 1,266 5,818 End of year 2,231 103.4 97.3 3,435 1,053 4,488 Proved undeveloped reserves: Beginning of year 571 55.7 28.8 1,079 407 1,486 End of year — — — — — — Year Ended December 31, 2014 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) Proved developed and undeveloped reserves: Beginning of year 2,730 194.7 183.5 4,999 1,404 6,403 Revisions of previous estimates 54 (13.0 ) (45.3 ) (297 ) (21 ) (318 ) Purchases of minerals in place 1,354 45.0 54.4 1,951 544 2,495 Sales of minerals in place (426 ) (22.8 ) (37.2 ) (786 ) (298 ) (1,084 ) Extensions, discoveries and other additions 36 6.7 2.5 92 158 250 Production (180 ) (13.2 ) (11.6 ) (328 ) (114 ) (442 ) End of year 3,568 197.4 146.3 5,631 1,673 7,304 Proved developed reserves: Beginning of year 1,824 138.7 125.2 3,407 933 4,340 End of year 2,997 141.7 117.5 4,552 1,266 5,818 Proved undeveloped reserves: Beginning of year 906 56.0 58.3 1,592 471 2,063 End of year 571 55.7 28.8 1,079 407 1,486 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 Predecessor was 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, 2016 2015 2014 (in thousands) Future estimated revenues $ 10,876,241 $ 11,810,044 $ 38,350,590 Future estimated production costs (6,286,264 ) (7,276,564 ) (16,358,433 ) Future estimated development costs (971,055 ) (775,328 ) (2,899,781 ) Future net cash flows 3,618,922 3,758,152 19,092,376 10% annual discount for estimated timing of cash flows (1,690,224 ) (1,719,979 ) (10,910,462 ) Standardized measure of discounted future net cash flows – continuing operations $ 1,928,698 $ 2,038,173 $ 8,181,914 Standardized measure of discounted future net cash flows – discontinued operations $ — $ 995,372 $ 4,330,377 Representative NYMEX prices: (1) Natural gas (MMBtu) $ 2.48 $ 2.59 $ 4.35 Oil (Bbl) $ 42.64 $ 50.16 $ 95.27 (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, 2016 2015 2014 (in thousands) Sales and transfers of oil, natural gas and NGL produced during the period $ (400,243 ) $ (496,489 ) $ (1,534,074 ) Changes in estimated future development costs 18,843 1,069,971 88,324 Net change in sales and transfer prices and production costs related to future production (162,460 ) (6,105,531 ) 421,484 Purchases of minerals in place — — 2,473,512 Sales of minerals in place — (97,785 ) (1,194,601 ) Extensions, discoveries and improved recovery 221,765 69,745 236,395 Previously estimated development costs incurred during the period — 91,719 550,514 Net change due to revisions in quantity estimates (9,291 ) (1,089,624 ) (606,104 ) Accretion of discount 203,817 818,191 726,400 Changes in production rates and other 18,094 (403,938 ) (243,933 ) Change – continuing operations $ (109,475 ) $ (6,143,741 ) $ 917,917 Change – discontinued operations $ (995,372 ) $ (3,335,005 ) $ (304,955 )

Supplemental Quarterly Data (43

Supplemental Quarterly Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
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) 2016: Oil, natural gas and natural gas liquids sales $ 199,849 $ 216,426 $ 257,902 $ 277,955 Gains (losses) on oil and natural gas derivatives 109,453 (183,794 ) 166 (90,155 ) Total revenues and other 346,699 64,851 286,913 219,250 Total expenses (1) 472,912 296,824 331,929 292,194 Losses on sale of assets and other, net 1,269 2,517 2,310 9,462 Reorganization items, net — 485,798 (28,361 ) (145,838 ) Income (loss) from continuing operations (222,927 ) 201,652 (99,927 ) (264,495 ) Income (loss) from discontinued operations, net of income taxes (1,124,819 ) 6,840 (98,438 ) (569,742 ) Net income (loss) (1,347,746 ) 208,492 (198,365 ) (834,237 ) Income (loss) per unit – continuing operations: Basic $ (0.64 ) $ 0.57 $ (0.28 ) $ (0.75 ) Diluted $ (0.64 ) $ 0.57 $ (0.28 ) $ (0.75 ) Income (loss) per unit – discontinued operations: Basic $ (3.19 ) $ 0.02 $ (0.28 ) $ (1.61 ) Diluted $ (3.19 ) $ 0.02 $ (0.28 ) $ (1.61 ) Net income (loss) per unit: Basic $ (3.83 ) $ 0.59 $ (0.56 ) $ (2.36 ) Diluted $ (3.83 ) $ 0.59 $ (0.56 ) $ (2.36 ) (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. 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 $ 293,983 $ 323,038 $ 286,993 $ 247,226 Gains (losses) on oil and natural gas derivatives 421,514 (186,714 ) 521,365 270,849 Total revenues and other 766,984 177,068 839,441 536,520 Total expenses (1) 681,222 420,494 2,113,892 3,284,372 Gains on sale of assets and other, net (7,814 ) (17,185 ) (169,613 ) (878 ) Loss from continuing operations (16,435 ) (350,295 ) (1,032,159 ) (2,345,745 ) Loss from discontinued operations, net of income taxes (322,725 ) (28,832 ) (537,158 ) (126,462 ) Net loss (339,160 ) (379,127 ) (1,569,317 ) (2,472,207 ) Loss per unit – continuing operations: Basic $ (0.05 ) $ (1.04 ) $ (2.94 ) $ (6.69 ) Diluted $ (0.05 ) $ (1.04 ) $ (2.94 ) $ (6.69 ) Loss per unit – discontinued operations: Basic $ (0.98 ) $ (0.08 ) $ (1.53 ) $ (0.36 ) Diluted $ (0.98 ) $ (0.08 ) $ (1.53 ) $ (0.36 ) Net loss per unit: Basic $ (1.03 ) $ (1.12 ) $ (4.47 ) $ (7.05 ) Diluted $ (1.03 ) $ (1.12 ) $ (4.47 ) $ (7.05 ) (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 Sig44

Basis of Presentation and Significant Accounting Policies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Deferred Tax Assets, Net, Current		$ 22,000
Deferred Tax Liabilities, Net, Noncurrent		11,000
Deferred Tax Assets, Net		11,201
Allowance for doubtful accounts	$ 8,000	1,000
Capitalized interest costs	0	3,000	$ 4,000
Impairment of Leasehold		2,000	125,000
Restricted cash	8,000	7,000
Gas Balancing Asset (Liability)	8,000	13,000
Natural gas production imbalance payables	6,000	11,000
Deferred financing fees	16,809	25,090
Amortization of Financing Costs	$ 10,000	$ 20,000	$ 43,000
Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	39 years

