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Document and Entity Information Document - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2013	Jun. 30, 2013
Entity Registrant Name	BERRY PETROLEUM COMPANY, LLC
Entity Central Index Key	0000778438
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding	0
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	Yes
Entity Public Float		$ 0

Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Current assets
Other current assets	$ 30,833	$ 19,190
Noncurrent assets
Oil and natural gas properties (successful efforts method)	4,813,659	4,296,732
Other property and equipment	83,126	37,408
Less accumulated depreciation	(233)	(25,340)
Other property and equipment, net	82,893	12,068
Current liabilities
Other accrued liabilities	28,993	35,821
Noncurrent liabilities
Credit facility	1,173,175	562,900
Successor
Current assets
Cash and cash equivalents	51,041
Accounts receivable – trade, net	122,855
Derivative instruments	5,596
Deferred income taxes	0
Other current assets	30,833
Total current assets	210,325
Noncurrent assets
Oil and natural gas properties (successful efforts method)	4,813,659
Less accumulated depletion and amortization	(10,394)
Oil and gas property, net (successful efforts method)	4,803,265
Other property and equipment	83,126
Less accumulated depreciation	(233)
Other property and equipment, net	82,893
Derivative instruments	2,511
Other noncurrent assets	8,051
Noncurrent assets excluding property total	10,562
Total noncurrent assets	4,896,720
Total assets	5,107,045
Current liabilities
Accounts payable and accrued expenses	264,271
Derivative instruments	20,393
Other accrued liabilities	28,993
Current portion of long-term debt	211,558
Deferred income taxes	0
Total current liabilities	525,215
Noncurrent liabilities
Credit facility	1,173,175
Senior notes, net	916,428
Derivative instruments	4,649
Deferred income taxes	0
Other noncurrent liabilities	192,091
Total noncurrent liabilities	2,286,343
Commitments and contingencies (Note 9)
Member's/Shareholders' equity
Preferred stock, $0.01 par value, 2,000,000 shares authorized; no shares outstanding	0
Additional paid-in capital	2,315,460
Accumulated income (deficit)	(19,973)
Total member's/shareholders' equity	2,295,487
Total liabilities and member's/shareholders' equity	$ 5,107,045
Predecessor
Current assets
Cash and cash equivalents		312
Accounts receivable – trade, net		122,159
Derivative instruments		14,661
Deferred income taxes		703
Other current assets		19,190
Total current assets		157,025
Noncurrent assets
Oil and natural gas properties (successful efforts method)		4,296,732
Less accumulated depletion and amortization		(1,180,298)
Oil and gas property, net (successful efforts method)		3,116,434
Other property and equipment		37,408
Less accumulated depreciation		(25,340)
Other property and equipment, net		12,068
Derivative instruments		10,891
Other noncurrent assets		28,984
Noncurrent assets excluding property total		39,875
Total noncurrent assets		3,168,377
Total assets		3,325,402
Current liabilities
Accounts payable and accrued expenses		248,244
Derivative instruments		1,111
Other accrued liabilities		35,821
Deferred income taxes		1,456
Total current liabilities		286,632
Noncurrent liabilities
Credit facility		562,900
Senior notes, net		1,102,917
Derivative instruments		1,239
Deferred income taxes		255,471
Other noncurrent liabilities		101,452
Total noncurrent liabilities		2,023,979
Commitments and contingencies (Note 9)
Member's/Shareholders' equity
Preferred stock, $0.01 par value, 2,000,000 shares authorized; no shares outstanding		0
Additional paid-in capital		364,710
Accumulated income (deficit)		649,539
Total member's/shareholders' equity		1,014,791
Total liabilities and member's/shareholders' equity		3,325,402
Predecessor \| Common Class A
Capital stock, $0.01 par value
Common Stock		524
Predecessor \| Common Class B
Capital stock, $0.01 par value
Common Stock		$ 18

Balance Sheets Parentheticals	Dec. 31, 2012 $ / shares shares
Predecessor
Preferred Stock, Par or Stated Value Per Share \| $ / shares	$ 0.01
Preferred Stock, Shares Authorized	2,000,000
Preferred Stock, Shares Outstanding	0
Predecessor \| Common Class A
Common Stock, Par or Stated Value Per Share \| $ / shares	$ 0.01
Common Stock, Shares Authorized	100,000,000
Common Stock, Shares, Issued	52,428,423
Common Stock, Shares, Outstanding	52,428,423
Predecessor \| Common Class B
Common Stock, Par or Stated Value Per Share \| $ / shares	$ 0.01
Common Stock, Shares Authorized	3,000,000
Common Stock, Shares, Issued	1,763,866
Common Stock, Shares, Outstanding	1,763,866
Common Stock Liquidation Preference Value \| $ / shares	$ 0.50

Statements of Operations - USD ($) $ in Thousands		12 Months Ended
Statements of Operations - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Other income and (expenses)
Income tax expense (benefit)	$ 0	$ 65,280	$ 88,121	$ (142,228)
Successor
Revenues and other
Oil, natural gas and NGL sales	50,324
Electricity sales	1,444
Gains (losses) on oil and natural gas derivatives	(5,049)
Marketing revenues	399
Other revenues	0
Total revenues	47,118
Expenses
Lease operating expenses	15,410
Electricity generation expenses	1,257
Transportation expenses	2,576
Marketing expenses	376
General and administrative expenses	20,298
Exploration costs	0
Depreciation, depletion and amortization	10,845
Impairment of long-lived assets	0
Taxes, other than income taxes	2,130
(Gains) losses on sale of assets and other, net	10,208
Total expenses	63,100
Other income and (expenses)
Interest expense, net of amounts capitalized	(3,963)
Loss on extinguishment of debt	0
Other, net	(28)
Total other income and (expenses)	(3,991)
Income (loss) before income taxes	(19,973)
Income tax expense (benefit)	0
Net income (loss)	$ (19,973)
Predecessor
Revenues and other
Oil, natural gas and NGL sales		1,103,245	937,261	870,773
Electricity sales		33,992	29,940	34,953
Gains (losses) on oil and natural gas derivatives		(34,711)	64,620	13,908
Marketing revenues		7,827	7,631	13,832
Other revenues		949	1,674	1,769
Total revenues		1,111,302	1,041,126	935,235
Expenses
Lease operating expenses		325,209	243,173	215,854
Electricity generation expenses		22,485	19,975	25,690
Transportation expenses		32,930	28,624	21,442
Marketing expenses		7,593	6,873	13,038
General and administrative expenses		122,991	71,564	61,618
Exploration costs		24,048	21,010	1,794
Depreciation, depletion and amortization		279,757	227,700	215,822
Impairment of long-lived assets		0	0	629,252
Taxes, other than income taxes		41,509	39,757	33,617
(Gains) losses on sale of assets and other, net		(23)	(1,782)	(1,046)
Total expenses		856,499	656,894	1,217,081
Other income and (expenses)
Interest expense, net of amounts capitalized		(96,127)	(83,136)	(72,807)
Loss on extinguishment of debt		0	(41,545)	(15,544)
Other, net		51	109	(94)
Total other income and (expenses)		(96,076)	(124,572)	(88,445)
Income (loss) before income taxes		158,727	259,660	(370,291)
Income tax expense (benefit)		65,280	88,121	(142,228)
Net income (loss)		$ 93,447	$ 171,539	$ (228,063)

Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Successor
Net income (loss)	$ (19,973)
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income taxes	0
Other comprehensive income	0
Comprehensive income (loss)	$ (19,973)
Predecessor
Net income (loss)		$ 93,447	$ 171,539	$ (228,063)
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income taxes		0	5,517	38,289
Other comprehensive income		0	5,517	38,289
Comprehensive income (loss)		$ 93,447	$ 177,056	$ (189,774)

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Net Income
-URI http://asc.fasb.org/extlink&oid=6518256

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=31042434&loc=d3e3602-108585

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.19)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.18)
-URI http://asc.fasb.org/extlink&oid=26872669&loc=d3e20235-122688

Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Subparagraph (SX 210.7-04.22)
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Other Comprehensive Income
-URI http://asc.fasb.org/extlink&oid=6519514

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=28358780&loc=d3e565-108580

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 03
-Paragraph 19
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 20
-Article 9

+ Details

Statements of Comprehensive Income (Loss) Parentheticals - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Predecessor
Income tax benefit from amortization of accumulated other comprehensive loss related to de-designated hedges	$ 3,382	$ 23,467

Statements of Shareholders' Equity (Predecessor) - Predecessor - USD ($) $ in Thousands	Total	Additional Paid-in Capital	Accumulated income (deficit)	Accumulated Other Comprehensive Income (Loss)	Common Class A Common Stock	Common Class B Common Stock
Balances, beginning of period at Dec. 31, 2010	$ 1,024,553	$ 327,369	$ 740,458	$ (43,806)	$ 514	$ 18
Increase (Decrease) in Shareholders' Equity
Stock options and restricted stock issued	10,113	10,106			7
Stock based compensation expense	9,636	9,636
Income tax effect of stock option exercises	3,047	3,047
Dividends	(16,846)		(16,846)
Net income (loss)	(228,063)		(228,063)
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income taxes	38,289			(38,289)
Balances, end of period at Dec. 31, 2011	840,729	350,158	495,549	(5,517)	521	18
Increase (Decrease) in Shareholders' Equity
Stock options and restricted stock issued	3,687	3,684			3
Stock based compensation expense	9,819	9,819
Income tax effect of stock option exercises	1,049	1,049
Dividends	(17,549)		(17,549)
Net income (loss)	171,539		171,539
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income taxes	5,517			(5,517)
Balances, end of period at Dec. 31, 2012	1,014,791	364,710	649,539	0	524	18
Increase (Decrease) in Shareholders' Equity
Stock options and restricted stock issued	730	727			3
Stock based compensation expense	12,576	12,576
Income tax effect of stock option exercises	2,345	2,345
Dividends	(17,612)		(17,612)
Net income (loss)	93,447		93,447
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income taxes	0
Balances, end of period at Dec. 16, 2013	$ 1,106,277	$ 380,358	$ 725,374	$ 0	$ 527	$ 18

Statements of Shareholders' Equity (Predecessor) Parentheticals - $ / shares	12 Months Ended
	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Predecessor
Dividends per share	$ 0.32	$ 0.32	$ 0.31

Statements of Member's Equity (Successor) Statement - Dec. 31, 2013 - USD ($) $ in Thousands	Total	Additional Paid-in Capital	Accumulated Deficit
Balance beginning (Successor) at Dec. 16, 2013	$ 2,781,888	$ 2,781,888	$ 0
Distribution to affiliate \| Successor	(435,000)	(435,000)
Transfer of derivative liability from affiliate \| Successor	(31,428)	(31,428)
Transfer of derivative liability from affiliate	(31,428)
Net loss \| Successor	(19,973)		(19,973)
Balance ending (Successor) at Dec. 31, 2013	$ 2,295,487	$ 2,315,460	$ (19,973)

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

+ Details

Statements of Cash Flows - USD ($) $ in Thousands		12 Months Ended
Statements of Cash Flows - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Successor
Cash flows from operating activities
Net income (loss)	$ (19,973)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	10,845
Impairment of long-lived assets	0
Stock-based compensation expense	0
Loss on extinguishment of debt	0
Amortization and write-off of deferred financing fees	(615)
Change in book overdraft	0
Deferred income taxes	0
Other, net	0
Derivatives activities
Total (gains) losses	5,049
Cash settlements	0
Cash settlements on canceled derivatives	0
Amortization of accumulated other comprehensive loss	0
Changes in assets and liabilities
(Increase) decrease in accounts receivable – trade, net	71,434
(Increase) decrease in other assets	10,613
Increase (decrease) in accounts payable and accrued expenses	(8,078)
Increase (decrease) in other liabilities	(12,597)
Net cash provided by operating activities	56,678
Cash flows from investing activities
Property acquisitions	0
Development of oil and natural gas properties	(17,478)
Proceeds from sale of properties and equipment and other	0
Net cash used in investing activities	(17,478)
Cash flows from financing activities
Proceeds from borrowings	0
Repayments of debt	0
Dividends paid	(4,272)
Financing fees and other, net	0
Proceeds from stock option exercises	0
Distribution to affiliate	(435,000)
Excess tax benefit from stock-based compensation	0
Net cash provided by (used in) financing activities	(439,272)
Net increase (decrease) in cash and cash equivalents	(400,072)
Cash and cash equivalents at beginning of year	451,113
Cash and cash equivalents at end of year	51,041	$ 451,113
Predecessor
Cash flows from operating activities
Net income (loss)		93,447	$ 171,539	$ (228,063)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization		279,757	227,700	215,822
Impairment of long-lived assets		0	0	629,252
Stock-based compensation expense		12,576	9,819	9,636
Loss on extinguishment of debt		0	6,842	4,072
Amortization and write-off of deferred financing fees		6,685	7,031	8,243
Change in book overdraft		(14,885)	(1,220)	(156)
Deferred income taxes		76,644	82,881	(149,279)
Other, net		14,907	12,028	1,302
Derivatives activities
Total (gains) losses		34,711	(64,620)	(13,908)
Cash settlements		182	4,927	(76,941)
Cash settlements on canceled derivatives		0	14,659	0
Amortization of accumulated other comprehensive loss		0	8,899	61,755
Changes in assets and liabilities
(Increase) decrease in accounts receivable – trade, net		(97,653)	(6,740)	(23,526)
(Increase) decrease in other assets		996	(6,203)	(2,768)
Increase (decrease) in accounts payable and accrued expenses		28,187	23,507	21,703
Increase (decrease) in other liabilities		7,414	10,390	(1,245)
Net cash provided by operating activities		442,968	501,439	455,899
Cash flows from investing activities
Property acquisitions		(3,933)	(78,313)	(158,090)
Development of oil and natural gas properties		(594,579)	(693,866)	(556,229)
Proceeds from sale of properties and equipment and other		11,530	14,007	3,300
Net cash used in investing activities		(586,982)	(758,172)	(711,019)
Cash flows from financing activities
Proceeds from borrowings		1,225,475	2,067,200	1,126,300
Repayments of debt		615,200	1,785,799	864,844
Dividends paid		(13,204)	(17,549)	(16,846)
Financing fees and other, net		(459)	(11,841)	(2,630)
Proceeds from stock option exercises		730	3,687	10,113
Distribution to affiliate		0	0	0
Excess tax benefit from stock-based compensation		2,345	1,049	3,047
Net cash provided by (used in) financing activities		599,687	256,747	255,140
Net increase (decrease) in cash and cash equivalents		455,673	14	20
Cash and cash equivalents at beginning of year	$ 455,985	312	298	278
Cash and cash equivalents at end of year		$ 455,985	$ 312	$ 298

Basis of Presentation and Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Basis of Presentation and Significant Accounting Policies

Nature of Business

Berry Petroleum Company, LLC (“Berry” or the “Company”) was formed as a Delaware limited liability company on December 16, 2013, and is an indirect wholly owned subsidiary of Linn Energy, LLC (“LINN Energy”) engaged in the production and development of oil and natural gas. The Company’s predecessor, Berry Petroleum Company, was publicly traded from 1987 until being acquired by LINN Energy on December 16, 2013 (see “LINN Energy Transaction” below and Note 2). As of December 31, 2013, Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, is the Company’s sole member.

The Company’s properties are located in the United States (“U.S.”). Prior to the LINN Energy transaction, the Company had seven asset teams as follows: South Midway-Sunset (“SMWSS”)—Steam Floods, North Midway-Sunset (“NMWSS”)—Diatomite, NMWSS—New Steam Floods (“NSF”), Permian Basin, Uinta Basin, East Texas and Piceance Basin. Effective December 16, 2013, the Company realigned its existing asset teams into operating areas. The realignment had no effect on the Company’s operations. The Company currently has five operating areas in the U.S.: California, which includes SMWSS—Steam Floods, NMWSS—Diatomite and NMWSS—NSF, Permian Basin, Uinta Basin, East Texas and Piceance Basin.

The operations of the Company are governed by the provisions of a limited liability company agreement executed by its member. Pursuant to applicable provisions of the Delaware Limited Liability Company Act (the “Delaware Act”) and the Limited Liability Company Agreement of Berry Petroleum Company, LLC (the “Agreement”), the member has no liability for the debts, obligations and liabilities of the Company, except as expressly required in the Agreement or the Delaware Act. The Company will remain in existence unless and until dissolved in accordance with the terms of the Agreement.

LINN Energy Transaction

On December 16, 2013, the Company completed the previously-announced transactions contemplated by the merger agreement between LINN Energy, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and LINN Energy, under which LinnCo contributed Berry to LINN Energy in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy.