Basis of Presentation and Sig45

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties	$ 1,400,000	$ 603,000	$ 165,044	$ 4,132,239	$ 2,050,387
Rockies region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			23,142	1,592,256	332,365
Hugoton Basin region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			0	1,667,768	0
TexLa region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			0	352,422	4,836
Mid-Continent region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			141,902	405,370	244,413
Permian Basin region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			0	71,990	1,337,444
South Texas region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			$ 0	$ 42,433	$ 131,329

Basis of Presentation and Sig46

Basis of Presentation and Significant Accounting Policies Unproved Property Impairment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment Of Unproved Oil And Gas Properties	$ 0	$ 827,905	$ 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

Basis of Presentation and Sig47

Basis of Presentation and Significant Accounting Policies Deferred Financing Fees (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
deferred financing costs [Line Items]
Deferred financing fees		$ 16,809	$ 25,090
Amortization of Financing Costs		10,000	20,000	$ 43,000
Other Current Assets [Member]
deferred financing costs [Line Items]
Deferred financing fees		17,000	25,000
Current portion of long-term debt [Member]
deferred financing costs [Line Items]
Deferred financing fees		1,000	2,000
Long-term debt, net [Member]
deferred financing costs [Line Items]
Deferred financing fees			35,000
Senior Notes [Member]
deferred financing costs [Line Items]
Deferred Finance Costs, Net	[1]	1,257	37,374
Reorganization items [Member]
deferred financing costs [Line Items]
Write off of Deferred Debt Issuance Cost		33,000
Other, net [Member]
deferred financing costs [Line Items]
Write off of Deferred Debt Issuance Cost		$ 1,000	$ 7,000	$ 8,000
[1]	Approximately $52 million in net discounts, premiums and deferred financing fees were written off to reorganization items in connection with the filing of the Bankruptcy Petitions.

Chapter 11 Proceedings and Co48

Chapter 11 Proceedings and Covenant Violations (Details) - USD ($) $ in Thousands	1 Months Ended		8 Months Ended	12 Months Ended
	May 31, 2016	Apr. 30, 2016	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 04, 2016	Mar. 15, 2016
Debt Instrument [Line Items]
Holders required for agreement			67.00%	67.00%
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations			$ 219,000
Increase (Decrease) in Restricted Cash		$ (45,000)
Repayments of debt				$ 913,209	$ 1,828,461	$ 4,605,000
Required issuance of additional debt							$ 1,000,000
Senior Notes [Member]
Debt Instrument [Line Items]
Deferred interest payment								$ 60,000
Interest Paid		60,000
Repayments of debt				$ 553,000
Linn Energy, LLC | Line of Credit
Debt Instrument [Line Items]
Repayments of debt	$ 350,000	$ 100,000
8.625% senior notes due April 2020 | Berry | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.75%	6.75%
6.50% senior notes due May 2019 | Linn Energy, LLC | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.50%	6.50%
Senior Notes Due February 2021 [Member] | Linn Energy, LLC | Senior Notes [Member]
Debt Instrument [Line Items]
Deferred interest payment								30,000
Debt Instrument, Interest Rate, Stated Percentage			7.75%	7.75%
6.50% senior notes due September 2021 | Linn Energy, LLC | Senior Notes [Member]
Debt Instrument [Line Items]
Deferred interest payment								12,000
Debt Instrument, Interest Rate, Stated Percentage			6.50%	6.50%
Senior Notes Due 2022 | Berry | Senior Notes [Member]
Debt Instrument [Line Items]
Deferred interest payment								$ 18,000
Debt Instrument, Interest Rate, Stated Percentage			6.375%	6.375%
6.25% senior notes due November 2019 | Linn Energy, LLC | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.25%	6.25%
Senior Notes Due April 2020 [Member] | Linn Energy, LLC | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			8.625%	8.625%

Chapter 11 Proceedings and Co49

Chapter 11 Proceedings and Covenant Violations Reorganization disclosures (Details) - USD ($) $ in Thousands		3 Months Ended				12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Liabilities Subject to Compromise
Accounts payable and accrued expenses		$ 137,692				$ 137,692
Accrued interest payable		144,184				144,184
Debt	[1]	4,023,129				4,023,129	$ 0
Liabilities Subject to Compromise		4,305,005				4,305,005	0
Reorganization Items
Legal and other professional advisory fees						56,656
Unamortized deferred financing fees, discounts and premiums						52,045
Gain related to interest payable on the 12.00% senior secured second lien notes due December 2020 (1)	[2]					551,000
Terminated contracts						(66,052)
Other						64,648
Reorganization items, net		$ 145,838	$ 28,361	$ (485,798)	$ 0	$ (311,599)	$ 0	$ 0
[1]	The Company’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016.
[2]	Represents a noncash gain on the write-off of postpetition contractual interest through maturity, recorded to reflect the carrying value of the liability subject to compromise at its estimated allowed claim amount.

Chapter 11 Proceedings and Co50

Chapter 11 Proceedings and Covenant Violations Reorganization plan disclosure (Details) - USD ($)	Feb. 28, 2017	May 31, 2016	Apr. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Stock Issued During Period, Value, New Issues					$ 224,665,000
Repayments of debt				$ 913,209,000	$ 1,828,461,000	$ 4,605,000,000
Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of debt				$ 553,000,000
Linn Energy, LLC | Line of Credit
Debt Instrument [Line Items]
Repayments of debt		$ 350,000,000	$ 100,000,000
Senior Secured Second Lien Notes Due 2020 [Member] | Linn Energy, LLC | Senior Secured Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				12.00%
6.50% senior notes due May 2019 | Linn Energy, LLC | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				6.50%
6.25% senior notes due November 2019 | Linn Energy, LLC | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				6.25%
Senior Notes Due April 2020 [Member] | Linn Energy, LLC | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				8.625%
Senior Notes Due February 2021 [Member] | Linn Energy, LLC | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				7.75%
6.50% senior notes due September 2021 | Linn Energy, LLC | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				6.50%
Subsequent Event [Member]
Debt Instrument [Line Items]
Equity exchanged	100.00%
Stock Issued During Period, Value, New Issues	$ 530,000,000
Percent of equity sold	50.00%
Subsequent Event [Member] | Linn Energy, LLC
Debt Instrument [Line Items]
Cash pool for unsecured claims	$ 40,000,000
bankruptcy claim amount	$ 2,500
Issuance of units (in units)	91,708,500
Percent of equity owners	10.00%
Subsequent Event [Member] | Berry
Debt Instrument [Line Items]
Accounts Payable, Related Parties	$ 25,000,000
Subsequent Event [Member] | Berry | Senior Notes [Member]
Debt Instrument [Line Items]
Cash pool for unsecured claims	35,000,000
Subsequent Event [Member] | Revolving Line of Credit [Member] | Linn Energy, LLC | Line of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,700,000,000
Line of Credit Facility, Current Borrowing Capacity	1,400,000,000
Subsequent Event [Member] | Revolving Line of Credit [Member] | Berry | Line of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	550,000,000
Subsequent Event [Member] | Term loan [Member] | Linn Energy, LLC | Line of Credit
Debt Instrument [Line Items]
Loans Payable	$ 300,000,000
Subsequent Event [Member] | Senior Secured Second Lien Notes Due 2020 [Member] | Linn Energy, LLC | Senior Secured Notes [Member]
Debt Instrument [Line Items]
Issuance of units (in units)	17,678,889
Repayments of debt	$ 30,000,000
Subsequent Event [Member] | 6.25% senior notes due November 2019 | Linn Energy, LLC | Senior Notes [Member]
Debt Instrument [Line Items]
Issuance of units (in units)	26,724,396
claims under $2,500 [Member] | Subsequent Event [Member] | Linn Energy, LLC
Debt Instrument [Line Items]
Cash pool for unsecured claims	$ 2,300,000
claims over $2,500 [Member] | Subsequent Event [Member] | Linn Energy, LLC
Debt Instrument [Line Items]
Cash pool for unsecured claims	$ 37,700,000