Basis of Presentation

The Company presents its financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.

The financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss), shareholders' equity or cash flows.

Predecessor and Successor Reporting

The LINN Energy transaction was accounted for under the acquisition method of accounting. Under the acquisition method of accounting, LinnCo initially, and LINN Energy upon the contribution was treated as the accounting acquirer and Berry was treated as the acquired company for financial reporting purposes. As such, the assets and liabilities of the Company were provisionally recorded at their respective fair values as of the acquisition date. Fair value adjustments related to the transaction have been pushed down to Berry, resulting in assets and liabilities of the Company being recorded at fair value at December 16, 2013. See Note 2 for additional information.

The Company’s statement of operations subsequent to the transaction includes depreciation, depletion and amortization expense on the Company’s oil and natural gas properties, and other property and equipment balances resulting from the fair value adjustments made under the new basis of accounting. Certain other items of income and expense were also impacted. Therefore, the Company’s financial information prior to the transaction is not comparable to its financial information subsequent to the transaction.

As a result of the impact of pushdown accounting, the financial statements and certain note presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the transaction (labeled predecessor) and the period after that date (labeled successor), to indicate the application of different basis of accounting between the periods presented.

Use of Estimates

The preparation of the accompanying financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. Actual results could differ from these estimates. Any changes in estimates resulting from continuous changes in the economic environment will be reflected in the financial statements in future periods.

Cash Equivalents

For purposes of the 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.”

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 $473,000 and $414,000 at December 31, 2013 (successor), and December 31, 2012 (predecessor), 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.

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $41,000, $6 million, $18 million and $29 million for the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011, respectively.

Impairment of Proved Properties

Based on the analysis described above, the Company recorded no impairment charges for the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, or for the year ended December 31, 2012. For the year ended December 31, 2011, the Company recorded a noncash impairment charge of approximately $625 million related to its East Texas natural gas properties primarily due to decreases in natural gas prices. The carrying value of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. Impairment charges are included in “impairment of long-lived assets” on the statements of operations.

Unproved Properties

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past.

Exploration Costs

Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves (“dry hole expense”) 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 exploration costs during the period from December 17, 2013, through December 31, 2013. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $16 million, $79,000 and $589,000 for the period from January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, December 31, 2011, respectively. For the year ended December 31, 2012, the Company also recorded dry hole expense and plugging and abandonment activities of approximately $15 million and $4 million, respectively. All of these expenses are included in “exploration costs” on the statements of operations.

Other Property and Equipment

Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from ten to 25 years for buildings and leasehold improvements and two to 30 years for plant and pipeline, drilling and other equipment.

Income Taxes and Uncertain Tax Positions

The successor Company is a limited liability company treated as a disregarded entity 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 members. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company.

Prior to the LINN Energy transaction on December 16, 2013, the Company was a Subchapter C-corporation. For predecessor periods prior to December 16, 2013, income taxes were recorded for the income tax effects of transactions reported in the financial statements and consist of income taxes payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income taxes were also recognized for income tax credits that were available to offset future income taxes. Deferred income taxes were measured by applying currently enacted income tax rates to the differences between the financial statements and income tax reporting. The Company routinely assessed the realizability of its deferred income tax assets, and a valuation allowance was recognized if it was determined that deferred income tax assets may not be fully utilized in future periods. The Company considered future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). The predecessor Company was subject to taxation in many jurisdictions, and the calculation of its income tax liabilities involved dealing with uncertainties in the application of complex income tax laws and regulations in various taxing jurisdictions. The Company recognized certain income tax positions that met a more-likely-than not recognition threshold. If the Company ultimately determined that the payment of these liabilities would be unnecessary, the Company reversed the liability and recognized an income tax benefit during the period in which the Company determined the liability no longer applied.

Derivative Instruments

The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and, from time to time, natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. These transactions are primarily in the form of swap contracts, collars and three-way collars.

Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the balance sheets as assets or liabilities. In January 2010, the Company elected to prospectively discontinue all hedge accounting, under which changes in derivative fair values were deferred in accumulated other comprehensive loss (“AOCL”). After January 2010, the Company no longer designated these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.

Fair Value of Financial Instruments

The carrying values of the Company’s receivables, payables and Credit Facility are estimated to be substantially the same as their fair values at December 31, 2013, and December 31, 2012. See Note 3 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.

Deferred Financing Fees

The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2013, and December 31, 2012, net deferred financing fees of approximately $5 million and $27 million, respectively, are included in “other noncurrent assets” on the balance sheets. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense. For the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011, amortization expense of approximately $83,000, $5 million, $5 million and $11 million, respectively, is included in “interest expense, net of amounts capitalized.”

Other Current Assets

The components of other current assets are as follows:



	Successor		Predecessor
(in thousands)	December 31, 2013		December 31, 2012
Short-term investments	$	—	$	125
Prepaid expenses	3,652		4,168
California carbon allowance inventories	15,895		545
Oil inventories	7,436		1,216
Materials inventories	3,036		12,943
Other	814		193
Other current assets	$	30,833	$	19,190

Other Accrued Liabilities

The components of other accrued liabilities are as follows:



	Successor		Predecessor
(in thousands)	December 31, 2013		December 31, 2012
Accrued interest	$	18,926	$	16,996
Accrued compensation	6,749		12,700
Asset retirement obligations (current portion)	3,318		4,430
Other	—		1,695
Other accrued liabilities	$	28,993	$	35,821

Revenue Recognition

Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the 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 electricity and natural gas the Company produces and uses in its operations are not included in revenues. The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing sales and marketing expenses.

Business and Credit Concentrations

The Company maintains its cash in bank deposit accounts which at times may exceed federally insured amounts. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on its cash.

The Company sells oil and natural gas to various types of customers, including pipelines, refineries and other oil and natural gas companies, and electricity to utility companies. Based on the current demand for oil and natural gas and the availability of other purchasers, the Company believes that, with the exception of its primary customer in Utah, the loss of any one of its major purchasers would not have a material adverse effect on its financial condition, results of operations and net cash provided by operating activities.

For the period from December 17, 2013, through December 31, 2013, the Company’s two largest customers represented approximately 50% and 10%, respectively, of the Company’s oil, natural gas and NGL sales. For the period from January 1, 2013, through December 16, 2013, the Company’s two largest customers represented approximately 45% and 10%, respectively, of the Company’s oil, natural gas and NGL sales. For the year ended December 31, 2012, the Company’s two largest customers represented approximately 43% and 13%, respectively, of the Company’s oil, natural gas and NGL sales. For the year ended December 31, 2011, the Company’s two largest customers represented approximately 43% and 14%, respectively, of the Company’s oil, natural and NGL gas sales. For the years ended December 31, 2013, December 31, 2012, and December 31, 2011, 100% of electricity sales were attributable to two customers.

At December 31, 2013, trade accounts receivable from one customer represented approximately 48% of the Company’s receivables. At December 31, 2012, trade accounts receivable from two customers represented approximately 43% and 13% of the Company’s receivables.

Electricity Cost Allocation

The Company owns three cogeneration facilities. Its investment in cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations in California and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power (“CHP”), extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. The Company allocates steam costs to lease operating expenses based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. A portion of the costs of operating the cogeneration facilities is also allocated to depreciation, depletion and amortization. Electricity revenue represents sales to utilities.

Stock-Based Compensation

The successor Company does not have any equity incentive plans under which it grants stock awards. Prior to the LINN Energy transaction, the Company granted equity awards to its employees under its own equity incentive plans.

The predecessor Company recognized stock-based compensation expense over the requisite service period in an amount equal to the fair value of stock-based awards granted to employees and nonemployee directors. The fair value of stock-based awards was computed at the date of grant and was not remeasured. See Note 6 for additional details about the Company’s accounting for stock-based compensation.

Supplemental Disclosures to Statements of Cash Flows

Supplemental disclosures to the statements of cash flows are presented below:



	Successor		Predecessor
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31,
(in thousands)	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		2012		2011
Cash payments for interest, net of amounts capitalized	$	—	$	87,495	$	64,602	$	59,853
Cash payments for income taxes	$	—	$	622	$	4,227	$	7,914
Noncash investing activities:
Accrued capital expenditures	$	4,788	$	70,866	$	98,020	$	61,098
Asset retirement obligations	$	—	$	15,998	$	18,248	$	7,448

On December 16, 2013, the date of the LINN Energy transaction, the Company paid approximately $5 million of debt issuance costs related to the amendment of it’s Credit Facility

LINN Energy Merger, Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

LINN Energy Merger, Acquisitions and Divestitures

LINN Energy Transaction, Acquisitions and Divestitures

LINN Energy Transaction

On December 16, 2013, the Company completed the previously-announced transactions contemplated by the merger agreement between LINN Energy, LinnCo, an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and LINN Energy, under which LinnCo contributed Berry to LINN Energy in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. The transaction has a preliminary value of approximately $4.6 billion, including the assumption of approximately $2.3 billion of Berry’s debt and net of cash acquired of approximately $451 million.

On the Berry acquisition date, LinnCo contributed Berry to its affiliate, LINN Energy. As a result, the assets, liabilities and results of operations of Berry are not included in LinnCo’s financial statements.

The acquisition was accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition date, while transaction and integration costs associated with the acquisition were expensed as incurred. The initial accounting for the business combination is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date.

The following presents the values assigned to the net assets acquired as of the acquisition date (in thousands):



Assets:
Cash	$	451,113
Current	249,564
Noncurrent	97,202
Oil and natural gas properties	4,791,394
Total assets acquired	5,589,273

Liabilities:
Current	310,105
Noncurrent	100,809
Asset retirement obligations, current and noncurrent	94,612
Long-term debt, including current portion	2,301,859
Total liabilities assumed	2,807,385

Net assets acquired	$	2,781,888

Current assets include receivables of approximately $194 million and derivative instruments of approximately $14 million. Noncurrent assets include derivative instruments of approximately $6 million and other property and equipment of approximately $83 million. Current liabilities include payables of approximately $272 million and out-of-market natural gas transportation contracts of approximately $19 million. Noncurrent liabilities include out-of-market natural gas transportation contracts of approximately $88 million.

The fair value measurements of derivative instruments assumed were determined utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis, and represent Level 2 inputs. The fair value measurements of long-term debt were estimated based on prices quoted from third-party financial institutions and also represent Level 2 inputs.

The fair value measurements of certain other assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value measurements of natural gas transportation contracts and operating leases assumed were determined utilizing a form of the income approach using Level 3 inputs which measures the contract relative to a replacement contract or the current market. Contracts with favorable fair values compared to the original contract terms were recorded in “other current assets” and “other noncurrent assets” and contracts with unfavorable fair values compared to the original contract terms were recorded in “accounts payable and accrued expenses” and “other noncurrent liabilities” on the balance sheet. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates at the time of the valuation and are the most sensitive and subject to change.

In connection with the LINN Energy transaction, the Company incurred transaction costs of approximately $16 million and $45 million for the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, respectively.

As a result of being formed as a limited liability company on December 16, 2013, the date of the LINN Energy transaction, the Company ceased to be subject to federal and state income taxes, with the exception of the state of Texas. Therefore, the Company’s net deferred income tax liabilities of approximately $256 million at December 31, 2012, decreased to zero at December 31, 2013. The Company’s net deferred income tax liabilities were assumed by LinnCo in the merger and were not transferred to LINN Energy in the contribution.

Acquisitions – 2012 and 2011

On September 12, 2012, the Company completed the acquisition of approximately 14,000 net acres contiguous to the Company’s Brundage Canyon asset in the Uinta Basin for approximately $40 million. The acquisition was financed using the Company’s Credit Facility.

On April 13, 2012, the Company completed the acquisition of approximately 2,000 net acres and one well in the Wolfberry trend in the Permian Basin for approximately $15 million. The acquisition was financed using the Company’s Credit Facility.

On May 25, 2011, the Company acquired interests in producing properties on approximately 6,000 net acres in the Wolfberry trend in the Permian Basin for approximately $128 million. The acquisition was financed using the Company’s Credit Facility.

Divestiture – 2012

In December 2011, the Company entered into an agreement to sell its assets related to proved developed properties in Elko, Eureka and Nye counties in Nevada (“Nevada Assets”), which closed on January 31, 2012, for total cash consideration of approximately $16 million and resulted in a gain of approximately $2 million which is included in “(gains) losses on sales of assets and other, net” on the statement of operations for the year ended December 31, 2012.

Debt

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt

The following summarizes the Company’s outstanding debt:



	Successor			Predecessor
(in millions, except percentages)	December 31, 2013			December 31, 2012
Credit facility ⁽¹⁾	$	1,173		$	563
10.25% senior notes due June 2014	205			205
6.75% senior notes due November 2020	300			300
6.375% senior notes due September 2022	600			600
Net unamortized discounts and premiums	23			(2		)
Total debt, net	2,301			1,666
Less current maturities	(211		)	—
Total long-term debt, net	$	2,090		$	1,666


⁽¹⁾	Variable interest rates of 2.67% and 2.00% at December 31, 2013, and December 31, 2012, respectively.

Fair Value

The Company’s debt is recorded at the carrying amount in the balance sheets. The carrying amount of the Company’s Credit Facility approximates fair value because the interest rate is variable and reflective of market rates. The Company uses a market approach to determine the fair value of its senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.



	Successor				Predecessor
	December 31, 2013				December 31, 2012
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit facility	$	1,173	$	1,173	$	563	$	563
Senior notes, net	1,128		1,129		1,103		1,179
Total debt, net	$	2,301	$	2,302	$	1,666	$	1,742

Credit Facility

In December 2013, the Company entered into an amendment to its Second Amended and Restated Credit Agreement (“Credit Facility”) primarily to conform certain terms in the Credit Facility to like terms in LINN Energy’s credit facility. The maturity date is May 2016. The Credit Facility has a borrowing base of $1.4 billion, subject to lender commitments. At December 31, 2013, lender commitments under the facility were $1.2 billion , including outstanding letters of credit, and there was no remaining borrowing capacity available. Any borrowings under the Credit Facility must be repaid upon the refinancing of all of the Company’s outstanding senior notes. In February 2014, the Company entered into an amendment to the Credit Facility to amend the terms of certain financial and reporting covenants.

Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October. The lenders under the Credit Facility also have the right to request interim borrowing base redeterminations once between scheduled redeterminations, contemporaneously with issuances of permitted unsecured debt, in conjunction with unwinding certain derivatives and in conjunction with certain permitted sales of property. The Company also has the right to request interim borrowing base redeterminations once between scheduled redeterminations and in conjunction with certain issuances of permitted unsecured debt. Significant declines in commodity prices may result in a decrease in the borrowing base. The Company’s obligations under the Credit Facility are secured by mortgages on its oil and natural gas properties and other personal property. The Company is required to maintain mortgages on properties representing at least 80% of the present value of its oil and natural gas proved reserves.

The Company is currently in compliance with all financial and other covenants of the Credit Facility. At December 31, 2013, the Company’s Current Ratio (as defined in the Credit Facility), fell short of the requirement under its covenant primarily due to factors related to the transactions between the Company, LinnCo and LINN Energy, including a reassessment of the carrying value of items on the Company’s balance sheet as of the acquisition date and updated accruals as of December 31, 2013. In February 2014, the Company received a waiver of the applicability of that covenant and any noncompliance which may have resulted as of December 31, 2013, and entered into an amendment to its Credit Facility to address this covenant for future periods. The shortfall and related waiver and amendment had no effect on the Company’s compliance with the indentures governing its outstanding senior notes for the quarter ended December 31, 2013, and the Company was in compliance with all of the covenants under the indentures governing its senior notes at December 31, 2013.

At the Company’s election, interest on borrowings under the Credit Facility is determined by reference to either the LIBOR plus an applicable margin between 1.5% and 2.5% per annum (depending on the then-current level of borrowings under the Credit Facility) or a Base Rate (as defined in the Credit Facility) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the Base Rate and at the end of the applicable interest period for loans bearing interest at LIBOR. The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% (depending on the then-current level of utilization under the Credit Facility) on the average daily unused amount of the maximum commitment amount of the lenders.

Senior Notes Due June 2014

The Company’s $205 million in aggregate principal amount of 10.25% senior notes due June 2014 (the “June 2014 Senior Notes”) matures on June 1, 2014. Therefore, the $205 million is classified as a current obligation on the Company’s balance sheet at December 31, 2013. In March 2014, the Company and LINN Energy entered into a parent support agreement under which LINN Energy agreed to provide the Company with funds in an amount sufficient to enable the Company to pay the Company’s June 2014 Senior Notes in full upon maturity.

The June 2014 Senior Notes were recorded at their fair value of $212 million on the acquisition date and the $7 million premium is being amortized to interest expense over the life of the related notes.

The June 2014 Senior Notes are redeemable at the Company’s option, in whole or in part, at any time at a price equal to 100% of the principal amount of the June 2014 Senior Notes plus accrued and unpaid interest, if any, plus a “make-whole” premium.

Senior Notes Due November 2020

The Company has $300 million in aggregate principal amount of 6.75% senior notes due November 2020 (the “November 2020 Senior Notes”). The November 2020 Senior Notes were recorded at their fair value of $310 million on the acquisition date and the $10 million premium is being amortized to interest expense over the life of the related notes.

The Company could have redeemed up to 35% of the November 2020 Senior Notes at any time prior to November 1, 2013, on one or more occasions, with the proceeds of certain equity offerings at a redemption price of 106.75%. The Company may redeem all or any part of the November 2020 Senior Notes at any time beginning on or after November 1, 2015 at the redemption prices set forth below, expressed as percentages of the principal amount redeemed, plus accrued and unpaid interest:



2015	103.375	%
2016	102.250	%
2017	101.125	%
2018 and thereafter	100.000	%

The Company may also redeem the November 2020 Senior Notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium, plus accrued and unpaid interest to the redemption date.

Senior Notes Due September 2022

On March 9, 2012, the Company issued $600 million aggregate principal amount of 6.375% notes due September 2022 (the “September 2022 Senior Notes”) for net proceeds of approximately $590 million. The September 2022 Senior Notes were recorded at their fair value of $607 million on the acquisition date and the $7 million premium is being amortized to interest expense over the life of the related notes.

Prior to March 15, 2015, the Company may, at its option, on any one or more occasions redeem up to 35% of the aggregate principal amount of the September 2022 Senior Notes with the net cash proceeds of certain equity offerings and if certain conditions are met as described in the indenture governing the September 2022 Senior Notes, at a redemption price of 106.375% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. At any time prior to March 15, 2017, the Company may also redeem all or part of the September 2022 Senior Notes at a redemption price equal to 100% of the principal amount of the notes redeemed plus a “make-whole” premium described in the indenture, plus accrued and unpaid interest, if any, to the redemption date.

On and after March 15, 2017, the Company may redeem all or, from time to time, a part of the September 2022 Senior Notes upon not less than 30 nor more than 60 days’ notice, at the following redemption prices (expressed as a percentage of principal amount of notes to be redeemed), plus accrued and unpaid interest, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the 12-month period beginning on March 15 of the years indicated below:



2017	103.188	%
2018	102.125	%
2019	101.063	%
2020 and thereafter	100.000	%

The June 2014 Senior Notes, November 2020 Senior Notes and September 2022 Senior Notes are senior unsecured obligations of the Company, which rank effectively junior in right of payment to all of the Company’s existing and any future secured debt, to the extent of the value of the collateral securing that debt, rank equally in right of payment with any of the Company’s future senior unsecured debt and rank senior in right of payment to any of the Company’s future subordinated debt.

The Company’s senior notes contain covenants that, among other things, may limit its ability to: (i) incur or guarantee additional indebtedness; (ii) pay distributions on its equity or redeem its subordinated debt; (iii) create certain liens; (iv) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (v) sell assets; (vi) engage in transactions with affiliates; and (vii) consolidate, merge or transfer all or substantially all of the Company’s assets. The Company is in compliance with all financial and other covenants of its senior notes.

The Company may from time to time seek to repurchase its outstanding debt through open market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, may be material and will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.

Debt Redemption and Repurchases

In April 2012, the Company redeemed all $200 million aggregate principal amount of its 8.25% senior notes due 2016 (the “2016 Senior Notes”) and repurchased $150 million aggregate principal amount of its June 2014 Senior Notes for an aggregate purchase price of approximately $216 million and $182 million, respectively, including accrued and unpaid interest. The related loss of approximately $42 million recorded in loss on extinguishment of debt consists of approximately $35 million in premiums paid over par and approximately $7 million in write-offs of debt issuance costs. These notes were redeemed and repurchased using net proceeds from the issuance of the Company’s September 2022 Senior Notes.

Following the $150 million repurchase, approximately $205 million aggregate principal amount of June 2014 Senior Notes remained outstanding.

From August to October 2011, the Company repurchased $95 million aggregate principal amount of its June 2014 Senior Notes for an aggregate purchase price of approximately $109 million. The related loss of approximately $15 million recorded in loss on extinguishment of debt consists of approximately $12 million in premiums paid over par and approximately $3 million in write-offs of net discounts and debt issuance costs. Following the repurchase, approximately $355 million aggregate principal amount of June 2014 Senior Notes remained outstanding.

Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Taxes

The Company is a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company, except as set forth in the tables below. Prior to the LINN Energy transaction, the Company was a Subchapter C-corporation subject to federal and state income taxes. Amounts recognized for income taxes purposes are reported in “income tax expense (benefit)” on the statements of operations.

Income tax expense (benefit) consisted of the following:



	Successor		Predecessor
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			Year Ended December 31,
(in thousands)	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			2012		2011
Current taxes:
Federal	$	—	$	(225	)	$	286	$	4,115
State	—		(11,043		)	4,954		2,936
Deferred taxes:
Federal	—		56,620			80,083		(125,261		)
State	—		19,928			2,798		(24,018		)
	$	—	$	65,280		$	88,121	$	(142,228	)

A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:



	Successor		Predecessor
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31,
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		2012		2011
Federal statutory rate	35	%	35	%	35	%	35	%
State, net of federal tax benefit	—		3		3		3
Loss excluded from nontaxable entities	(35	)	—		—		—
Deferred state rate impact	—		—		(1	)	—
Research and development credits	—		—		(3	)	—
Net impact to uncertain income tax positions	—		(2	)	—		1
Transaction costs	—		4		—		—
Other	—		1		—		(1	)
Effective rate	—	%	41	%	34	%	38	%

The effective tax rate for the successor period from December 17, 2013, through December 31, 2013, was zero as the Company is a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas.

Significant components of the deferred tax assets and liabilities were as follows:



	Successor		Predecessor
(in thousands)	December 31, 2013		December 31, 2012
Deferred tax assets:
Federal benefit of state income taxes	$	—	$	(239	)
Credit carryforwards	—		36,028
Equity and deferred compensation	—		15,139
Net operating loss	—		412
Bad debt expense	—		163
Other, net	—		610
Valuation allowance	—		(1,201		)
	—		50,912
Deferred tax liabilities:
Depreciation and depletion	—		(298,659		)
Derivatives	—		(8,477		)
	—		(307,136		)

Net deferred tax liabilities	$	—	$	(256,224	)

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2013, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.

Changes in the balance of unrecognized tax benefits excluding interest and penalties on uncertain tax positions were as follows:



	Successor		Predecessor
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			Year Ended December 31,
(in millions)	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			2012			2011
Unrecognized tax benefits at beginning of period	$	—	$	23		$	3		$	5
Increases (decreases) for positions taken in prior year	—		(1		)	21			—
Decreases for settlements with taxing authorities	—		—			—			(2		)
Decreases for lapses in the applicable statute of limitations	—		(2		)	(1		)	—
Unrecognized tax benefits at end of period	$	—	$	20		$	23		$	3

In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2013, and December 31, 2012.

As a result of being formed as a limited liability company on December 16, 2013, the date of the LINN Energy transaction, all unrecognized tax benefits of the predecessor were assumed by LinnCo. The tax years 2010 – 2012 remain open to examination for income tax purposes in the state of Texas.

During the predecessor period from January 1, 2013, through December 16, 2013, the Company decreased the unrecognized tax benefits by approximately $3 million due to the closing of certain federal and state income tax years, which resulted in a reduction of the effective income tax rate. As of December 16, 2013, the Company had a gross liability for uncertain income tax benefits of approximately $20 million. The Company had accrued approximately $19,000 and $426,000 of interest related to its uncertain income tax positions as of December 16, 2013, and December 31, 2012, respectively.

Member's and Shareholders' Equity	12 Months Ended
Member's and Shareholders' Equity	Dec. 31, 2013
Equity [Abstract]
Shareholder's Equity	Member’s and Shareholders’ Equity On December 16, 2013, in connection with the LINN Energy transaction, the outstanding Class A Common Stock (“Common Stock”) and Class B Stock of the Company were acquired by LinnCo, an affiliate of LINN Energy. On that date, the Company was reorganized as a Delaware limited liability company and its sole member is Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy. Prior to being acquired by LinnCo, shares of Common Stock and Class B Stock were entitled to one vote and 95% of one vote, respectively. Each share of Class B Stock was entitled to a $0.50 per share preference in the event of liquidation or dissolution. Further, each share of Class B Stock was convertible into one share of Common Stock at the option of the holder. Dividends The regular annual dividend for 2013 was $0.32 per share and was paid quarterly in March, June, September and December. Dividend payments were limited by covenants in the Credit Facility to the greater of $35 million or 75% of net income for any four quarter period. In addition, the indentures governing the Company’s senior notes contain provisions potentially restricting the Company’s ability to declare dividends if certain situations arose; provided that, notwithstanding such restrictions, the Company may declare dividends up to $0.36 per share annually (so long as such distributions did not exceed $20 million annually) in the event that the Company was not in default under the indentures and up to $10 million in the event that the Company was in a nonpayment default under the indentures. Since December 16, 2013, the effective date of the LINN Energy transaction, the Company has not declared a dividend and does not currently plan to do so in the future. However, the Company has the ability to make distributions to LINN Energy in accordance with the terms of the indentures governing its senior notes.

- Definition

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(d),(e))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 4
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Topic 310
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-Paragraph 2
-Subparagraph (SAB TOPIC 4.E)
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Subparagraph (SX 210.3-04)
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 30
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-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6405834&loc=d3e23285-112656

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Preferred Stock
-URI http://asc.fasb.org/extlink&oid=6521494

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21564-112644

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
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-Paragraph d
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Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
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Reference 16: http://www.xbrl.org/2003/role/presentationRef
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-Name Staff Accounting Bulletin (SAB)
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Reference 17: http://www.xbrl.org/2003/role/presentationRef
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Reference 18: http://www.xbrl.org/2003/role/presentationRef
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Reference 19: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

+ Details

Equity Incentive Compensation Plans and Other Benefit Plans

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity Incentive Compensation Plans and Other Benefit Plans

LINN Energy Transaction

In connection with the LINN Energy transaction, effective December 16, 2013, the following occurred with respect to the Company’s stock-based incentive awards:

Each Company restricted stock unit (“RSU”) that was vested as of the effective time of the acquisition, that was held by a current or former nonemployee director or by an employee of the Company whose employment was terminated in connection with the acquisition as agreed by the parties or that was subject to performance-based vesting criteria was converted as of the effective time of the acquisition into a number of LinnCo common shares equal to the product determined by multiplying the number of shares of the Company’s Common Stock subject to the Company RSU immediately prior to the effective time of the acquisition by the exchange ratio (1.68). Each performance-based Company RSU that was outstanding immediately prior to the effective time of the acquisition was deemed to have been earned at the target level as specified in the applicable award agreement.

Each unvested Company RSU (excluding any Company RSU held by a current or former nonemployee director of the Company or by an employee of the Company whose employment was terminated in connection with the acquisition as agreed by the parties and any performance-based Company RSU) was converted into a restricted unit award in respect of the number of LINN Energy units (rounded to the nearest whole unit) equal to the product determined by multiplying the number of shares of the Company Common Stock subject to the Company RSU immediately prior to the effective time of the acquisition by the exchange ratio (1.68) and by the LinnCo/LINN exchange ratio (1.0013), and are subject generally to the same terms and conditions as were applicable to the related Company RSU immediately prior to the effective time of the acquisition. The LinnCo/LINN exchange ratio was the average of the closing prices of one LinnCo common share on the NASDAQ on the last five full trading days prior to the closing date of the acquisition divided by the average of the closing prices of one LINN Energy unit on the NASDAQ on the last five full trading days prior to the closing date of the acquisition.

Each option to purchase shares of the Company Common Stock was converted into an option to purchase, generally on the same terms and conditions as were applicable to such option immediately prior to the effective time of the acquisition, (i) a number of LINN Energy units (rounded down to the nearest whole unit) equal to the product determined by multiplying the number of shares of Company Common Stock subject to such option by the exchange ratio and by the LinnCo/LINN exchange ratio, (ii) at an exercise price per LINN Energy unit (rounded up to the nearest whole cent) equal to the quotient determined by dividing the per share exercise price for the shares of Company Common Stock subject to the option by the product determined by multiplying the exchange ratio and the LinnCo/LINN exchange ratio.

The following disclosures relate to the predecessor periods and the conversion of Company RSUs and options only. All information is based on historical Company stock prices and includes no adjustments for the exchange ratios.

Predecessor Stock Compensation Plans

The Predecessor’s 2010 Equity Incentive Plan (“2010 Plan”) and 2005 Equity Incentive Plan (“2005 Plan”), collectively, (the (“Equity Incentive Plans”), approved by the Company’s shareholders in May 2010 and May 2005, provided for granting of equity compensation up to an aggregate of 1,000,000 shares and 2,900,000 shares of Common Stock, respectively. The purpose of the Equity Incentive Plans was to encourage ownership in the Company by key personnel whose long-term service was considered essential to the Company’s continued progress and, thereby, align participants’ and shareholders’ interests. Stock options, stock appreciation rights (“SAR”), cash awards and stock awards, including restricted shares and stock units, could be granted under the Equity Incentive Plans. The exercise price of an option could not be less than the fair market value of one share of Common Stock on the date of grant. Stock options and RSUs granted under the Equity Incentive Plans historically vested either in increments of 25% on each of the first four anniversary dates of the date of grant or 100% after three years. Stock options and RSUs granted to nonemployee directors historically vested immediately. Options granted under the Equity Incentive Plans had a term of ten years.

The total compensation expense recognized by the predecessor in the statements of operations for grants under the Equity Incentive Plans was approximately $12 million, $9 million and $9 million for the period from January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011, respectively.

Stock Options

The following table summarizes stock option activity under the predecessor’s Equity Incentive Plans for the period from January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011:



	Number of Shares		Weighted Average Exercise Price		Aggregate Intrinsic Value (in thousands) ⁽¹⁾		Weighted Average Remaining Contractual Term (Years)
Outstanding at January 1, 2011	2,017,225		$	25.87	$	35,974
Granted	89,865		48.50
Exercised	(579,636	)	17.47		17,746
Canceled/expired	(6,765	)	45.92
Outstanding at December 31, 2011	1,520,689		30.32		17,798
Granted	82,262		53.02
Exercised	(215,359	)	17.12		7,194
Outstanding at December 31, 2012	1,387,592		33.71		4,681
Exercised	(57,350	)	12.74		2,066
Outstanding at December 16, 2013	1,330,242		$	34.61	$	19,243	3.21
Vested and expected to vest at December 16, 2013	1,328,771		$	34.60	$	19,243	3.21
Exercisable at December 16, 2013	1,224,022		$	33.18	$	19,229	2.81


⁽¹⁾	The intrinsic value of a stock option is the amount by which the market value of the underlying stock at the end of the related period exceeds the exercise price of the option.

The fair value of each option granted was estimated using the Black-Scholes option pricing model. Expected volatility was calculated based on the historical volatility of the Company’s Common Stock, and the risk-free interest rate was based on U.S. treasury yield curve rates with maturities consistent with the expected life of each stock option. The key assumptions used in computing the weighted average fair market value of stock options granted were as follows:



	2012		2011
Expected volatility	50.00	%	45.00	%
Risk-free rate	0.95	%	2.54	%
Dividend yield	0.57	%	0.62	%
Expected term (in years)	5.2		6.0

The following table summarizes information about stock options at December 16, 2013:



	Stock Options Outstanding				Stock Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Remaining Contractual Term (Years)	Weighted Average Exercise Price		Number of Options	Weighted Average Remaining Contractual Term (Years)	Weighted Average Exercise Price
$21.58-$21.77	240,000	0.90	$	21.60	240,000	0.90	$	21.60
$30.65-$32.57	639,000	2.50	31.70		639,000	2.50	31.70
$38.00-$53.02	451,242	5.43	45.66		345,022	4.71	43.98
	1,330,242	3.21	$	34.61	1,224,022	2.81	$	33.18

Restricted Stock Units

The following table summarizes RSU activity under the predecessor’s Equity Incentive Plans for the period from January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011:



	RSUs		Weighted Average Intrinsic Value at Grant Date		Vest Date Fair Value (in thousands)
Outstanding at January 1, 2011	857,360		$	19.67
Granted	159,333		47.98
Issued	(62,127	)	26.18		$	2,588
Canceled/expired	(39,544	)	25.12
December 31, 2011	915,022		$	23.88
Granted	164,112		50.60
Issued	(79,068	)	33.10		$	3,401
Canceled/expired	(18,189	)	41.50
December 31, 2012	981,877		$	26.72
Granted	286,344		45.51
Issued	(853,169	)	23.94		$	39,513
Canceled/expired	(22,511	)	44.69
Outstanding at December 16, 2013	392,541		$	46.86

The grant date fair value of RSUs issued under the 2005 Plan and 2010 Plan was based on the average high and low stock price of a share of Common Stock on the date of grant and the closing price of a share of Common Stock on the date of grant, respectively. The Company used historical data and projections to estimate expected restricted stock forfeitures. The expected forfeitures are then included as part of the grant date estimate of compensation expense.