Discontinued Operations, Dive51

Discontinued Operations, Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding Discontinued Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016		Dec. 31, 2015	Dec. 31, 2014
Discontinued Operations, Statements of Operations
Revenues and other	$ 387,706	[1]	$ 641,654	$ 1,431,289
Expenses	1,524,296	[1]	1,579,029	1,319,633
Other income and (expenses)	(57,030)	[1]	(77,870)	(88,991)
Reorganization items, net	(46,127)	[1]	0	0
Income (loss) from discontinued operations before income taxes	(1,239,747)	[1]	(1,015,245)	22,665
Income tax expense (benefit)	196	[1]	(68)	69
Income (loss) from discontinued operations, net of income taxes	(1,239,943)	[1]	(1,015,177)	22,596
Current assets:
Cash and cash equivalents	0		1,023	$ 1,586
Accounts receivable – trade, net			46,053
Other			34,115
Current assets of discontinued operations	0		81,191
Noncurrent assets:
Oil and natural gas properties (successful efforts method), net	0		3,414,896
Restricted cash			250,359
Other			115,030
Noncurrent assets of discontinued operations	0		3,780,285
Current liabilities:
Accounts payable and accrued expenses			125,748
Current portion of long-term debt			873,175
Other			18,976
Current liabilities of discontinued operations	0		1,017,899
Noncurrent liabilities:
Long-term debt, net			845,368
Other			212,050
Noncurrent liabilities of discontinued operations	$ 0		$ 1,057,418
[1]	(1) Results of discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016.

Discontinued Operations, Dive52

Discontinued Operations, 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Oil and Gas Property		$ 0	$ 0	$ 149,195
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				50,000
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				99,000
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
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

Discontinued Operations, Dive53

Discontinued Operations, Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding (Acquisitions, Joint-Venture Funding) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2016
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
Future Funding Of Joint Venture Agreement		$ 400
Senior Notes [Member] | 6.50% senior notes due May 2019 | Linn Energy, LLC
Business Acquisition [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.50%
Senior Notes [Member] | 6.50% senior notes due September 2021 | Linn Energy, LLC
Business Acquisition [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.50%

Unitholders' Capital (Deficit)

Unitholders' Capital (Deficit) (Details) - USD ($)	1 Months Ended		12 Months Ended
	Aug. 31, 2015	May 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Offerings [Line Items]
Canceled (in units)			2,230,182
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
At-the-Market Offering Program [Member]
Schedule of Equity Offerings [Line Items]
Equity Offering Program Maximum Value			$ 500,000,000
Sale of units (in units)			0	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
Public Offering of Units [Member]
Schedule of Equity Offerings [Line Items]
Sale of units (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

Unit-Based Compensation and O55

Unit-Based Compensation and Other Benefit Plans (Details) - USD ($)	1 Months Ended		12 Months Ended			24 Months Ended
	Dec. 31, 2016	Jan. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units authorized for issuance (in units)	0		0			0
Share-based Compensation [Abstract]
Allocated Share Based Compensation	$ 14,000,000		$ 44,218,000	$ 56,136,000	$ 53,284,000
Income tax benefit			$ 16,339,000	20,742,000	19,688,000
Restricted/Unrestricted Nonvested Units [Roll Forward]
Canceled (in units)			2,230,182
Weighted Average Exercise Price Per Unit
Forfeited or expired (in dollars per unit)			$ 25.80
Share based compensation arrangement by share based payment award, options, cancellations in period, weighted average exercise price			$ 21.83
Aggregate Intrinsic Value
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options	$ 0		$ 0	0		$ 0
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			$ 9,000,000	11,000,000	10,000,000
General and Administrative Expense [Member]
Share-based Compensation [Abstract]
Allocated Share Based Compensation			34,268,000	47,312,000	45,195,000
Lease Operating Expense [Member]
Share-based Compensation [Abstract]
Allocated Share Based Compensation			$ 9,950,000	$ 8,824,000	$ 8,089,000
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
Number of Units Underlying Options
Outstanding, beginning (in units)	0		0	824,711		0
Forfeited or expired (in units)			184,498
Canceled (in units)			(640,213)
Outstanding, ending (in units)	0		0	824,711		0
Exercisable (in units)	0		0			0
Weighted Average Exercise Price Per Unit
Outstanding, beginning (in dollars per unit)	$ 0		$ 0	$ 22.72		$ 0
Outstanding, ending (in dollars per unit)	0		0	$ 22.72		0
Exercisable (in dollars per unit)	$ 0		$ 0			$ 0
Weighted Average Remaining Contractual Life in Years
Outstanding, beginning (in years)			0 years	2 years 3 months 7 days
Outstanding, ending (in years)			0 years	2 years 3 months 7 days
Exercisable (in years)			0 years
Aggregate Intrinsic Value
Intrinsic value of outstanding unit options	$ 0		$ 0	$ 0		$ 0
Intrinsic value of exercisable unit options	$ 0		$ 0			$ 0
Intrinsic value of options exercised			0	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value					$ 11,000,000
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant (in units)	21,000,000		21,000,000			21,000,000
Units reserved for future issuance (in units)	21,000,000		21,000,000			21,000,000
Restricted/Unrestricted Nonvested Units [Roll Forward]
Nonvested units, beginning (in units)	0		0	4,926,572		0
Granted (in units)			0
Vested (in units)			(2,069,004)
Forfeited (in units)			(349,243)
Canceled (in units)			2,508,325
Nonvested units, ending (in units)	0		0	4,926,572		0
Outstanding, beginning (in dollars per unit)	$ 0		$ 0	$ 16.22		$ 0
Granted (in dollars per unit)				10.21	$ 33.10
Vested (in dollars per unit)			19.66
Forfeited (in dollars per unit)			14.29
Canceled (in dollars per unit)			13.95
Outstanding, ending (in dollars per unit)	$ 0		$ 0	$ 16.22		$ 0
Restricted/Unrestricted Units [Abstract]
Fair value of units vested			$ 41,000,000	$ 49,000,000	$ 42,000,000
Unrecognized compensation cost	$ 0		$ 0			$ 0
Granted (in units)			0
Aggregate Intrinsic Value
Unrecognized compensation cost	0		$ 0			0
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		$ 0			$ 0
Restricted/Unrestricted Nonvested Units [Roll Forward]
Granted (in units)		567,320
Restricted/Unrestricted Units [Abstract]
Granted (in units)		567,320