Performance Share Program

The following table summarizes performance share award activity under the predecessor’s equity incentive plans for the period from January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011:



	Performance Share Awards		Weighted Average Grant Date Fair Value		Vest Date Fair Value (in thousands)
Outstanding on January 1, 2011	103,794		$	31.20
Granted	65,620		51.86
Canceled/expired	(6,565	)	44.20
Outstanding at December 31, 2011	162,849		$	39.00
Granted	59,738		63.69
Outstanding at December 31, 2012	222,587		$	45.79
Issued	(135,167	)	44.33		$	6,308
Canceled/expired	(87,420	)	44.42
Outstanding at December 16, 2013	—		$	—

The vesting of the performance share awards was contingent upon satisfying certain performance criteria. For the portion of the performance share awards subject to internal performance metrics, the grant date fair value was determined by reference to the closing price of a share of Common Stock on the date of grant. The Company recognized compensation expense when it became probable that these conditions would be achieved. However, any such compensation expense recognized was reversed if vesting did not actually occur.

For the portion of the performance share awards subject to market-based vesting criteria, the grant date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company’s Common Stock, and the risk-free interest rate is based on U.S. treasury yield curve rates with maturities consistent with the three-year vesting period. The key assumptions used in valuing the market-based portion of the performance share awards were as follows:



	2012		2011
Number of simulations	100,000		100,000
Expected volatility	50	%	44	%
Risk-free rate	0.42	%	1.15	%

The total grant date fair value of the market-based portion of the performance share awards issued during each of the years ended December 31, 2012 and December 31, 2011, as determined by the Monte Carlo valuation model, was approximately $1 million and was being recognized ratably over the respective three-year vesting period. Compensation expense for the market-based portion of the performance share awards was not reversed if vesting did not actually occur.

Director Fees

Under the predecessor, the Company’s directors could elect to receive their annual retainer and meeting fees in the form of the Company’s Common Stock issued pursuant to the Company’s Non-Employee Director Deferred Stock and Compensation Plan (“Deferred Plan”). The Deferred Plan permitted eligible directors, in recognition of their contributions to the Company, to receive compensation for service and to defer recognition of their compensation in whole or in part to a stock unit account or an interest account. When the eligible director ceased to be a director, the distribution from the stock unit account was made in shares of Common Stock while the distribution from the interest account was made in cash. Shares of Common Stock earned and deferred in accordance with the Deferred Plan for the period from January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011 were 10,758, 12,797 and 13,647, respectively.

Amounts allocated to the stock unit account had the right to receive a “dividend equivalent” equal to the dividends declared and paid by the Company and reinvested in additional stock units and credited to the director’s account using an established market value. Amounts allocated to the interest account were credited with interest at an established interest rate.

Defined Contribution Plan

Prior to the LINN Energy transaction, the Company sponsored a defined contribution thrift plan under section 401(k) of the Internal Revenue Code to assist all employees in providing for retirement or other future financial needs. Employees were eligible to participate in the 401(k) Plan on their date of hire and the Company matched 100% of each employee’s contribution up to 8% of an employee’s eligible compensation. Approximately 93% of the Company’s employees participated in the 401(k) Plan for the period from January 1, 2013, through December 16, 2013. The Company’s contributions to the 401(k) Plan, net of forfeitures, were approximately $2 million for the period from January 1, 2013, through December 16, 2013, and for each of the years ended December 31, 2012, and December 31, 2011.

As of December 31, 2013, the Company had no employees. All former employees of the Company that were retained after the LINN Energy transaction are now employed by Linn Operating, Inc. (“LOI”), a subsidiary of LINN Energy, and along with other LOI personnel, will provide services and support to the Company in accordance with an agency agreement and power of attorney between the Company and LOI.

Derivative Instruments

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the price of oil 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. As a result, currently, the Company directly hedges only its oil production. The Company also, from time to time, enters into derivative contracts for a portion of its natural gas consumption.

The Company enters into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars. Swap contracts are designed to provide a fixed price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price.

The Company enters into these transactions with respect to a portion of its projected production to provide an economic hedge of the risk related to the future commodity prices received. The Company does not enter into derivative contracts for trading purposes. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

The following table summarizes derivative positions for the periods indicated as of December 31, 2013:



	2014		2015
Oil positions:
Fixed price swaps (NYMEX WTI):
Hedged volume (MBbls)	4,928		—
Average price ($/Bbl)	$	91.26	$	—
Collars (NYMEX WTI):
Hedged volume (MBbls)	730		—
Average floor price ($/Bbl)	$	90.00	$	—
Average ceiling price ($/Bbl)	$	102.87	$	—
Three-way collars (NYMEX WTI):
Hedged volume (MBbls)	3,103		1,095
Short put ($/Bbl)	$	72.11	$	70.00
Long put ($/Bbl)	$	93.76	$	90.00
Short call ($/Bbl)	$	109.79	$	101.62
Three-way collars (ICE Brent):
Hedged volume (MBbls)	365		—
Short put ($/Bbl)	$	80.00	$	—
Long put ($/Bbl)	$	100.00	$	—
Short call ($/Bbl)	$	114.05	$	—
Oil basis differential positions:
ICE Brent - NYMEX WTI basis swaps:
Hedged volume (MBbls)	3,650		2,920
Hedged differential ($/Bbl)	$	11.60	$	11.60
Oil timing differential positions:
Trade month roll swaps (NYMEX WTI): ⁽¹⁾
Hedged volume (MBbls)	1,825		—
Hedged differential ($/Bbl)	$	0.32	$	—

⁽¹⁾

The Company hedges the timing risk associated with the sales price of oil in the Permian Basin. In this operating area, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

During the year ended December 31, 2013, the Company entered into commodity derivative contracts consisting of oil three-way collars for 2013 through 2014, oil trade month roll swaps, oil collars and oil swaps for 2014 and oil basis swaps for 2013 through 2015. These derivative positions are included in the summary table above.

Balance Sheet Presentation

The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis (in thousands):



	Successor		Predecessor
	December 31, 2013		December 31, 2012
Assets:
Commodity derivatives	$	28,291	$	27,277
Liabilities:
Commodity derivatives	$	45,226	$	4,075

By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $28 million at December 31, 2013. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

Gains (Losses) on Derivatives

Gains (losses) on oil and natural gas derivatives were net losses of approximately $5 million and $35 million for the periods from December 17, 2013, through December 31, 2013, and from January 1, 2013, through December 16, 2013, respectively, and net gains of approximately $65 million and $14 million for the years ended December 31, 2012, and December 31, 2011, respectively. These amounts are reported on the statements of operations in “gains (losses) on oil and natural gas derivatives.”

Discontinuance of Hedge Accounting

In 2010, the Company elected to de-designate all of its derivatives contracts that had been previously designated as cash flow hedges. As a result of discontinuing hedge accounting, the fair values of the Company's open derivative instruments designated as cash flow hedges, less any ineffectiveness recognized, were frozen in AOCL and reclassified into earnings as the original hedge transactions settled. For the year ended December 31, 2012, a loss of approximately $11 million and a gain of approximately $2 million of noncash amortization of AOCL related to discontinuing hedge accounting were reclassified from AOCL to oil, natural gas and NGL sales and interest expense, respectively. For the year ended December 31, 2011, losses of approximately $61 million and $1 million were reclassified from AOCL to oil, natural gas and NGL sales and interest expense, respectively. At December 31, 2012, the entire balance of AOCL had been reclassified into earnings.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 30
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 815
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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+ Details

Fair Value Measurements on a Recurring Basis

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements on a Recurring Basis

The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives.

Fair Value Hierarchy

In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Financial assets and liabilities recorded in the balance sheets are categorized based on the inputs to the valuation techniques as follows:


Level 1	Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.


Level 2	Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives and interest rate swaps).


Level 3	Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.

The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:



	Successor
	December 31, 2013
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	28,291	$	(20,184	)	$	8,107
Liabilities:
Commodity derivatives	$	45,226	$	(20,184	)	$	25,042



	Predecessor
	December 31, 2012
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	27,277	$	(1,725	)	$	25,552
Liabilities:
Commodity derivatives	$	4,075	$	(1,725	)	$	2,350


⁽¹⁾	Represents counterparty netting under agreements governing such derivatives.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Operating Leases and Other Commitments

The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2020. The Company recognized expense under operating leases of approximately $302,000, $5 million, $3 million and $3 million for the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011, respectively.

The table below shows the Company’s future minimum payments under noncancelable operating leases and other commitments as of December 31, 2013:



(in millions)	Total		2014		2015		2016		2017		2018		Thereafter
Operating leases⁽¹⁾	$	21	$	6	$	5	$	4	$	2	$	2	$	2
Other commitments ⁽²⁾	16		11		3		2		—		—		—
Firm natural gas transportation contracts⁽³⁾	214		34		34		33		33		24		56
Total	$	251	$	51	$	42	$	39	$	35	$	26	$	58


⁽¹⁾	Operating leases relate primarily to obligations associated with the Company’s office facilities, vehicles, rail cars and aircraft.


⁽²⁾	Other commitments relate primarily to cogeneration facility management services and equipment purchase obligations.


⁽³⁾	The Company enters into certain firm commitments to transport natural gas production to market and to transport natural gas for use in the Company’s cogeneration and conventional steam generation facilities. The remaining terms of these contracts range from approximately one to nine years and require a minimum monthly charge regardless of whether the contracted capacity is used or not.

East Texas Gathering System

The Company has entered into certain long-term natural gas gathering agreements for east Texas production containing embedded leases. The transaction has been accounted for as a financing obligation. The fair value of the property associated with this transaction is approximately $13 million and is being depreciated over the remaining useful life of the asset. Under the agreements, portions of the payments are recorded as gathering expense and interest expense with the balance recorded as a reduction to the financing obligation. There are no minimum payments required under these agreements.

Carry and Earning Agreement

In January 2011, the Company entered into an amendment relating to certain contractual obligations to a third-party co-owner of certain Piceance Basin assets in Colorado. The amendment waives a $200,000 penalty for each well not spud by February 2011 and requires the Company to reassign to such co-owner, by January 31, 2020, all of the interest acquired by the Company from the co-owner in each 160-acre tract in which the Company has not drilled and completed a well that is producing or capable of producing from a designated formation, or deeper formation, on January 1, 2020. The amendment also requires the Company to pay the first $9 million of costs incurred in connection with the construction of either an extension of the existing access road or a new access road, including the third party’s 50% share. Pursuant to the terms of a further amendment effective June 2013, if by September 30, 2014, the Company does not expend $9 million on the construction of either the extension of the road or a new road, the Company is obligated to pay the third party 50% of the difference between $12 million and the actual amount expended on road construction as of such date. This deadline is subject to further extension to no later than December 31, 2014 under the terms of the amendment; however, negotiations are currently underway to obtain an extension beyond this date. Due to the need to obtain regulatory approvals, among other reasons, the Company has not yet commenced construction of either an extension of the existing access road or a new access road and may be unable to do so by the extended deadline, thus triggering the payment obligation to the third party.

Environmental Matters

The Company has no material accrued environmental liabilities for its sites, including sites in which governmental agencies have designated the Company as a potentially responsible party, because it is not probable that a loss will be incurred and the minimum cost and/or amount of loss cannot be reasonably estimated. However, because of the uncertainties associated with environmental assessment and remediation activities, future expense to remediate the currently identified sites, and sites identified in the future, if any, could be incurred. Management believes, based upon current site assessments, that the ultimate resolution of any matters will not result in material costs incurred.

Legal Matters

Department of the Interior Notice of Proposed Debarment

On June 14, 2012, the Company received a Notice of Proposed Debarment issued by the United States Department of the Interior (DOI). Pursuant to the notice, the DOI’s Office of the Inspector General proposed to debar the Company from participation in certain federal contracts and assistance activities, including oil and natural gas leases, for a period of three years. The basis for the proposed debarment relates to the Company’s purported noncompliance with Bureau of Land Management (BLM) regulations relating to the operation of certain equipment, and the submission of related site facility diagrams, in its Uinta operations. In 2011, the Company entered into a settlement agreement with the BLM and paid a $2 million civil penalty relating to the matter. The Company contested the proposed debarment and believes the matter is without merit; nevertheless, in June 2013, the Company entered into an agreement with the DOI to resolve the matter administratively through an independent compliance review. The independent compliance review has concluded and the final compliance review reports have been submitted to the DOI. The Company has been informed that DOI intends to make follow-up inquiries to the Company in the near future, but has not received any further communications to date.

Other

The Company is involved in various other lawsuits, claims and inquiries, most of which are routine to the nature of its business. In the opinion of management, the resolution of these matters will not have a material effect on its financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

Other Property and Equipment

12 Months Ended

Dec. 31, 2013

Oil and Gas Properties, Buildings and Equipment [Abstract]

Oil and Gas Properties, Buildings and Equipment

Other Property and Equipment

Other property and equipment consists of the following:



	Successor			Predecessor
(in thousands)	December 31, 2013			December 31, 2012
Plant and pipeline, drilling and other equipment	$	74,155		$	18,131
Buildings and leasehold improvements	6,515			10,110
Vehicles	2,456			9,167
	83,126			37,408
Less accumulated depreciation	(233		)	(25,340		)
	$	82,893		$	12,068

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other accrued liabilities” and “other noncurrent liabilities” on the balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the 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 presents a reconciliation of the Company’s asset retirement obligations:



	Successor		Predecessor
(in thousands)	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			Year Ended December 31, 2012
Asset retirement obligations at beginning of year ⁽¹⁾	$	94,612	$	86,746		$	64,019
Liabilities added from drilling	—		10,097			7,249
Settlements	—		(3,882		)	(3,325		)
Liabilities added from acquisitions	—		—			2,651
Liabilities associated with assets sold	—		(40		)	(705		)
Current year accretion expense	218		7,136			5,858
Revisions of estimates	—		5,900			10,999
Asset retirement obligations at end of year	$	94,830	$	105,957		$	86,746


⁽¹⁾	As a result of the application of pushdown accounting, the Company remeasured its asset retirement obligations on the LINN Energy transaction date.

Related Party Transactions (Notes)	12 Months Ended
Related Party Transactions (Notes)	Dec. 31, 2013
Related Party Transactions [Abstract]
Related Party Transactions Disclosure	Related Party Transactions On December 16, 2013, the Company completed the previously-announced transactions contemplated by the merger agreement between LINN Energy, LinnCo, an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and LINN Energy, under which LinnCo contributed Berry to LINN Energy in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. Berry’s sole member is Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy. See Note 2 for more information. On December 19, 2013, the Company distributed $435 million to LINN Energy. In connection with the LINN Energy transaction, LOI transferred a derivative liability of approximately $31 million to the Company. The Company also has affiliated accounts payable of approximately $17 million due to LOI primarily related to severance payments made by LOI on behalf of Berry to former Berry employees incurred in connection with the LINN Energy transaction. The Company’s $205 million of June 2014 Senior Notes matures on June 1, 2014. In March 2014, the Company and LINN Energy entered into a parent support agreement under which LINN Energy agreed to provide the Company with funds in an amount sufficient to enable the Company to pay the Company’s June 2014 Senior Notes in full upon maturity.

- Definition

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References + Details

Supplemental Oil & Natural Gas Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Information about Oil & Gas Producing Activities (Unaudited)

BERRY PETROLEUM COMPANY, LLC

SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited)

The following discussion and analysis should be read in conjunction with the “Financial Statements” and “Notes to 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:



	Successor		Predecessor
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31,
(in thousands)	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		2012		2011
Property acquisition costs:
Proved	$	—	$	3,457	$	70,700	$	149,158
Unproved	—		463		10,686		6,632
Exploration costs	—		868		16,405		627
Development costs	22,266		577,568		696,095		536,666
Asset retirement costs	—		15,998		18,248		7,448
Total costs incurred ⁽¹⁾	$	22,266	$	598,354	$	812,134	$	700,531


⁽¹⁾	The total above does not reflect approximately $41,000, $6 million, $18 million and $29 million of capitalized interest incurred for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the years ended December 31, 2012, December 31, 2011, respectively.