Debt (Details)

Debt (Details)		1 Months Ended		12 Months Ended
		May 31, 2016USD ($)	Apr. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Debt Instrument [Line Items]
Repayments of debt				$ 913,209,000	$ 1,828,461,000	$ 4,605,000,000
Gain (Losses) on Extinguishment of Debt excluding TDR				356,000,000
Extinguishment of Debt, Amount				927,000,000
Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of debt				553,000,000
Linn Energy, LLC | Loans Payable
Debt Instrument [Line Items]
Loans Payable				$ 284,000,000
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]
Credit facilities	[1]			$ 1,654,745,000	2,215,000,000
Repayments of debt		$ 350,000,000	$ 100,000,000
Linn Energy, LLC | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity				0
Minimum liquidity				$ 500,000,000
Minimum liquidity as a percentage of borrowing base				15.00%
Line Of Credit Facility Portion Of Properties Required To Maintain Mortgages				90.00%
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]
Debt Instrument, Interest Rate, Stated Percentage				12.00%
Linn Energy, LLC | Senior Notes [Member] | 6.50% 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] | 6.25% 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] | 6.50% 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
Debt Instrument [Line Items]
Credit facilities	[2]			$ 0	$ 873,175,000
Berry | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line Of Credit Facility Portion Of Properties Required To Maintain Mortgages				90.00%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage				0.50%
Berry | Senior Notes [Member] | Senior Notes Due 2022
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				6.375%
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%
[1]	Variable interest rates of 5.50% and 2.66% at December 31, 2016, and December 31, 2015, respectively.
[2]	Variable interest rates of 5.50% and 3.17% at December 31, 2016, and December 31, 2015, respectively.

Debt Schedule of Long-Term Debt

Debt Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Senior notes, net		$ 3,023,129	$ 2,967,308
Senior secured second lien notes		1,000,000	1,000,000
Total debt, net		5,960,858	9,007,369
Less current portion	[1]	(1,937,729)	(2,841,518)
Liabilities Subject to Compromise, Debt and Accrued Interest	[2]	(4,023,129)	0
Less debt and unamortized premiums of discontinued operations		0	(1,718,543)
Total long-term debt, net		0	4,447,308
Gain related to interest payable on the 12.00% senior secured second lien notes due December 2020 (1)	[3]	551,000
Accrued interest payable		144,184
Unamortized deferred financing fees, discounts and premiums		52,045
Senior Notes [Member]
Debt Instrument [Line Items]
Net unamortized discounts and premiums	[4]	0	(8,694)
Net unamortized deferred financing fees	[4]	(1,257)	(37,374)
Linn Energy, LLC | Line of Credit
Debt Instrument [Line Items]
Credit facilities	[5]	$ 1,654,745	$ 2,215,000
Linn Energy, LLC | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End		5.50%	2.66%
Linn Energy, LLC | Loans Payable
Debt Instrument [Line Items]
Term loan		$ 284,241	$ 500,000
Linn Energy, LLC | Senior Notes [Member] | 6.50% senior notes due May 2019
Debt Instrument [Line Items]
Senior notes, net		562,234	562,234
Linn Energy, LLC | Senior Notes [Member] | 6.25% senior notes due November 2019
Debt Instrument [Line Items]
Senior notes, net		581,402	581,402
Linn Energy, LLC | Senior Notes [Member] | 8.625% senior notes due April 2020
Debt Instrument [Line Items]
Senior notes, net		718,596	718,596
Linn Energy, LLC | Senior Notes [Member] | 7.75% senior notes due February 2021
Debt Instrument [Line Items]
Senior notes, net		779,474	779,474
Linn Energy, LLC | Senior Notes [Member] | 6.50% senior notes due September 2021
Debt Instrument [Line Items]
Senior notes, net		381,423	381,423
Linn Energy, LLC | Senior Secured Notes [Member] | Senior Secured Second Lien Notes Due 2020 [Member]
Debt Instrument [Line Items]
Senior secured second lien notes	[6]	1,000,000	1,000,000
Accrued interest payable		57,000
Linn Energy, LLC | Secured Debt [Member] | Senior Secured Second Lien Notes Due 2020 [Member]
Debt Instrument [Line Items]
Interest payable on second lien notes	[6]	0	608,333
Interest Payments on Troubled Debt, Current		128,000
Berry | Line of Credit
Debt Instrument [Line Items]
Credit facilities	[7]	$ 0	$ 873,175
Berry | Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End		5.50%	3.17%
Berry | Senior Notes [Member] | 8.625% senior notes due April 2020
Debt Instrument [Line Items]
Senior notes, net		$ 0	$ 261,100
Berry | Senior Notes [Member] | Senior Notes Due 2022
Debt Instrument [Line Items]
Senior notes, net		$ 0	$ 572,700
[1]	Due to existing and anticipated covenant violations, the Company’s Credit Facilities and term loan were classified as current at December 31, 2016, and December 31, 2015. The current portion as of December 31, 2015, also includes approximately $128 million of interest payable on the Second Lien Notes that was due within one year.
[2]	The Company’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016.
[3]	Represents a noncash gain on the write-off of postpetition contractual interest through maturity, recorded to reflect the carrying value of the liability subject to compromise at its estimated allowed claim amount.
[4]	Approximately $52 million in net discounts, premiums and deferred financing fees were written off to reorganization items in connection with the filing of the Bankruptcy Petitions.
[5]	Variable interest rates of 5.50% and 2.66% at December 31, 2016, and December 31, 2015, respectively.
[6]	The issuance of the Second Lien Notes was accounted for as a troubled debt restructuring which requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. During the year ended December 31, 2016, $551 million was written off to reorganization items in connection with the filing of the Bankruptcy Petitions. The remaining amount of approximately $57 million was classified as liabilities subject to compromise at December 31, 2016
[7]	Variable interest rates of 5.50% and 3.17% at December 31, 2016, and December 31, 2015, respectively.