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:



	Successor			Predecessor
(in thousands)	December 31, 2013			December 31, 2012
Oil and natural gas:
Proved properties	$	3,397,785		$	4,060,106
Unproved properties	1,415,874			236,626
	4,813,659			4,296,732
Less accumulated depletion and amortization	(10,394		)	(1,180,298		)
	$	4,803,265		$	3,116,434

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:



	Successor			Predecessor
	December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013			Year Ended December 31,
	December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013			2012			2011
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	50,324		$	1,103,245		$	937,261		$	870,773
Gains (losses) on oil and natural gas derivatives	(5,049		)	(34,711		)	64,620			13,908
	45,275			1,068,534			1,001,881			884,681
Production costs:
Lease operating expenses	15,410			325,209			243,173			215,854
Transportation expenses	2,576			32,930			28,624			21,442
Severance and ad valorem taxes	2,130			41,509			39,374			33,617
	20,116			399,648			311,171			270,913
Other costs:
Exploration costs	—			24,048			21,010			1,794
Depletion and amortization	10,612			275,927			224,836			212,125
Impairment of long-lived assets	—			—			—			629,252
(Gains) losses on sale of assets and other, net	10,208			(23		)	(1,782		)	(1,046		)
	20,820			299,952			244,064			842,125
Income tax expense (benefit)	—			65,280			88,121			(142,228		)
Results of operations	$	4,339		$	303,654		$	358,525		$	(86,129	)

There is no federal tax provision included in the results above for the period from December 17, 2013, through December 31, 2013, because the Company was not subject to federal income taxes during that period. See Note 4 for additional information about income taxes.

Proved Oil, Natural Gas and NGL Reserves

The proved reserves of oil and natural gas of the Company have been prepared by the independent engineering firm, DeGolyer and MacNaughton. In accordance with SEC regulations, reserves at December 31, 2013, December 31, 2012, and December 31, 2011, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the U.S., is shown below:



	Successor						Predecessor
	December 17, 2013 through December 31, 2013						January 1, 2013 through December 16, 2013
	Oil MBOE		Natural Gas MMcf		Total MBOE		Oil MBOE		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of period	187,892		280,943		234,715		204,208		425,519		275,129
Revisions of previous estimates	—		—		—		(13,536	)	(153,330	)	(39,092	)
Extensions, discoveries and other additions	—		—		—		10,955		29,756		15,913
Sales of minerals in place	—		—		—		(2,263	)	(3,071	)	(2,775	)
Production	(530	)	(826	)	(667	)	(11,472	)	(17,931	)	(14,460	)
End of period	187,362		280,117		234,048		187,892		280,943		234,715

Proved developed reserves	121,694		202,798		155,494		122,224		203,624		156,161
Proved undeveloped reserves	65,668		77,319		78,554		65,668		77,319		78,554
Total proved reserves	187,362		280,117		234,048		187,892		280,943		234,715



	Predecessor
	Year Ended December 31, 2012						Year Ended December 31, 2011
	Oil MBOE		Natural Gas MMcf		Total MBOE		Oil MBOE		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of year	185,880		534,279		274,926		166,181		630,192		271,213
Revisions of previous estimates	12,145		(205,845	)	(22,162	)	(4,054	)	(146,349	)	(28,446	)
Extensions, discoveries and other additions	8,459		100,129		25,148		19,601		65,992		30,600
Purchase of minerals in place	8,304		16,740		11,094		13,193		8,351		14,584
Sales of minerals in place	(556	)	—		(556	)	—		—		—
Production	(10,024	)	(19,784	)	(13,321	)	(9,041	)	(23,907	)	(13,025	)
End of year	204,208		425,519		275,129		185,880		534,279		274,926

Proved developed reserves	118,937		187,668		150,216		107,849		221,606		144,783
Proved undeveloped reserves	85,271		237,851		124,913		78,031		312,673		130,143
Total proved reserves	204,208		425,519		275,129		185,880		534,279		274,926

The tables above include changes in estimated quantities of natural gas reserves shown in BOE equivalents at a rate of six Mcf per one barrel.

Proved reserves decreased by approximately 667 MBOE to approximately 234,048 MBOE at December 31, 2013, from 234,715 MBOE at December 16, 2013, due to production during the successor period.

Proved reserves decreased by approximately 40,414 MBOE to approximately 234,715 MBOE at December 16, 2013, from 275,129 MBOE at December 31, 2012. The period from January 1, 2013, through December 16, 2013, includes 39,092 MBOE of negative revisions of previous estimates, due primarily to the SEC five-year development limitation on PUDs. During the period from January 1, 2013, through December 16, 2013, two sales in the Permian Basin operating area decreased proved reserves by approximately 2,775 MBOE. In addition, extensions and discoveries, primarily from 340 productive wells drilled during the period, contributed approximately 15,913 MBOE to the increase in proved reserves.

Proved reserves increased by approximately 203 MBOE to approximately 275,129 MBOE for the year ended December 31, 2012, from 274,926 MBOE for the year ended December 31, 2011. The year ended December 31, 2012, includes 22,162 MBOE of negative revisions of previous estimates, primarily in the Piceance Basin and East Texas due to the SEC five-year development limitation on PUDs and pricing, offset by positive revisions due to development drilling in Diatomite, McKittrick, and the Permian Basin. During the year ended December 31, 2012, the Company acquired reserves of approximately 11,094 MBOE primarily in Utah and the Permian Basin, and the sale of its Nevada Assets (see Note 2) decreased proved reserves by approximately 556 MBOE. In addition, extensions and discoveries, primarily from 467 productive wells drilled during the year, contributed approximately 25,148 MBOE to the increase in proved reserves.

Proved reserves increased by approximately 3,713 MBOE to approximately 274,926 MBOE for the year ended December 31, 2011, from 271,213 MBOE for the year ended December 31, 2010. The year ended December 31, 2011, includes 28,446 MBOE of negative revisions of previous estimates, due primarily to the SEC five-year development limitation on PUDs and negative performance revisions. During the year ended December 31, 2011, the Company acquired reserves of approximately 14,584 MBOE primarily in the Wolfberry trend in the Permian Basin (see Note 2). In addition, extensions and discoveries, primarily from 404 productive wells drilled during the year, contributed approximately 30,600 MBOE to the increase in proved reserves.

Standardized Measure of Discounted Future Net Cash Flows

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 at December 31, 2013, because the Company is not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts are not material. Prior to the LINN Energy transaction, the Company was a Subchapter C-corporation subject to federal and state income taxes. Future income tax expenses at December 31, 2012, and December 31, 2011, were computed by applying the appropriate year-end statutory income tax rates to the estimated future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax bases of the properties involved. The future income tax expenses gave effect to income tax deductions, credits and allowances relating to the proved oil and natural gas reserves.



	Successor			Predecessor
(in thousands)	December 31, 2013			December 31, 2012			December 31, 2011
Future estimated revenues	$	17,863,984		$	19,738,729		$	19,568,628
Future estimated production costs	(6,654,536		)	(5,884,891		)	(5,226,044		)
Future estimated development costs	(1,854,849		)	(2,164,780		)	(1,975,429		)
Future estimated income tax expense	—			(3,344,024		)	(3,770,512		)
Future net cash flows	9,354,599			8,345,034			8,596,643
10% annual discount for estimated timing of cash flows	(4,719,267		)	(4,511,619		)	(4,561,364		)
Standardized measure of discounted future net cash flows	$	4,635,332		$	3,833,415		$	4,035,279

Representative NYMEX prices:⁽¹⁾
Oil (Bbl)	$	96.89		$	90.66		$	93.72
Natural gas (MMBtu)	$	3.67		$	2.88		$	4.02


⁽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 summarizes the principal sources of change in the standardized measure of discounted future net cash flows:



	Successor			Predecessor
(in thousands)	December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013
Standardized measure—beginning of period	$	3,558,595		$	3,833,415
Sales and transfers of oil, natural gas, and NGL produced during the period	(30,208		)	(703,597		)
Changes in estimated future development costs	—			20,932
Net change in sales and transfer prices and production costs related to future production	(1,272		)	(214,489		)
Extensions, discoveries and improved recovery	—			189,625
Sales of minerals in place	—			(13,279		)
Previously estimated development costs incurred during the period	—			401,791
Net change due to revisions in quantity estimates	—			(856,118		)
Accretion of discount	19,184			496,718
Income taxes	1,109,522			237,117
Changes in production rates and other	(20,489		)	166,480
Net increase (decrease)	1,076,737			(274,820		)
Standardized measure—end of period	$	4,635,332		$	3,558,595



	Predecessor
(in thousands)	December 31, 2012			December 31, 2011
Standardized measure—beginning of year	$	4,035,279		$	2,799,156
Sales and transfers of oil, natural gas, and NGL produced during the period	(625,707		)	(599,679		)
Changes in estimated future development costs	(331,498		)	(274,122		)
Net change in sales and transfer prices and production costs related to future production	(786,022		)	1,473,454
Extensions, discoveries and improved recovery	124,466			601,313
Purchases of minerals in place	114,094			164,383
Sales of minerals in place	(15,283		)	—
Previously estimated development costs incurred during the period	497,036			433,660
Net change due to revisions in quantity estimates	743			(281,765		)
Accretion of discount	570,505			383,418
Income taxes	323,128			(634,747		)
Changes in production rates and other	(73,326		)	(29,792		)
Net increase (decrease)	(201,864		)	1,236,123
Standardized measure—end of year	$	3,833,415		$	4,035,279

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited)

Quarterly Financial Data



	Predecessor											Successor
	Periods Ended											Period Ended
(in thousands)	March 31			June 30		September 30			October 1, 2013 through December 16, 2013			December 17, 2013 through December 31, 2013
2013
Oil, natural gas and natural gas liquids sales	$	266,772		$	274,715	$	306,183		$	255,575		$	50,324
Electricity sales	7,589			9,513		10,046			6,844			1,444
Gains (losses) on oil and natural gas derivatives	(737		)	35,622		(45,293		)	(24,303		)	(5,049		)
Total revenues and other, net	276,123			322,338		273,014			239,827			47,118
Total expenses ⁽¹⁾	198,239			201,331		202,647			254,305			52,892
(Gains) losses on sales of assets and other, net	(23		)	—		—			—			10,208
Net income (loss)	32,434			61,364		28,178			(28,529		)	(19,973		)



	Predecessor
	Quarters Ended
(in thousands)	March 31			June 30		September 30			December 31⁽¹⁾
2012
Oil, natural gas and natural gas liquids sales	$	233,653		$	221,781	$	232,916		$	248,911
Electricity sales	5,980			5,860		9,514			8,586
Gains (losses) on oil and natural gas derivatives	(28,481		)	113,082		(28,287		)	8,306
Total revenues and other, net	213,629			342,790		216,352			268,355
Total expenses ⁽¹⁾	140,876			149,760		166,749			201,291
(Gains) losses on sales of assets and other, net	(1,763		)	163		(170		)	(12		)
Net income (loss)	33,898			81,016		18,126			38,499


⁽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 Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]
Predecessor and Successor Reporting	Predecessor and Successor Reporting The LINN Energy transaction was accounted for under the acquisition method of accounting. Under the acquisition method of accounting, LinnCo initially, and LINN Energy upon the contribution was treated as the accounting acquirer and Berry was treated as the acquired company for financial reporting purposes. As such, the assets and liabilities of the Company were provisionally recorded at their respective fair values as of the acquisition date. Fair value adjustments related to the transaction have been pushed down to Berry, resulting in assets and liabilities of the Company being recorded at fair value at December 16, 2013. See Note 2 for additional information. The Company’s statement of operations subsequent to the transaction includes depreciation, depletion and amortization expense on the Company’s oil and natural gas properties, and other property and equipment balances resulting from the fair value adjustments made under the new basis of accounting. Certain other items of income and expense were also impacted. Therefore, the Company’s financial information prior to the transaction is not comparable to its financial information subsequent to the transaction. As a result of the impact of pushdown accounting, the financial statements and certain note presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the transaction (labeled predecessor) and the period after that date (labeled successor), to indicate the application of different basis of accounting between the periods presented.
Income Taxes	Income Taxes and Uncertain Tax Positions The successor Company is a limited liability company treated as a disregarded entity 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 members. As such, with the exception of the state of Texas, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company. Prior to the LINN Energy transaction on December 16, 2013, the Company was a Subchapter C-corporation. For predecessor periods prior to December 16, 2013, income taxes were recorded for the income tax effects of transactions reported in the financial statements and consist of income taxes payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income taxes were also recognized for income tax credits that were available to offset future income taxes. Deferred income taxes were measured by applying currently enacted income tax rates to the differences between the financial statements and income tax reporting. The Company routinely assessed the realizability of its deferred income tax assets, and a valuation allowance was recognized if it was determined that deferred income tax assets may not be fully utilized in future periods. The Company considered future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). The predecessor Company was subject to taxation in many jurisdictions, and the calculation of its income tax liabilities involved dealing with uncertainties in the application of complex income tax laws and regulations in various taxing jurisdictions. The Company recognized certain income tax positions that met a more-likely-than not recognition threshold. If the Company ultimately determined that the payment of these liabilities would be unnecessary, the Company reversed the liability and recognized an income tax benefit during the period in which the Company determined the liability no longer applied.
Derivative Instruments	Derivative Instruments The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil and, from time to time, natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. These transactions are primarily in the form of swap contracts, collars and three-way collars. Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the balance sheets as assets or liabilities. In January 2010, the Company elected to prospectively discontinue all hedge accounting, under which changes in derivative fair values were deferred in accumulated other comprehensive loss (“AOCL”). After January 2010, the Company no longer designated these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.
Fair Value of Financial Instruments	Fair Value of Financial Instruments The carrying values of the Company’s receivables, payables and Credit Facility are estimated to be substantially the same as their fair values at December 31, 2013, and December 31, 2012. See Note 3 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.
Inventories	Inventories Materials, supplies and commodity inventories are valued at the lower of average cost or market. Inventories also include California carbon allowance instruments.
Business Description and Basis of Presentation	Nature of Business Berry Petroleum Company, LLC (“Berry” or the “Company”) was formed as a Delaware limited liability company on December 16, 2013, and is an indirect wholly owned subsidiary of Linn Energy, LLC (“LINN Energy”) engaged in the production and development of oil and natural gas. The Company’s predecessor, Berry Petroleum Company, was publicly traded from 1987 until being acquired by LINN Energy on December 16, 2013 (see “LINN Energy Transaction” below and Note 2). As of December 31, 2013, Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, is the Company’s sole member. The Company’s properties are located in the United States (“U.S.”). Prior to the LINN Energy transaction, the Company had seven asset teams as follows: South Midway-Sunset (“SMWSS”)—Steam Floods, North Midway-Sunset (“NMWSS”)—Diatomite, NMWSS—New Steam Floods (“NSF”), Permian Basin, Uinta Basin, East Texas and Piceance Basin. Effective December 16, 2013, the Company realigned its existing asset teams into operating areas. The realignment had no effect on the Company’s operations. The Company currently has five operating areas in the U.S.: California, which includes SMWSS—Steam Floods, NMWSS—Diatomite and NMWSS—NSF, Permian Basin, Uinta Basin, East Texas and Piceance Basin. The operations of the Company are governed by the provisions of a limited liability company agreement executed by its member. Pursuant to applicable provisions of the Delaware Limited Liability Company Act (the “Delaware Act”) and the Limited Liability Company Agreement of Berry Petroleum Company, LLC (the “Agreement”), the member has no liability for the debts, obligations and liabilities of the Company, except as expressly required in the Agreement or the Delaware Act. The Company will remain in existence unless and until dissolved in accordance with the terms of the Agreement. LINN Energy Transaction On December 16, 2013, the Company completed the previously-announced transactions contemplated by the merger agreement between LINN Energy, LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, and Berry under which LinnCo acquired all of the outstanding common shares of Berry and the contribution agreement between LinnCo and LINN Energy, under which LinnCo contributed Berry to LINN Energy in exchange for LINN Energy units. Under the merger agreement, as amended, Berry’s shareholders received 1.68 LinnCo common shares for each Berry common share they owned, totaling 93,756,674 LinnCo common shares. Under the contribution agreement, LinnCo contributed Berry to LINN Energy in exchange for 93,756,674 newly issued LINN Energy units, after which Berry became an indirect wholly owned subsidiary of LINN Energy. Basis of Presentation The Company presents its financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. The financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss), shareholders' equity or cash flows.
Use of Estimates	Use of Estimates The preparation of the accompanying financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. Actual results could differ from these estimates. Any changes in estimates resulting from continuous changes in the economic environment will be reflected in the financial statements in future periods.
Cash Equivalents	Cash Equivalents For purposes of the 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.”
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 $473,000 and $414,000 at December 31, 2013 (successor), and December 31, 2012 (predecessor), respectively.
Oil and Natural Gas Properties	Oil and Natural Gas Properties Proved Properties The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $41,000, $6 million, $18 million and $29 million for the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011, respectively. Impairment of Proved Properties Based on the analysis described above, the Company recorded no impairment charges for the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, or for the year ended December 31, 2012. For the year ended December 31, 2011, the Company recorded a noncash impairment charge of approximately $625 million related to its East Texas natural gas properties primarily due to decreases in natural gas prices. The carrying value of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. Impairment charges are included in “impairment of long-lived assets” on the statements of operations. Unproved Properties Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. The fair values of unproved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of unproved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties, and the relative proportion of such properties on which proved reserves have been found in the past. Exploration Costs Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves (“dry hole expense”) 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 exploration costs during the period from December 17, 2013, through December 31, 2013. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $16 million, $79,000 and $589,000 for the period from January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, December 31, 2011, respectively.
Impairment of Proved Properties	Impairment of Proved Properties Based on the analysis described above, the Company recorded no impairment charges for the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, or for the year ended December 31, 2012. For the year ended December 31, 2011, the Company recorded a noncash impairment charge of approximately $625 million related to its East Texas natural gas properties primarily due to decreases in natural gas prices. The carrying value of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. Impairment charges are included in “impairment of long-lived assets” on the statements of operations.
Other Property and Equipment	Other Property and Equipment Other property and equipment includes natural gas gathering systems, pipelines, buildings, software, data processing and telecommunications equipment, office furniture and equipment, and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from ten to 25 years for buildings and leasehold improvements and two to 30 years for plant and pipeline, drilling and other equipment.
Deferred Financing Costs	Deferred Financing Fees The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2013, and December 31, 2012, net deferred financing fees of approximately $5 million and $27 million, respectively, are included in “other noncurrent assets” on the balance sheets. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense. For the periods from December 17, 2013, through December 31, 2013, and January 1, 2013, through December 16, 2013, and for the years ended December 31, 2012, and December 31, 2011, amortization expense of approximately $83,000, $5 million, $5 million and $11 million, respectively, is included in “interest expense, net of amounts capitalized.”
Revenue Recognition	Revenue Recognition Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the 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 electricity and natural gas the Company produces and uses in its operations are not included in revenues. The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing sales and marketing expenses.
Electricity Cost Allocation	Electricity Cost Allocation The Company owns three cogeneration facilities. Its investment in cogeneration facilities has been for the express purpose of lowering steam costs in its heavy oil operations in California and securing operating control of the respective steam generation. Cogeneration, also called combined heat and power (“CHP”), extracts energy from the exhaust of a turbine, which would otherwise be wasted, to produce steam. Such cogeneration operations also produce electricity. The Company allocates steam costs to lease operating expenses based on the conversion efficiency of the cogeneration facilities plus certain direct costs in producing steam. A portion of the costs of operating the cogeneration facilities is also allocated to depreciation, depletion and amortization. Electricity revenue represents sales to utilities.
Share-based Compensation	Stock-Based Compensation The successor Company does not have any equity incentive plans under which it grants stock awards. Prior to the LINN Energy transaction, the Company granted equity awards to its employees under its own equity incentive plans. The predecessor Company recognized stock-based compensation expense over the requisite service period in an amount equal to the fair value of stock-based awards granted to employees and nonemployee directors. The fair value of stock-based awards was computed at the date of grant and was not remeasured.
Concentration Risk Disclosure	Business and Credit Concentrations The Company maintains its cash in bank deposit accounts which at times may exceed federally insured amounts. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on its cash. The Company sells oil and natural gas to various types of customers, including pipelines, refineries and other oil and natural gas companies, and electricity to utility companies. Based on the current demand for oil and natural gas and the availability of other purchasers, the Company believes that, with the exception of its primary customer in Utah, the loss of any one of its major purchasers would not have a material adverse effect on its financial condition, results of operations and net cash provided by operating activities. For the period from December 17, 2013, through December 31, 2013, the Company’s two largest customers represented approximately 50% and 10%, respectively, of the Company’s oil, natural gas and NGL sales. For the period from January 1, 2013, through December 16, 2013, the Company’s two largest customers represented approximately 45% and 10%, respectively, of the Company’s oil, natural gas and NGL sales. For the year ended December 31, 2012, the Company’s two largest customers represented approximately 43% and 13%, respectively, of the Company’s oil, natural gas and NGL sales. For the year ended December 31, 2011, the Company’s two largest customers represented approximately 43% and 14%, respectively, of the Company’s oil, natural and NGL gas sales. For the years ended December 31, 2013, December 31, 2012, and December 31, 2011, 100% of electricity sales were attributable to two customers. At December 31, 2013, trade accounts receivable from one customer represented approximately 48% of the Company’s receivables. At December 31, 2012, trade accounts receivable from two customers represented approximately 43% and 13% of the Company’s receivables.

Basis of Presentation and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Supplemental Cash Flow Disclosures



	Successor		Predecessor
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31,
(in thousands)	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		2012		2011
Cash payments for interest, net of amounts capitalized	$	—	$	87,495	$	64,602	$	59,853
Cash payments for income taxes	$	—	$	622	$	4,227	$	7,914
Noncash investing activities:
Accrued capital expenditures	$	4,788	$	70,866	$	98,020	$	61,098
Asset retirement obligations	$	—	$	15,998	$	18,248	$	7,448

Other Current Assets



	Successor		Predecessor
(in thousands)	December 31, 2013		December 31, 2012
Short-term investments	$	—	$	125
Prepaid expenses	3,652		4,168
California carbon allowance inventories	15,895		545
Oil inventories	7,436		1,216
Materials inventories	3,036		12,943
Other	814		193
Other current assets	$	30,833	$	19,190

Other Accrued Liabilities



	Successor		Predecessor
(in thousands)	December 31, 2013		December 31, 2012
Accrued interest	$	18,926	$	16,996
Accrued compensation	6,749		12,700
Asset retirement obligations (current portion)	3,318		4,430
Other	—		1,695
Other accrued liabilities	$	28,993	$	35,821

LINN Energy Merger, Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2013

LINN Energy Merger, Acquisitions, and Divestitures

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]



Assets:
Cash	$	451,113
Current	249,564
Noncurrent	97,202
Oil and natural gas properties	4,791,394
Total assets acquired	5,589,273

Liabilities:
Current	310,105
Noncurrent	100,809
Asset retirement obligations, current and noncurrent	94,612
Long-term debt, including current portion	2,301,859
Total liabilities assumed	2,807,385

Net assets acquired	$	2,781,888

Debt (Tables)

12 Months Ended

Dec. 31, 2013

Debt Instrument

Schedule of Long-term Debt Instruments [Table Text Block]



	Successor			Predecessor
(in millions, except percentages)	December 31, 2013			December 31, 2012
Credit facility ⁽¹⁾	$	1,173		$	563
10.25% senior notes due June 2014	205			205
6.75% senior notes due November 2020	300			300
6.375% senior notes due September 2022	600			600
Net unamortized discounts and premiums	23			(2		)
Total debt, net	2,301			1,666
Less current maturities	(211		)	—
Total long-term debt, net	$	2,090		$	1,666

Senior notes, expressed as percentage of principal amount redeemed, plus accured and unpaid interest, by maturity



2015	103.375	%
2016	102.250	%
2017	101.125	%
2018 and thereafter	100.000	%

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]



	Successor				Predecessor
	December 31, 2013				December 31, 2012
(in millions)	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit facility	$	1,173	$	1,173	$	563	$	563
Senior notes, net	1,128		1,129		1,103		1,179
Total debt, net	$	2,301	$	2,302	$	1,666	$	1,742

6.375% Senior notes due 2022

Debt Instrument

Senior notes, expressed as percentage of principal amount redeemed, plus accured and unpaid interest, by maturity



2017	103.188	%
2018	102.125	%
2019	101.063	%
2020 and thereafter	100.000	%

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

+ Details

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)



	Successor		Predecessor
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			Year Ended December 31,
(in thousands)	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			2012		2011
Current taxes:
Federal	$	—	$	(225	)	$	286	$	4,115
State	—		(11,043		)	4,954		2,936
Deferred taxes:
Federal	—		56,620			80,083		(125,261		)
State	—		19,928			2,798		(24,018		)
	$	—	$	65,280		$	88,121	$	(142,228	)

Schedule of Deferred Tax Assets and Liabilities



	Successor		Predecessor
(in thousands)	December 31, 2013		December 31, 2012
Deferred tax assets:
Federal benefit of state income taxes	$	—	$	(239	)
Credit carryforwards	—		36,028
Equity and deferred compensation	—		15,139
Net operating loss	—		412
Bad debt expense	—		163
Other, net	—		610
Valuation allowance	—		(1,201		)
	—		50,912
Deferred tax liabilities:
Depreciation and depletion	—		(298,659		)
Derivatives	—		(8,477		)
	—		(307,136		)

Net deferred tax liabilities	$	—	$	(256,224	)

Schedule of Effective Income Tax Rate Reconciliation



	Successor		Predecessor
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31,
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		2012		2011
Federal statutory rate	35	%	35	%	35	%	35	%
State, net of federal tax benefit	—		3		3		3
Loss excluded from nontaxable entities	(35	)	—		—		—
Deferred state rate impact	—		—		(1	)	—
Research and development credits	—		—		(3	)	—
Net impact to uncertain income tax positions	—		(2	)	—		1
Transaction costs	—		4		—		—
Other	—		1		—		(1	)
Effective rate	—	%	41	%	34	%	38	%

Summary of Income Tax Contingencies



	Successor		Predecessor
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			Year Ended December 31,
(in millions)	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			2012			2011
Unrecognized tax benefits at beginning of period	$	—	$	23		$	3		$	5
Increases (decreases) for positions taken in prior year	—		(1		)	21			—
Decreases for settlements with taxing authorities	—		—			—			(2		)
Decreases for lapses in the applicable statute of limitations	—		(2		)	(1		)	—
Unrecognized tax benefits at end of period	$	—	$	20		$	23		$	3

Equity Incentive Compensation Plans and Other Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of stock options or units activity



	Number of Shares		Weighted Average Exercise Price		Aggregate Intrinsic Value (in thousands) ⁽¹⁾		Weighted Average Remaining Contractual Term (Years)
Outstanding at January 1, 2011	2,017,225		$	25.87	$	35,974
Granted	89,865		48.50
Exercised	(579,636	)	17.47		17,746
Canceled/expired	(6,765	)	45.92
Outstanding at December 31, 2011	1,520,689		30.32		17,798
Granted	82,262		53.02
Exercised	(215,359	)	17.12		7,194
Outstanding at December 31, 2012	1,387,592		33.71		4,681
Exercised	(57,350	)	12.74		2,066
Outstanding at December 16, 2013	1,330,242		$	34.61	$	19,243	3.21
Vested and expected to vest at December 16, 2013	1,328,771		$	34.60	$	19,243	3.21
Exercisable at December 16, 2013	1,224,022		$	33.18	$	19,229	2.81


⁽¹⁾	The intrinsic value of a stock option is the amount by which the market value of the underlying stock at the end of the related period exceeds the exercise price of the option.

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions



	2012		2011
Expected volatility	50.00	%	45.00	%
Risk-free rate	0.95	%	2.54	%
Dividend yield	0.57	%	0.62	%
Expected term (in years)	5.2		6.0

Schedule of Range of Exercise Prices



	Stock Options Outstanding				Stock Options Exercisable
Range of Exercise Prices	Number of Options	Weighted Average Remaining Contractual Term (Years)	Weighted Average Exercise Price		Number of Options	Weighted Average Remaining Contractual Term (Years)	Weighted Average Exercise Price
$21.58-$21.77	240,000	0.90	$	21.60	240,000	0.90	$	21.60
$30.65-$32.57	639,000	2.50	31.70		639,000	2.50	31.70
$38.00-$53.02	451,242	5.43	45.66		345,022	4.71	43.98
	1,330,242	3.21	$	34.61	1,224,022	2.81	$	33.18

Summary of restricted stock units activity



	RSUs		Weighted Average Intrinsic Value at Grant Date		Vest Date Fair Value (in thousands)
Outstanding at January 1, 2011	857,360		$	19.67
Granted	159,333		47.98
Issued	(62,127	)	26.18		$	2,588
Canceled/expired	(39,544	)	25.12
December 31, 2011	915,022		$	23.88
Granted	164,112		50.60
Issued	(79,068	)	33.10		$	3,401
Canceled/expired	(18,189	)	41.50
December 31, 2012	981,877		$	26.72
Granted	286,344		45.51
Issued	(853,169	)	23.94		$	39,513
Canceled/expired	(22,511	)	44.69
Outstanding at December 16, 2013	392,541		$	46.86

Summary of performance share awards activity



	Performance Share Awards		Weighted Average Grant Date Fair Value		Vest Date Fair Value (in thousands)
Outstanding on January 1, 2011	103,794		$	31.20
Granted	65,620		51.86
Canceled/expired	(6,565	)	44.20
Outstanding at December 31, 2011	162,849		$	39.00
Granted	59,738		63.69
Outstanding at December 31, 2012	222,587		$	45.79
Issued	(135,167	)	44.33		$	6,308
Canceled/expired	(87,420	)	44.42
Outstanding at December 16, 2013	—		$	—

Schedule of Market Based Restricted Shares Using Monte Carlo Model Valuation Assumptions



	2012		2011
Number of simulations	100,000		100,000
Expected volatility	50	%	44	%
Risk-free rate	0.42	%	1.15	%

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of derivative instruments



	2014		2015
Oil positions:
Fixed price swaps (NYMEX WTI):
Hedged volume (MBbls)	4,928		—
Average price ($/Bbl)	$	91.26	$	—
Collars (NYMEX WTI):
Hedged volume (MBbls)	730		—
Average floor price ($/Bbl)	$	90.00	$	—
Average ceiling price ($/Bbl)	$	102.87	$	—
Three-way collars (NYMEX WTI):
Hedged volume (MBbls)	3,103		1,095
Short put ($/Bbl)	$	72.11	$	70.00
Long put ($/Bbl)	$	93.76	$	90.00
Short call ($/Bbl)	$	109.79	$	101.62
Three-way collars (ICE Brent):
Hedged volume (MBbls)	365		—
Short put ($/Bbl)	$	80.00	$	—
Long put ($/Bbl)	$	100.00	$	—
Short call ($/Bbl)	$	114.05	$	—
Oil basis differential positions:
ICE Brent - NYMEX WTI basis swaps:
Hedged volume (MBbls)	3,650		2,920
Hedged differential ($/Bbl)	$	11.60	$	11.60
Oil timing differential positions:
Trade month roll swaps (NYMEX WTI): ⁽¹⁾
Hedged volume (MBbls)	1,825		—
Hedged differential ($/Bbl)	$	0.32	$	—

Schedule of derivative assets and liabilities



	Successor		Predecessor
	December 31, 2013		December 31, 2012
Assets:
Commodity derivatives	$	28,291	$	27,277
Liabilities:
Commodity derivatives	$	45,226	$	4,075

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5579240-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41620-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurements on a Recurring Basis (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair value, assets measured on recurring and nonrecurring basis



	Successor
	December 31, 2013
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	28,291	$	(20,184	)	$	8,107
Liabilities:
Commodity derivatives	$	45,226	$	(20,184	)	$	25,042



	Predecessor
	December 31, 2012
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	27,277	$	(1,725	)	$	25,552
Liabilities:
Commodity derivatives	$	4,075	$	(1,725	)	$	2,350


⁽¹⁾	Represents counterparty netting under agreements governing such derivatives.