Debt Debt Fair Value Disclosure

Debt Debt Fair Value Disclosure (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Carrying Value
Senior secured second lien notes	$ 1,000,000	$ 1,000,000
Senior notes, net	3,023,129	2,967,308
Fair Value
Senior secured second lien notes	863,750	501,250
Senior notes, net	$ 1,179,224	$ 461,930

Debt Debt Exchange (Details)

Debt Debt Exchange (Details) - USD ($)	1 Months Ended	12 Months Ended
	Nov. 30, 2015	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	$ 2,000,000,000
Gains (Losses) on Restructuring of Debt		$ 352,000,000
Troubled Debt Restructuring, Debtor, Current Period, Gain (Loss) on Restructuring, Per Share, Net		$ 1.03
Linn Energy, LLC | Senior Secured Notes [Member] | Senior Secured Second Lien Notes Due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 1,000,000,000	$ 1,000,000,000
Linn Energy, LLC | Senior Notes [Member] | 6.50% senior notes due May 2019
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	584,422,000
Linn Energy, LLC | Senior Notes [Member] | 6.25% senior notes due November 2019
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	824,348,000
Linn Energy, LLC | Senior Notes [Member] | 8.625% senior notes due April 2020
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	286,344,000
Linn Energy, LLC | Senior Notes [Member] | 7.75% senior notes due February 2021
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	184,300,000
Linn Energy, LLC | Senior Notes [Member] | 6.50% senior notes due September 2021
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	$ 120,586,000

Derivatives (Commodity Derivati

Derivatives (Commodity Derivatives) (Details)	Dec. 31, 2016MBblsMMMBTU$ / MMBTU$ / bbl
2017 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	135,050
Average Fixed Price (in usd per energy unit) | $ / MMBTU	3.17
2017 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	4,380
Average Fixed Price (in usd per energy unit)	52.13
2017 | Oil Derivative Instruments | Curde Oil Sales - Collars [Member]
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	0
Derivative, Floor Price	0
Derivative, Cap Price	0
2018 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	40,150
Average Fixed Price (in usd per energy unit) | $ / MMBTU	3.02
2018 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	0
Average Fixed Price (in usd per energy unit)	0
2018 | Oil Derivative Instruments | Curde Oil Sales - Collars [Member]
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	1,825
Derivative, Floor Price	50
Derivative, Cap Price	55.50
2019 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	3,650
Average Fixed Price (in usd per energy unit) | $ / MMBTU	3.08
2019 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	0
Average Fixed Price (in usd per energy unit)	0
2019 | Oil Derivative Instruments | Curde Oil Sales - Collars [Member]
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	1,825
Derivative, Floor Price	50
Derivative, Cap Price	55.50

Derivatives (Balance Sheet Pres

Derivatives (Balance Sheet Presentation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Assets:
Commodity derivatives	$ 19,369	$ 1,798,568
Liabilities:
Commodity derivatives	113,226	$ 26,012
Maximum Loss Upon All Counterparties Failing To Perform	$ 19,000

Derivatives Gains (Losses) on D

Derivatives Gains (Losses) on Derivatives (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended									12 Months Ended
	May 31, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Settlements on Canceled Derivatives	$ 1,200,000
Total (gains) losses		$ 90,155	$ (166)	$ 183,794	$ (109,453)	$ (270,849)	$ (521,365)	$ 186,714	$ (421,514)		$ 164,330	$ (1,027,014)	$ (1,127,395)
Cash Settlements On Derivatives including canceled derivatives										$ 89,000	861,000	$ 1,100,000
Noncash Settlements on Derivatives	$ 841,000										$ 841,000

Fair Value Measurements on a 63

Fair Value Measurements on a Recurring Basis (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Assets:
Commodity derivatives		$ 19,369	$ 1,798,568
Commodity derivatives	[1]	(19,369)	(25,155)
Commodity derivatives		0	1,773,413
Liabilities:
Commodity derivatives		113,226	26,012
Commodity derivatives	[1]	(19,369)	(25,155)
Commodity derivatives		$ 93,857	$ 857
[1]	Represents counterparty netting under agreements governing such derivatives.

Other Property and Equipment (D

Other Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 636,487	$ 597,216
Property, Plant and Equipment, Other, Gross, inclusive of discontinued operations	636,487	708,711
Less accumulated depreciation	(224,547)	(195,661)
Less other property and equipment, net – discontinued operations	0	(98,973)
Other property and equipment, net	411,940	414,077
Natural gas plant and pipeline
Property, Plant and Equipment [Line Items]
Other property and equipment	421,806	480,161
Furniture and office equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	105,353	106,462
Buildings and leasehold improvements
Property, Plant and Equipment [Line Items]
Other property and equipment	66,014	72,976
Vehicles
Property, Plant and Equipment [Line Items]
Other property and equipment	31,496	37,641
Drilling and other equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	8,082	7,934
Land
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 3,736	$ 3,537

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset retirement obligations rollforward
Asset retirement obligations at beginning of year	$ 523,541	$ 497,570
Liabilities added from drilling	546	3,574
Liabilities added from acquisitions	1,416	0
Liabilities associated with assets divested	0	(3,306)
Deconsolidation of Berry Petroleum Company, LLC asset retirement obligations	(141,612)
Current year accretion expense	30,498	30,016
Settlements	(12,823)	(6,336)
Revision of estimates	596	2,023
Asset retirement obligations at end of year	402,162	523,541
Less asset retirement obligations of discontinued operations	0	(137,563)
Asset retirement obligations at beginning of year	$ 402,162	$ 385,978

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Loss Contingency, Estimate [Abstract]
Payments for Legal Settlements	$ 0

Operating Leases (Details)

Operating Leases (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015
Leases, Operating [Abstract]
Operating lease expense	$ 7,000	$ 9,000	$ 15,000
Future Minimum Lease Payments [Abstract]
2,017		3,627
2,018		2,852
2,019		2,008
2,020		468
2,021		4
Thereafter		60
Operating Leases, Future Minimum Payments Due, Total		$ 9,019

Earnings Per Unit (Details)

Earnings Per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Loss from continuing operations										$ (385,697)	$ (3,744,634)	$ (474,405)
Allocated to participating securities										0	(3,039)	(7,117)
Loss from continuing operations attributable to common unitholders										(385,697)	(3,747,673)	(481,522)
Income (loss) from discontinued operations, net of income taxes	$ (569,742)	$ (98,438)	$ 6,840	$ (1,124,819)	$ (126,462)	$ (537,158)	$ (28,832)	$ (322,725)		(1,786,159)	(1,015,177)	22,596
Net loss	$ (834,237)	$ (198,365)	$ 208,492	$ (1,347,746)	$ (2,472,207)	$ (1,569,317)	$ (379,127)	$ (339,160)		(2,171,856)	(4,759,811)	(451,809)
Allocated to participating securities										0	(3,039)	(7,117)
Net loss attributable to common unitholders										$ (2,171,856)	$ (4,762,850)	$ (458,926)
Basic loss per unit – continuing operations	$ (0.75)	$ (0.28)	$ 0.57	$ (0.64)	$ (6.69)	$ (2.94)	$ (1.04)	$ (0.05)		$ (1.10)	$ (10.91)	$ (1.47)
Diluted loss per unit – continuing operations	(0.75)	(0.28)	0.57	(0.64)	(6.69)	(2.94)	(1.04)	(0.05)		(1.10)	(10.91)	(1.47)
Basic income (loss) per unit – discontinued operations	(1.61)	(0.28)	0.02	(3.19)	(0.36)	(1.53)	(0.08)	(0.98)		(5.06)	(2.96)	0.07
Diluted income (loss) per unit – discontinued operations	(1.61)	(0.28)	0.02	(3.19)	(0.36)	(1.53)	(0.08)	(0.98)		(5.06)	(2.96)	0.07
Basic net loss per unit	(2.36)	(0.56)	0.59	(3.83)	(7.05)	(4.47)	(1.12)	(1.03)		(6.16)	(13.87)	(1.40)
Diluted net loss per unit	$ (2.36)	$ (0.56)	$ 0.59	$ (3.83)	$ (7.05)	$ (4.47)	$ (1.12)	$ (1.03)		$ (6.16)	$ (13.87)	$ (1.40)
Basic weighted average units outstanding										352,653	343,323	328,918
Dilutive effect of unit equivalents										0	0	0
Diluted weighted average units outstanding										352,653	343,323	328,918
Weighted average anti-dilutive unit equivalents excluded from computation of earnings per unit (in units)									6,000	1,000	4,000

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current taxes:
Federal	$ (494)	$ (12,021)	$ 473
State	321	1,022	21
Deferred taxes:
Federal	11,582	8,237	(104)
State	(215)	(3,631)	3,978
Income tax expense (benefit)	$ 11,194	$ (6,393)	$ 4,368
Effective income tax rate reconciliation [Abstract]
Federal statutory rate	35.00%	35.00%	35.00%
State, net of federal tax benefit	0.70%	0.10%	(0.90%)
Loss excluded from nontaxable entities	(24.70%)	(34.70%)	(34.50%)
Other	(14.00%)	(0.20%)	(0.50%)
Effective rate	(3.00%)	0.20%	(0.90%)
Deferred tax assets:
Net operating loss carryforwards	$ 1,730	$ 370
Reorganization items	14,932	0
Unit-based compensation	0	18,214
Valuation allowance	(19,558)	(2,159)
Other	10,030	7,300
Total deferred tax assets	7,134	23,725
Deferred tax liabilities:
Property and equipment principally due to differences in depreciation	(7,021)	(12,534)
Other	(279)	10
Total deferred tax liabilities	(7,300)	(12,524)
Total deferred tax liabilities	(166)
Net deferred tax assets (liabilities)		11,201
Operating Loss Carryforwards [Line Items]
Material Uncertain Tax Position	0	$ 0
Federal [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 5,000
Net operating loss carryforwards, expiration dates	Dec. 31, 2036

Supplemental Disclosures to t70

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Balance Sheets) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Other current assets
Prepaid expenses	$ 70,116	$ 29,237
Inventories	15,798	19,184
Deferred financing fees	16,809	25,090
Other	4,890	1,185
Other current assets	107,613	74,696
Restricted cash	8,000	7,000
Net Outstanding Checks	$ 6,000	$ 21,000

Supplemental Disclosures to t71

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Cash Flows) (Details) - USD ($)	2 Months Ended	12 Months Ended
	May 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Cash payments for interest, net of amounts capitalized		$ 143,305,000	$ 476,077,000	$ 446,860,000
Cash payments for income taxes		4,427,000	643,000	0
Cash payments for reorganization items, net		37,748,000	0	0
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	0	2,733,814,000
Cash paid, net of cash acquired		0	0	(2,398,763,000)
Noncash gains on exchanges of properties		0	0	(149,195,000)
Receivables from sellers		0	0	10,369,000
Liabilities assumed		0	0	196,225,000
Accrued capital expenditures		31,128,000	71,105,000	180,447,000
Noncash Settlements on Derivatives	$ 841,000,000	841,000,000
Joint-venture funding				$ 25,000,000
Senior Secured Notes [Member] | Linn Energy, LLC | Senior Secured Second Lien Notes Due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 1,000,000,000	$ 1,000,000,000

Significant Customers (Details)

Significant Customers (Details) - Trade Accounts Receivable [Member] - Credit Risk [Member]	12 Months Ended
	Dec. 31, 2015
Concentration Risk [Line Items]
Total Number Of Largest Customers Represented In Sales	1
Customer 1 [Member]
Concentration Risk [Line Items]
Concentration risk percentage (in hundredths)	12.00%

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014
Related Party Transaction [Line Items]
Notes Payable, Related Parties							$ 352,000
Payments for Advance to Affiliate	$ 129,000	$ 58,000			$ 223,000
General and administrative expenses			$ 237,841	$ 285,996		$ 274,006
Share-based compensation expense			44,218	56,136		53,284
Distributions to unitholders			0	323,878		962,048
Investment in discontinued operations			0	132,332		100,921
Senior notes, net			$ 3,023,129	$ 2,967,308
LinnCo
Related Party Transaction [Line Items]
Ownership percentage			71.00%	37.00%
General and administrative expenses			$ 6,100	$ 3,400		2,900
General and administrative expenses paid on behalf of related party			5,900
Distributions to unitholders				121,000		373,000
Related party transaction, amounts of transaction			2,400	2,000		1,900
Berry
Related Party Transaction [Line Items]
Related Party Transaction, Other Revenues from Transactions with Related Party			69,000	78,000		86,000
Investment in discontinued operations			0	471,000		220,000
Noncash investment in affiliate				250,000
Due from Related Parties, Current				9,000
Director
Related Party Transaction [Line Items]
Related party transaction, amounts of transaction			$ 5,000	8,000		21,000
LinnCo
Related Party Transaction [Line Items]
Units of LINN Energy Acquired			123,100,715
FY 2013 [Member] | LinnCo
Related Party Transaction [Line Items]
General and administrative expenses paid on behalf of related party						11,000
Accounts Payable [Member] | Berry
Related Party Transaction [Line Items]
Due to Related Parties, Current			$ 3,000
Liabilities subject to compromise [Member] | Berry
Related Party Transaction [Line Items]
Due to Related Parties, Current			25,000
Senior Notes Due 2014 [Member] | Senior Notes [Member] | Berry
Related Party Transaction [Line Items]
Senior notes, net								$ 205,000
Debt Instrument, Interest Rate, Stated Percentage								10.25%
Reportable Legal Entities [Member] | Non-Guarantor Subsidiaries [Member]
Related Party Transaction [Line Items]
Proceeds from Contributions from Affiliates			$ 0	$ 89,000		$ 119,000