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Schedule of future minimum rental payments for operating leases



(in millions)	Total		2014		2015		2016		2017		2018		Thereafter
Operating leases⁽¹⁾	$	21	$	6	$	5	$	4	$	2	$	2	$	2
Other commitments ⁽²⁾	16		11		3		2		—		—		—
Firm natural gas transportation contracts⁽³⁾	214		34		34		33		33		24		56
Total	$	251	$	51	$	42	$	39	$	35	$	26	$	58

Other Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Oil and Gas Properties, Buildings and Equipment [Abstract]

Other Property and Equipment



	Successor			Predecessor
(in thousands)	December 31, 2013			December 31, 2012
Plant and pipeline, drilling and other equipment	$	74,155		$	18,131
Buildings and leasehold improvements	6,515			10,110
Vehicles	2,456			9,167
	83,126			37,408
Less accumulated depreciation	(233		)	(25,340		)
	$	82,893		$	12,068

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Summary of change in asset retirement obligations



	Successor		Predecessor
(in thousands)	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			Year Ended December 31, 2012
Asset retirement obligations at beginning of year ⁽¹⁾	$	94,612	$	86,746		$	64,019
Liabilities added from drilling	—		10,097			7,249
Settlements	—		(3,882		)	(3,325		)
Liabilities added from acquisitions	—		—			2,651
Liabilities associated with assets sold	—		(40		)	(705		)
Current year accretion expense	218		7,136			5,858
Revisions of estimates	—		5,900			10,999
Asset retirement obligations at end of year	$	94,830	$	105,957		$	86,746

Supplemental Oil & Natural Gas Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities



	Successor		Predecessor
	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31,
(in thousands)	December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		2012		2011
Property acquisition costs:
Proved	$	—	$	3,457	$	70,700	$	149,158
Unproved	—		463		10,686		6,632
Exploration costs	—		868		16,405		627
Development costs	22,266		577,568		696,095		536,666
Asset retirement costs	—		15,998		18,248		7,448
Total costs incurred ⁽¹⁾	$	22,266	$	598,354	$	812,134	$	700,531


⁽¹⁾	The total above does not reflect approximately $41,000, $6 million, $18 million and $29 million of capitalized interest incurred for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the years ended December 31, 2012, December 31, 2011, respectively.

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure



	Successor			Predecessor
(in thousands)	December 31, 2013			December 31, 2012
Oil and natural gas:
Proved properties	$	3,397,785		$	4,060,106
Unproved properties	1,415,874			236,626
	4,813,659			4,296,732
Less accumulated depletion and amortization	(10,394		)	(1,180,298		)
	$	4,803,265		$	3,116,434

Results of Operations for Oil and Gas Producing Activities Disclosure



	Successor			Predecessor
	December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013			Year Ended December 31,
	December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013			2012			2011
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	50,324		$	1,103,245		$	937,261		$	870,773
Gains (losses) on oil and natural gas derivatives	(5,049		)	(34,711		)	64,620			13,908
	45,275			1,068,534			1,001,881			884,681
Production costs:
Lease operating expenses	15,410			325,209			243,173			215,854
Transportation expenses	2,576			32,930			28,624			21,442
Severance and ad valorem taxes	2,130			41,509			39,374			33,617
	20,116			399,648			311,171			270,913
Other costs:
Exploration costs	—			24,048			21,010			1,794
Depletion and amortization	10,612			275,927			224,836			212,125
Impairment of long-lived assets	—			—			—			629,252
(Gains) losses on sale of assets and other, net	10,208			(23		)	(1,782		)	(1,046		)
	20,820			299,952			244,064			842,125
Income tax expense (benefit)	—			65,280			88,121			(142,228		)
Results of operations	$	4,339		$	303,654		$	358,525		$	(86,129	)

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities



	Successor						Predecessor
	December 17, 2013 through December 31, 2013						January 1, 2013 through December 16, 2013
	Oil MBOE		Natural Gas MMcf		Total MBOE		Oil MBOE		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of period	187,892		280,943		234,715		204,208		425,519		275,129
Revisions of previous estimates	—		—		—		(13,536	)	(153,330	)	(39,092	)
Extensions, discoveries and other additions	—		—		—		10,955		29,756		15,913
Sales of minerals in place	—		—		—		(2,263	)	(3,071	)	(2,775	)
Production	(530	)	(826	)	(667	)	(11,472	)	(17,931	)	(14,460	)
End of period	187,362		280,117		234,048		187,892		280,943		234,715

Proved developed reserves	121,694		202,798		155,494		122,224		203,624		156,161
Proved undeveloped reserves	65,668		77,319		78,554		65,668		77,319		78,554
Total proved reserves	187,362		280,117		234,048		187,892		280,943		234,715



	Predecessor
	Year Ended December 31, 2012						Year Ended December 31, 2011
	Oil MBOE		Natural Gas MMcf		Total MBOE		Oil MBOE		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of year	185,880		534,279		274,926		166,181		630,192		271,213
Revisions of previous estimates	12,145		(205,845	)	(22,162	)	(4,054	)	(146,349	)	(28,446	)
Extensions, discoveries and other additions	8,459		100,129		25,148		19,601		65,992		30,600
Purchase of minerals in place	8,304		16,740		11,094		13,193		8,351		14,584
Sales of minerals in place	(556	)	—		(556	)	—		—		—
Production	(10,024	)	(19,784	)	(13,321	)	(9,041	)	(23,907	)	(13,025	)
End of year	204,208		425,519		275,129		185,880		534,279		274,926

Proved developed reserves	118,937		187,668		150,216		107,849		221,606		144,783
Proved undeveloped reserves	85,271		237,851		124,913		78,031		312,673		130,143
Total proved reserves	204,208		425,519		275,129		185,880		534,279		274,926

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows



	Successor			Predecessor
(in thousands)	December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013
Standardized measure—beginning of period	$	3,558,595		$	3,833,415
Sales and transfers of oil, natural gas, and NGL produced during the period	(30,208		)	(703,597		)
Changes in estimated future development costs	—			20,932
Net change in sales and transfer prices and production costs related to future production	(1,272		)	(214,489		)
Extensions, discoveries and improved recovery	—			189,625
Sales of minerals in place	—			(13,279		)
Previously estimated development costs incurred during the period	—			401,791
Net change due to revisions in quantity estimates	—			(856,118		)
Accretion of discount	19,184			496,718
Income taxes	1,109,522			237,117
Changes in production rates and other	(20,489		)	166,480
Net increase (decrease)	1,076,737			(274,820		)
Standardized measure—end of period	$	4,635,332		$	3,558,595



	Predecessor
(in thousands)	December 31, 2012			December 31, 2011
Standardized measure—beginning of year	$	4,035,279		$	2,799,156
Sales and transfers of oil, natural gas, and NGL produced during the period	(625,707		)	(599,679		)
Changes in estimated future development costs	(331,498		)	(274,122		)
Net change in sales and transfer prices and production costs related to future production	(786,022		)	1,473,454
Extensions, discoveries and improved recovery	124,466			601,313
Purchases of minerals in place	114,094			164,383
Sales of minerals in place	(15,283		)	—
Previously estimated development costs incurred during the period	497,036			433,660
Net change due to revisions in quantity estimates	743			(281,765		)
Accretion of discount	570,505			383,418
Income taxes	323,128			(634,747		)
Changes in production rates and other	(73,326		)	(29,792		)
Net increase (decrease)	(201,864		)	1,236,123
Standardized measure—end of year	$	3,833,415		$	4,035,279

Schedule of Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves



	Successor			Predecessor
(in thousands)	December 31, 2013			December 31, 2012			December 31, 2011
Future estimated revenues	$	17,863,984		$	19,738,729		$	19,568,628
Future estimated production costs	(6,654,536		)	(5,884,891		)	(5,226,044		)
Future estimated development costs	(1,854,849		)	(2,164,780		)	(1,975,429		)
Future estimated income tax expense	—			(3,344,024		)	(3,770,512		)
Future net cash flows	9,354,599			8,345,034			8,596,643
10% annual discount for estimated timing of cash flows	(4,719,267		)	(4,511,619		)	(4,561,364		)
Standardized measure of discounted future net cash flows	$	4,635,332		$	3,833,415		$	4,035,279

Representative NYMEX prices:⁽¹⁾
Oil (Bbl)	$	96.89		$	90.66		$	93.72
Natural gas (MMBtu)	$	3.67		$	2.88		$	4.02


⁽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.

- Definition

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 27
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62352-109447

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 24
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62246-109447

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 23
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62136-109447

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
-URI http://asc.fasb.org/extlink&oid=27015464&loc=d3e511914-122862

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62259-109447

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62299-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62094-109447

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62395-109447

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (c)(3)
-URI http://asc.fasb.org/extlink&oid=6392692&loc=d3e7535-110849

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 55
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=8451751&loc=d3e63071-109448

+ Details

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details

- Definition

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

+ References + Details

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

Quarterly Financial Data



	Predecessor											Successor
	Periods Ended											Period Ended
(in thousands)	March 31			June 30		September 30			October 1, 2013 through December 16, 2013			December 17, 2013 through December 31, 2013
2013
Oil, natural gas and natural gas liquids sales	$	266,772		$	274,715	$	306,183		$	255,575		$	50,324
Electricity sales	7,589			9,513		10,046			6,844			1,444
Gains (losses) on oil and natural gas derivatives	(737		)	35,622		(45,293		)	(24,303		)	(5,049		)
Total revenues and other, net	276,123			322,338		273,014			239,827			47,118
Total expenses ⁽¹⁾	198,239			201,331		202,647			254,305			52,892
(Gains) losses on sales of assets and other, net	(23		)	—		—			—			10,208
Net income (loss)	32,434			61,364		28,178			(28,529		)	(19,973		)



	Predecessor
	Quarters Ended
(in thousands)	March 31			June 30		September 30			December 31⁽¹⁾
2012
Oil, natural gas and natural gas liquids sales	$	233,653		$	221,781	$	232,916		$	248,911
Electricity sales	5,980			5,860		9,514			8,586
Gains (losses) on oil and natural gas derivatives	(28,481		)	113,082		(28,287		)	8,306
Total revenues and other, net	213,629			342,790		216,352			268,355
Total expenses ⁽¹⁾	140,876			149,760		166,749			201,291
(Gains) losses on sales of assets and other, net	(1,763		)	163		(170		)	(12		)
Net income (loss)	33,898			81,016		18,126			38,499


⁽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 Significant Accounting Policies (Details)			12 Months Ended
	Dec. 31, 2013 USD ($)	Dec. 16, 2013 USD ($) shares	Dec. 31, 2013 USD ($) Cogeneration_facilities	Dec. 16, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)
Accounting Policies
Allowance for doubtful accounts receivable	$ 473,000		$ 473,000		$ 414,000
Capitalized interest	41,000			$ 6,000,000	18,000,000	$ 29,000,000
Impairment of unproved oil and gas properties				16,000,000	79,000	589,000
Dry hole costs					15,000,000
Plugging and abandonment expense					4,000,000
Deferred financing fees	5,000,000		$ 5,000,000		27,000,000
Amortization of deferred financing fees	$ 83,000			$ 5,000,000	$ 5,000,000	$ 11,000,000
Number of cogeneration facilities (in ones) \| Cogeneration_facilities			3
Debt issuance costs paid		$ 5,000,000
Minimum \| Building and leasehold improvements
Accounting Policies
Property, plant and equipment, useful life			10 years
Minimum \| Pipe and pipeline, drilling and other equipment
Accounting Policies
Property, plant and equipment, useful life			2 years
Maximum \| Building and leasehold improvements
Accounting Policies
Property, plant and equipment, useful life			25 years
Maximum \| Pipe and pipeline, drilling and other equipment
Accounting Policies
Property, plant and equipment, useful life			30 years
Electricity sales
Accounting Policies
Concentration risk, percentage			100.00%		100.00%	100.00%
Berry and LinnCo
Accounting Policies
Exchange ratio		168.00%
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares		93,756,674
Linn Energy LLC and LinnCo
Accounting Policies
Exchange ratio		100.13%
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares \| shares		93,756,674
Major Customer 2 \| Trade Accounts Receivable
Accounting Policies
Concentration risk, percentage					13.00%
Major Customer 2 \| Oil, natural gas and NGL sales
Accounting Policies
Concentration risk, percentage	10.00%			10.00%	13.00%	14.00%
Major Customer 1 \| Trade Accounts Receivable
Accounting Policies
Concentration risk, percentage			48.00%		43.00%
Major Customer 1 \| Oil, natural gas and NGL sales
Accounting Policies
Concentration risk, percentage	50.00%			45.00%	43.00%	43.00%
East Texas
Accounting Policies
Impairment of long-lived assets						$ 625,000,000

Basis of Presentation and Significant Accounting Policies (Other Current Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Other current assets
Short-term investments	$ 0	$ 125
Prepaid expenses	3,652	4,168
California carbon allowance inventories	15,895	545
Oil inventories	7,436	1,216
Materials inventories	3,036	12,943
Other	814	193
Other current assets	$ 30,833	$ 19,190

Basis of Presentation and Significant Accounting Policies (Other Accrued Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Accrued interest	$ 18,926	$ 16,996
Accrued compensation	6,749	12,700
Asset retirement obligation, current	3,318	4,430
Other	0	1,695
Other accrued liabilities	$ 28,993	$ 35,821

Basis of Presentation and Significant Accounting Policies (Supplemental Cash Flow Data) (Details) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Cash Flow Data [Abstract]
Cash payments for interest, net of amounts capitalized	$ 0	$ 87,495	$ 64,602	$ 59,853
Cash payments for income taxes	0	622	4,227	7,914
Accrued capital expenditures	4,788	70,866	98,020	61,098
Asset retirement obligations	$ 0	$ 15,998	$ 18,248	$ 7,448

LINN Energy Merger (Details) $ in Thousands	Dec. 16, 2013 USD ($) shares
LINN Energy Merger, Acquisitions, and Divestitures
Long-term debt assumed	$ 2,301,859
Cash acquired	451,113
Linn Merger
LINN Energy Merger, Acquisitions, and Divestitures
Preliminary value of acquisition	4,600,000
Long-term debt assumed	2,300,000
Cash acquired	$ 451,113
Berry and LinnCo
LINN Energy Merger, Acquisitions, and Divestitures
Exchange ratio	168.00%
Number of shares issued in merger \| shares	93,756,674
Linn Energy LLC and LinnCo
LINN Energy Merger, Acquisitions, and Divestitures
Exchange ratio	100.13%
Number of shares issued in merger \| shares	93,756,674

LINN Energy Merger (Details 2) - USD ($)		12 Months Ended
LINN Energy Merger (Details 2) - USD ($)	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012
LINN Energy Merger, Acquisitions, and Divestitures
Cash acquired		$ 451,113,000
Current assets		249,564,000
Noncurrent assets		97,202,000
Oil and natural gas properties		4,791,394,000
Total assets acquired		5,589,273,000
Current liabilities		310,105,000
Noncurrent liabilities		100,809,000
Asset retirement obligations, current and noncurrent		94,612,000
Long-term debt, including current portion		2,301,859,000
Total liabilities assumed		2,807,385,000
Net assets acquired		2,781,888,000
Current receivables acquired		194,000,000
Derivative instruments acquired, current		14,000,000
Derivative instruments acquired, noncurrent		6,000,000
Other property and equipment acquired		83,000,000
Current payables acquired		272,000,000
Out-of-market natural gas transportation contracts acquired, current		19,000,000
Out-of-market natural gas transportation contracts acquired, noncurrent		88,000,000
Transaction costs related to the merger	$ 16,000,000	$ 45,000,000
Net deferred income tax liability	$ 0		$ 256,224,000

Acquisitions and Divestitures (Details ) $ in Millions	Sep. 12, 2012 USD ($) a	Apr. 13, 2012 USD ($) a Wells	Jan. 31, 2012 USD ($)	May 25, 2011 USD ($) a
LINN Energy Merger, Acquisitions, and Divestitures
Number of wells acquired in acquisition \| Wells		1
Wolfberry Acquisition
LINN Energy Merger, Acquisitions, and Divestitures
Acquisition of oil and natural gas properties acres acquired \| a		2,000
Purchase price paid, net of customary post-closing adjustments		$ 15
Brundage Canyon Acquisition
LINN Energy Merger, Acquisitions, and Divestitures
Acquisition of oil and natural gas properties acres acquired \| a	14,000
Purchase price paid, net of customary post-closing adjustments	$ 40
Nevada assets
LINN Energy Merger, Acquisitions, and Divestitures
Proceeds from sale of assets			$ 16
Gain (loss) on sale of oil and natural gas property			$ 2
2011 \| Wolfberry Acquisition
LINN Energy Merger, Acquisitions, and Divestitures
Acquisition of oil and natural gas properties acres acquired \| a				6,000
Purchase price paid, net of customary post-closing adjustments				$ 128