Supplemental Oil and Natural 74

Supplemental Oil and Natural Gas Data (Unaudited) (Details) Mcfe in Millions, Mcf in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2016USD ($)McfeMcfMMBbls	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)McfeMcfMMBbls	Dec. 31, 2015USD ($)McfeMcfMMBbls	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)McfeMcfMMBbls	Dec. 31, 2016USD ($)Mcfe$ / MMBTU$ / bblMcfMMBbls	Dec. 31, 2015USD ($)Mcfe$ / MMBTU$ / bblMcfMMBbls	Dec. 31, 2014USD ($)Mcfe$ / MMBTU$ / bblMcfMMBbls
Property acquisition costs: (1)
Proved	[1]									$ 0	$ 0	$ 2,306,541,000
Unproved	[1]									0	0	793,742,000
Exploration costs										40,074,000	19,929,000	644,000
Development costs										86,053,000	298,028,000	925,750,000
Asset retirement costs										419,000	4,152,000	14,855,000
Total costs incurred – continuing operations										126,546,000	322,109,000	4,041,532,000
Total costs incurred – discontinued operations										11,147	132,427	1,040,152
Oil and Natural Gas Capitalized Costs
Proved properties		$ 12,234,099,000				$ 16,337,814,000				12,234,099,000	16,337,814,000
Unproved properties		998,860,000				1,783,341,000				998,860,000	1,783,341,000
Capitalized cost, oil and gas producing activities		13,232,959,000				18,121,155,000				13,232,959,000	18,121,155,000
Less accumulated depletion and amortization		(9,999,560,000)				(11,097,492,000)				(9,999,560,000)	(11,097,492,000)
Proved oil and gas properties, inclusive of discontinued operations		3,233,399,000				7,023,663,000				3,233,399,000	7,023,663,000
Less oil and natural gas capitalized costs, net – discontinued operations		0				(3,414,896,000)				0	(3,414,896,000)
Capitalized costs, oil and gas producing activities, net		3,233,399,000				3,608,767,000				3,233,399,000	3,608,767,000
Revenues and other:
Oil, natural gas and natural gas liquids sales										952,132,000	1,151,240,000	2,312,137,000
Gains (losses) on oil and natural gas derivatives		$ (90,155,000)	$ 166,000	$ (183,794,000)	$ 109,453,000	$ 270,849,000	$ 521,365,000	$ (186,714,000)	$ 421,514,000	(164,330,000)	1,027,014,000	1,127,395,000
Results of Operations, Revenue from Oil and Gas Producing Activities										787,802,000	2,178,254,000	3,439,532,000
Production costs:
Lease operating expenses										317,046,000	375,840,000	443,157,000
Transportation expenses										161,037,000	167,561,000	165,489,000
Severance taxes, ad valorem taxes and California carbon allowances										73,806,000	111,350,000	169,417,000
Results of Operations, Expense from Oil and Gas Producing Activities										551,889,000	654,751,000	778,063,000
Other costs:
Exploration costs										4,080,000	9,473,000	125,037,000
Depletion and amortization										356,825,000	504,493,000	726,567,000
Impairment of long-lived assets										165,044,000	4,960,144,000	2,050,387,000
(Gains) losses on sale of assets and other, net										417,000	(199,296,000)	(501,036,000)
Texas margin tax expense (benefit)										(649,000)	(2,721,000)	3,984,000
Total other costs										525,717,000	5,272,093,000	2,404,939,000
Results of operations – continuing operations										(289,804,000)	(3,748,590,000)	256,530,000
Results of operations – discontinued operations	[2]									$ (1,066,634,000)	$ (858,833,000)	$ 213,280,000
Proved developed and undeveloped reserves:
Beginning of year | Mcfe					3,435				5,631	3,435	5,631	4,999
Beginning of year | Mcfe					1,053				1,673	1,053	1,673	1,404
Revisions of previous estimates | Mcfe										(29)	(1,855)	(297)
Revisions of previous estimates | Mcfe											(524)	(21)
Revisions of previous estimates | Mcfe											(2,379)	(318)
Purchases of minerals in place | Mcfe												1,951
Purchases of minerals in place | Mcfe												544
Purchases of minerals in place | Mcfe												2,495
Sales of minerals in place | Mcfe											50	786
Sales of minerals in place | Mcfe											0	(298)
Sales of minerals in place | Mcfe											50	1,084
Extensions, discoveries and other additions | Mcfe										417	37	92
Extensions, discoveries and other additions | Mcfe											10	158
Extensions, discoveries and other additions | Mcfe											47	250
Production | Mcfe										(303)	(328)	(328)
Production | Mcfe											(106)	(114)
Production | Mcfe											434	442
End of year | Mcfe		3,520				3,435				3,520	3,435	5,631
End of year | Mcfe						1,053					1,053	1,673
End of year | Mcfe					4,488				7,304	4,488	7,304	6,403
Proved developed reserves:
Beginning of year | Mcfe					3,435				4,552	3,435	4,552	3,407
Beginning of year | Mcfe					1,053				1,266	1,053	1,266	933
Beginning of year | Mcfe					4,488				5,818	4,488	5,818	4,340
End of year | Mcfe		3,254				3,435				3,254	3,435	4,552
End of year | Mcfe						1,053					1,053	1,266
End of year | Mcfe						4,488					4,488	5,818
Proved undeveloped reserves:
Beginning of year | Mcfe					0				1,079	0	1,079	1,592
Beginning of year | Mcfe					0				407	0	407	471
Beginning of year | Mcfe					0				1,486	0	1,486	2,063
End of year | Mcfe		266				0				266	0	1,079
End of year | Mcfe						0					0	407
End of year | Mcfe						0					0	1,486
Conversion rate between oil and NGL volumes to natural gas										6
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | Mcfe										(85)	0	632
Change in proved reserves due to change in commodity prices (in Mcfe) | Mcfe										107	1,348	(28)
Change in proved reserves due to the SEC five-year development limitation on PUDs | Mcfe											237	129
Change in proved reserves due to ethane rejection | Mcfe												(174)
Change in proved reserves due to the uncertainty of future capital commitments | Mcfe											(258)
Change in proved reserves due to asset performance (in Mcfe) | Mcfe										(78)	12	22
Productive wells drilled										211	0	0
Standardized Measure of Discounted Future Net Cash Flows
Future estimated revenues		$ 10,876,241,000				$ 11,810,044,000				$ 10,876,241,000	$ 11,810,044,000	$ 38,350,590,000
Future estimated production costs		(6,286,264,000)				(7,276,564,000)				(6,286,264,000)	(7,276,564,000)	(16,358,433,000)
Future estimated development costs		(971,055,000)				(775,328,000)				(971,055,000)	(775,328,000)	(2,899,781,000)
Future net cash flows		3,618,922,000				3,758,152,000				3,618,922,000	3,758,152,000	19,092,376,000
10% annual discount for estimated timing of cash flows		(1,690,224,000)				(1,719,979,000)				(1,690,224,000)	(1,719,979,000)	(10,910,462,000)
Standardized measure of discounted future net cash flows – continuing operations		1,928,698,000				2,038,173,000				1,928,698,000	2,038,173,000	8,181,914,000
Standardized measure of discounted future net cash flows – discontinued operations		$ 0				$ 995,372,000				$ 0	$ 995,372,000	$ 4,330,377,000
Representative NYMEX prices: (1)
Natural gas (MMBtu) | $ / MMBTU	[3]									2.48	2.59	4.35
Oil (Bbl) | $ / bbl	[3]									42.64	50.16	95.27
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										$ (400,243,000)	$ (496,489,000)	$ (1,534,074,000)
Changes in estimated future development costs										18,843,000	1,069,971,000	88,324,000
Net change in sales and transfer prices and production costs related to future production										(162,460,000)	(6,105,531,000)	421,484,000
Purchases of minerals in place										0	0	2,473,512,000
Sales of minerals in place										0	(97,785,000)	(1,194,601,000)
Extensions, discoveries and improved recovery										221,765,000	69,745,000	236,395,000
Previously estimated development costs incurred during the period										0	91,719,000	550,514,000
Net change due to revisions in quantity estimates										(9,291,000)	(1,089,624,000)	(606,104,000)
Accretion of discount										203,817,000	818,191,000	726,400,000
Changes in production rates and other										18,094,000	(403,938,000)	(243,933,000)
Change – continuing operations										(109,475,000)	(6,143,741,000)	917,917,000
Change – discontinued operations										$ (995,372,000)	$ (3,335,005,000)	$ (304,955,000)
Natural Gas (Bcf)
Proved developed and undeveloped reserves:
Beginning of year | Mcf					2,231				3,568	2,231	3,568	2,730
Revisions of previous estimates | Mcf										(9)	(1,134)	54
Purchases of minerals in place | Mcf												1,354
Sales of minerals in place | Mcf											(13)	(426)
Extensions, discoveries and other additions | Mcf										265	10	36
Production | Mcf										(187)	(200)	(180)
End of year | Mcf		2,300				2,231				2,300	2,231	3,568
Proved developed reserves:
Beginning of year | Mcf					2,231				2,997	2,231	2,997	1,824
End of year | Mcf		2,128				2,231				2,128	2,231	2,997
Proved undeveloped reserves:
Beginning of year | Mcf					0				571	0	571	906
End of year | Mcf		172				0				172	0	571
Oil (MMBbls)
Proved developed and undeveloped reserves:
Beginning of year | MMBbls					103.4				197.4	103.4	197.4	194.7
Revisions of previous estimates | MMBbls										(4.3)	(81.9)	(13)
Purchases of minerals in place | MMBbls												45
Sales of minerals in place | MMBbls											(4.1)	(22.8)
Extensions, discoveries and other additions | MMBbls										10.1	3.8	6.7
Production | MMBbls										(10)	(11.8)	(13.2)
End of year | MMBbls		99.2				103.4				99.2	103.4	197.4
Proved developed reserves:
Beginning of year | MMBbls					103.4				141.7	103.4	141.7	138.7
End of year | MMBbls		93.3				103.4				93.3	103.4	141.7
Proved undeveloped reserves:
Beginning of year | MMBbls					0				55.7	0	55.7	56
End of year | MMBbls		5.9				0				5.9	0	55.7
NGL (MMBbls)
Proved developed and undeveloped reserves:
Beginning of year | MMBbls					97.3				146.3	97.3	146.3	183.5
Revisions of previous estimates | MMBbls										0.9	(38.4)	(45.3)
Purchases of minerals in place | MMBbls												54.4
Sales of minerals in place | MMBbls											(2)	(37.2)
Extensions, discoveries and other additions | MMBbls										15.2	0.8	2.5
Production | MMBbls										(9.3)	(9.4)	(11.6)
End of year | MMBbls		104.1				97.3				104.1	97.3	146.3
Proved developed reserves:
Beginning of year | MMBbls					97.3				117.5	97.3	117.5	125.2
End of year | MMBbls		94.4				97.3				94.4	97.3	117.5
Proved undeveloped reserves:
Beginning of year | MMBbls					0				28.8	0	28.8	58.3
End of year | MMBbls		9.7				0				9.7	0	28.8
[1]	See Note 3 for details about the Company’s acquisitions.
[2]	The results of discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016.
[3]	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 (75

Supplemental Quarterly Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Oil, natural gas and natural gas liquids sales		$ 277,955	$ 257,902	$ 216,426	$ 199,849	$ 247,226	$ 286,993	$ 323,038	$ 293,983	$ 952,132	$ 1,151,240	$ 2,312,137
Gains (losses) on oil and natural gas derivatives		(90,155)	166	(183,794)	109,453	270,849	521,365	(186,714)	421,514	(164,330)	1,027,014	1,127,395
Total revenues and other		219,250	286,913	64,851	346,699	536,520	839,441	177,068	766,984	917,713	2,320,013	3,638,267
Total expenses	[1]	292,194	331,929	296,824	472,912	3,284,372	2,113,892	420,494	681,222
(Gains) losses on sale of assets and other, net		9,462	2,310	2,517	1,269	(878)	(169,613)	(17,185)	(7,814)	15,558	(195,490)	(487,286)
Reorganization items, net		(145,838)	(28,361)	485,798	0					311,599	0	0
Income (loss) from continuing operations		(264,495)	(99,927)	201,652	(222,927)	(2,345,745)	(1,032,159)	(350,295)	(16,435)	(385,697)	(3,744,634)	(474,405)
Income (loss) from discontinued operations, net of income taxes		(569,742)	(98,438)	6,840	(1,124,819)	(126,462)	(537,158)	(28,832)	(322,725)	(1,786,159)	(1,015,177)	22,596
Net loss		$ (834,237)	$ (198,365)	$ 208,492	$ (1,347,746)	$ (2,472,207)	$ (1,569,317)	$ (379,127)	$ (339,160)	$ (2,171,856)	$ (4,759,811)	$ (451,809)
Income (loss) per unit – continuing operations:
Basic (in usd per unit)		$ (0.75)	$ (0.28)	$ 0.57	$ (0.64)	$ (6.69)	$ (2.94)	$ (1.04)	$ (0.05)	$ (1.10)	$ (10.91)	$ (1.47)
Diluted (in usd per unit)		(0.75)	(0.28)	0.57	(0.64)	(6.69)	(2.94)	(1.04)	(0.05)	(1.10)	(10.91)	(1.47)
Income (loss) per unit – discontinued operations:
Basic (in usd per unit)		(1.61)	(0.28)	0.02	(3.19)	(0.36)	(1.53)	(0.08)	(0.98)	(5.06)	(2.96)	0.07
Diluted (in usd per unit)		(1.61)	(0.28)	0.02	(3.19)	(0.36)	(1.53)	(0.08)	(0.98)	(5.06)	(2.96)	0.07
Net income (loss) per unit:
Basic (in usd per unit)		(2.36)	(0.56)	0.59	(3.83)	(7.05)	(4.47)	(1.12)	(1.03)	(6.16)	(13.87)	(1.40)
Diluted (in usd per unit)		$ (2.36)	$ (0.56)	$ 0.59	$ (3.83)	$ (7.05)	$ (4.47)	$ (1.12)	$ (1.03)	$ (6.16)	$ (13.87)	$ (1.40)
[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.