Debt (Details) - USD ($)	12 Months Ended
Debt (Details) - USD ($)	Dec. 31, 2013	Dec. 31, 2012	Apr. 30, 2012	Mar. 09, 2012	Oct. 31, 2011
Debt Instrument
Credit facility, amount outstanding	$ 1,173,175,000	$ 562,900,000
Total debt, net	2,302,000,000	1,742,000,000
Long-term debt, excluding current maturities	2,090,000,000	1,666,000,000
Senior notes, net	1,129,000,000	1,179,000,000
Remaining borrowing capacity available under the agreement	$ 0
Credit facility, portion of properties required to maintain mortgages	80.00%
10.25% Senior notes due 2014
Debt Instrument
Interest rate on debt instrument (as a percent)	10.25%
Senior notes, current	$ 205,000,000
Senior notes, net			$ 205,000,000		$ 355,000,000
Credit Facility
Debt Instrument
Credit facility, maximum borrowing capacity	1,400,000,000
Lender commitments	$ 1,200,000,000
6.75% Senior notes due 2020
Debt Instrument
Interest rate on debt instrument (as a percent)	6.75%
Senior notes, net	$ 300,000,000
6.375% Senior notes due 2022
Debt Instrument
Interest rate on debt instrument (as a percent)	6.375%
Senior notes, net				$ 600,000,000
Low end of the range \| Credit Facility
Debt Instrument
Credit facility, unused capacity, commitment fee percentage	0.375%
Low end of the range \| Credit Facility \| LIBOR
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)	1.50%
Low end of the range \| Credit Facility \| Variable prime rate
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)	0.50%
High end of the range \| Credit Facility
Debt Instrument
Credit facility, unused capacity, commitment fee percentage	0.50%
High end of the range \| Credit Facility \| LIBOR
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)	2.50%
High end of the range \| Credit Facility \| Variable prime rate
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)	1.50%
Carrying amount
Debt Instrument
Credit facility, amount outstanding		562,900,000
Net unamortized discounts and premium	$ 23,000,000	(2,000,000)
Total debt, net	2,301,000,000	1,666,000,000
Long-term debt, current maturities	(211,000,000)	0
Senior notes, net	1,128,000,000	1,103,000,000
Carrying amount \| 10.25% Senior notes due 2014
Debt Instrument
Senior notes, current	205,000,000
Senior notes, noncurrent		205,000,000
Carrying amount \| Credit Facility
Debt Instrument
Credit facility, amount outstanding	1,173,175,000
Carrying amount \| 6.75% Senior notes due 2020
Debt Instrument
Senior notes, noncurrent	300,000,000	300,000,000
Carrying amount \| 6.375% Senior notes due 2022
Debt Instrument
Senior notes, noncurrent	$ 600,000,000	$ 600,000,000
Credit Facility
Debt Instrument
Credit facility, variable interest rate	2.67%	2.00%

Debt 10.25% Senior Notes Due 2014 (Details) - 10.25% Senior notes due 2014 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 16, 2013
Debt Instrument
Interest rate on debt instrument (as a percent)	10.25%
Senior notes, current	$ 205
Current debt, fair value		$ 212
Unamortized premium		$ 7
Debt instrument redemption price percentage of principal amount plus make whole premium and accrued and unpaid interest	100.00%

Debt 6.75% Senior Notes Due 2020 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012
Debt Instrument
Senior notes	$ 1,129		$ 1,179
6.75% Senior notes due 2020
Debt Instrument
Interest rate on debt instrument (as a percent)	6.75%
Senior notes	$ 300
Long-term debt, fair value		$ 310
Unamortized premium		$ 10
Debt instrument redemption price percentage of principal amount plus make whole premium and accrued and unpaid interest	100.00%
Prior to November 1, 2013 \| 6.75% Senior notes due 2020
Debt Instrument
Debt instrument redemption percentage, maximum	35.00%
Senior notes redemption price percentage of principal	106.75%
November 1, 2015 through October 31, 2016 \| 6.75% Senior notes due 2020
Debt Instrument
Senior notes redemption price percentage of principal	103.375%
November 1, 2016 through October 31, 2017 \| 6.75% Senior notes due 2020
Debt Instrument
Senior notes redemption price percentage of principal	102.25%
November 1, 2017 through October 31, 2018 \| 6.75% Senior notes due 2020
Debt Instrument
Senior notes redemption price percentage of principal	101.125%
November 1, 2018 and thereafter \| 6.75% Senior notes due 2020
Debt Instrument
Senior notes redemption price percentage of principal	100.00%

Debt 6.375% Senior Notes Due 2020 (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
	Mar. 09, 2012	Sep. 30, 2013	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012
Debt Instrument
Senior notes			$ 1,129		$ 1,179
6.375% Senior notes due 2022
Debt Instrument
Interest rate on debt instrument (as a percent)			6.375%
Senior notes	$ 600
Net proceeds from issuance long-term debt	$ 590
Long-term debt, fair value				$ 607
Unamortized premium				$ 7
March 9, 2012 Through March 14, 2015 \| 6.375% Senior notes due 2022
Debt Instrument
Debt instrument redemption percentage, maximum			35.00%
Senior notes redemption price percentage of principal			106.375%
March 15, 2017 through March 14, 2018 \| 6.375% Senior notes due 2022
Debt Instrument
Senior notes redemption price percentage of principal			103.188%
March 15, 2018 through March 14, 2019 \| 6.375% Senior notes due 2022
Debt Instrument
Senior notes redemption price percentage of principal			102.125%
March 15, 2019 through March 14, 2020 \| 6.375% Senior notes due 2022
Debt Instrument
Senior notes redemption price percentage of principal			101.063%
March 15, 2020 and thereafter \| 6.375% Senior notes due 2022
Debt Instrument
Senior notes redemption price percentage of principal			100.00%
March 9, 2012 through March 14, 2017 \| 6.375% Senior notes due 2022
Debt Instrument
Debt instrument redemption price percentage of principal amount plus make whole premium and accrued and unpaid interest			100.00%
Minimum redemption notice at stipulated date and rate \| 6.375% Senior notes due 2022
Debt Instrument
Senior notes redemption price, notice period range in days		30 days
Maximum redemption notice at stipulated date and rate \| 6.375% Senior notes due 2022
Debt Instrument
Senior notes redemption price, notice period range in days			60 days

Debt Debt Redemptions and Repurchases (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Apr. 30, 2012	Oct. 31, 2011	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument
Senior notes			$ 1,129	$ 1,179
8.25% Senior subordinated notes due 2016
Debt Instrument
Interest rate on debt instrument (as a percent)			8.25%
Debt repurchase amount	$ 200
Subordinated debt aggregate purchase price	216
Loss on extinguishment of debt	(42)
Write off of deferred debt issuance cost	7
10.25% Senior notes due 2014
Debt Instrument
Interest rate on debt instrument (as a percent)			10.25%
Debt repurchase amount	150
Unsecured debt aggregate purchase price	182
Senior notes	205	$ 355
10.25% bond repurchases
Debt Instrument
Debt repurchase amount		95
Unsecured debt aggregate purchase price		109
Loss on extinguishment of debt		(15)
Write off of deferred debt issuance cost		3
Premium paid over par \| 8.25% Senior subordinated notes due 2016
Debt Instrument
Loss on extinguishment of debt	$ (35)
Premium paid over par \| 10.25% bond repurchases
Debt Instrument
Loss on extinguishment of debt		$ (12)

Income Taxes (Details) - USD ($)	12 Months Ended
Income Taxes (Details) - USD ($)	Dec. 16, 2013	Dec. 31, 2013	Dec. 31, 2012
Income Tax Contingency [Line Items]
Unrecognized tax benefits, period decrease	$ 3,000,000
Accrued interest recognized due to uncertain tax positions		$ 19,000	$ 426,000

Income Taxes (Schedule of Components of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Current:
Federal	$ 0	$ (225)	$ 286	$ 4,115
State	0	(11,043)	4,954	2,936
Deferred:
Federal	0	56,620	80,083	(125,261)
State	0	19,928	2,798	(24,018)
Income tax expense (benefit)	$ 0	$ 65,280	$ 88,121	$ (142,228)

Income Taxes (Schedule of Effective Income Tax Rate Reconciliation) (Details)		12 Months Ended
	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]
Federal statutory rate, percent	35.00%	35.00%	35.00%	35.00%
State, net of federal tax benefits, percent	0.00%	3.00%	3.00%	3.00%
Loss excluded from nontaxable entities, percent	(35.00%)	(0.00%)	(0.00%)	(0.00%)
Deferred state rate impact, percent	0.00%	0.00%	(1.00%)	0.00%
Research and development credits, percent	(0.00%)	(0.00%)	(3.00%)	(0.00%)
Net impact to uncertain income tax positions, percent	0.00%	(2.00%)	0.00%	1.00%
Transaction costs, percent	0.00%	4.00%	0.00%	0.00%
Other, percent	0.00%	1.00%	0.00%	(1.00%)
Effective rate, percent	0.00%	41.00%	34.00%	38.00%

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($)	Dec. 31, 2013	Dec. 31, 2012
Deferred tax assets:
Federal benefit of state income taxes	$ 0	$ 239,000
Credit carryforwards	0	36,028,000
Equity and deferred compensation	0	15,139,000
Net operating loss	0	412,000
Bad debt expense	0	163,000
Other, net	0	610,000
Valuation allowance	0	(1,201,000)
Deferred tax assets, net	0	50,912,000
Deferred tax liabilities:
Depreciation and depletion	0	(298,659,000)
Derivatives	0	(8,477,000)
Deferred tax liabilities, gross	0	(307,136,000)
Net deferred tax liabilities	$ 0	$ 256,224,000

Income Taxes (Summary of Income Tax Contingencies) (Details) - USD ($) $ in Millions		12 Months Ended
	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Contingency [Line Items]
Unrecognized tax benefits at beginning of period		$ 23	$ 3	$ 5
Increase resulting from prior period tax positions	$ 0	1	21	0
Decreases for settlements with taxing authorities	0	0	0	2
Decreases for lapses in the applicable statute of limitations	0	2	1	0
Unrecognized tax benefits at end of period	0		$ 23	$ 3
Successor
Income Tax Contingency [Line Items]
Unrecognized tax benefits at beginning of period	0
Unrecognized tax benefits at end of period		0
Predecessor
Income Tax Contingency [Line Items]
Unrecognized tax benefits at beginning of period	$ 20
Unrecognized tax benefits at end of period		$ 20

Member's and Shareholders' Equity (Details) - USD ($)	12 Months Ended
Member's and Shareholders' Equity (Details) - USD ($)	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Common Class A
Member's and Shareholders' Equity
Common stock, voting rights	1
Common Class B
Member's and Shareholders' Equity
Common stock, voting rights	.95
Common stock liquidation preference value	$ 0.50
Conversion of stock, shares	1
Dividend payments limited by covenants in Credit Facility
Member's and Shareholders' Equity
Dividends payment covenant credit agreement based on net earnings	$ 35,000,000
Dividends payment covenant credit agreement based on net earnings, percent	75.00%
Dividends payment covenant credit agreement based on net earnings, number of quarters	4
Dividend payments limited by covenants in Indentures
Member's and Shareholders' Equity
Dividends payment covenant credit agreement based on indentures governing senior and subordinated indentures per share annually, in dollars per share	$ 0.36
Dividends payments credit agreement bond indentures annually without consideration of coverage ratio or exhausted restricted payments baskets	$ 20,000,000
Dividends payments credit agreement on debt in event it is in a non-payment default	$ 10,000,000
Predecessor
Member's and Shareholders' Equity
Dividends per share	$ 0.32	$ 0.32	$ 0.31
Predecessor \| Common Class B
Member's and Shareholders' Equity
Common stock liquidation preference value		$ 0.50

Equity Incentive Compensation Plans and Other Benefit Plans (Equity Incentive Plans) (Details) - USD ($) $ in Millions		12 Months Ended
	Dec. 16, 2013	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011	May 31, 2010	May 31, 2005
Share-based Compensation Arrangement by Share-based Payment Award
Term of options granted under plan		10 years
Total compensation cost		$ 12	$ 9	$ 9
Scenerio one
Share-based Compensation Arrangement by Share-based Payment Award
Vesting rate based on plan (as a percent)		25.00%
Vesting period based on plan (in years)		4 years
Scenerio two
Share-based Compensation Arrangement by Share-based Payment Award
Vesting rate based on plan (as a percent)		100.00%
Vesting period based on plan (in years)		3 years
Common Class A \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Options may not be less than fair market value of Common Stock on the date of grant (in shares)	1	1
2010 Equity Incentive Plan \| Common Class A
Share-based Compensation Arrangement by Share-based Payment Award
Number of common stock shares available for grant					1,000,000
2005 Equity Incentive Plan \| Common Class A
Share-based Compensation Arrangement by Share-based Payment Award
Number of common stock shares available for grant						2,900,000
Linn Energy LLC and LinnCo
Share-based Compensation Arrangement by Share-based Payment Award
Exchange ratio	100.13%
Berry and LinnCo
Share-based Compensation Arrangement by Share-based Payment Award
Exchange ratio	168.00%

Equity Incentive Compensation Plans (Stock Options) (Details) - USD ($)
$ / shares in Units, $ in Thousands

12 Months Ended

Dec. 16, 2013

Dec. 31, 2012

Dec. 31, 2011

Equity Incentive Compensation Plans

Expected volatility

50.00%

45.00%

Risk free rate

0.95%

2.54%

Dividend yield

0.57%

0.62%

Expected term (in years)

5 years 2 months

6 years

Weighted average remaining contractual term of outstanding options

3 years 2 months 16 days

Stock options activity

Outstanding shares at the beginning of the period

1,387,592.000

1,520,689.000

2,017,225

Shares granted

82,262

89,865

Shares exercised

(57,350)

(215,359)

(579,636)

Shares canceled/expired

(6,765)

Outstanding shares at the end of the period

1,330,242.000

1,387,592.000

1,520,689.000

Stock options, weighted average exercise price

Outstanding at the beginning of the period (in dollars per share)

$ 33.71

$ 30.32

$ 25.87

Granted (in dollars per share)

53.02

48.50

Exercised (in dollars per share)

12.74

17.12

17.47

Cancelled/expired (in dollars per share)

45.92

Outstanding at the end of the period (in dollars per share)

$ 34.61

$ 33.71

$ 30.32

Stock options, aggregate intrinsic value

Outstanding at the beginning of the period

$ 4,681

$ 17,798

$ 35,974

Exercised

2,066

7,194

^[1]

17,746

^[1]

Outstanding at the end of the period

$ 19,243

$ 4,681

$ 17,798

Stock options, exercisable

Exercisable options outstanding

1,224,022

Weighted average exercise price of exercisable options

$ 33.18

Aggregate intrinsic value of stock options exercisable

$ 19,229

Weighted average remaining contractual term of exercisable options

2 years 9 months 23 days

Stock options, vested and expected to vest

Vested and expected to vest options outstanding

1,328,771

Weighted average exercise price of vested and expected to vest options

$ 34.60

Aggregate intrinsic value of vested and expected to vest options

$ 19,243

Weighted average remaining contractual term for vested and expected to vest options

3 years 2 months 14 days

[1]	The intrinsic value of a stock option is the amount by which the market value of the underlying stock at the end of the related period exceeds the exercise price of the option.

Equity Incentive Compensation Plans (Range of Exercise Prices) (Details) - $ / shares		12 Months Ended
	Dec. 16, 2013	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Number of stock options outstanding	1,330,242	1,330,242
Weighted average remaining contractual term of outstanding options	3 years 2 months 16 days
Weighted average exercise price of stock options outstanding	$ 34.61	$ 34.61	$ 33.71	$ 30.32	$ 25.87
Number of stock options exercisable	1,224,022	1,224,022
Weighted average remaining contractual term of exercisable options	2 years 9 months 23 days
Weighted average exercise price of exercisable options	$ 33.18	$ 33.18
Exercise Prices 21.58 to 21.77
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Range of exercise prices, lower range limit		21.58
Range of exercise prices, upper range limit		$ 21.77
Number of stock options outstanding	240,000	240,000
Weighted average remaining contractual term of outstanding options		10 months 24 days
Weighted average exercise price of stock options outstanding	$ 21.60	$ 21.60
Number of stock options exercisable	240,000	240,000
Weighted average remaining contractual term of exercisable options		10 months 24 days
Weighted average exercise price of exercisable options	$ 21.60	$ 21.60
Exercise Prices 30.65 to 32.57
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Range of exercise prices, lower range limit		30.65
Range of exercise prices, upper range limit		$ 32.57
Number of stock options outstanding	639,000	639,000
Weighted average remaining contractual term of outstanding options		2 years 6 months
Weighted average exercise price of stock options outstanding	$ 31.70	$ 31.70
Number of stock options exercisable	639,000	639,000
Weighted average remaining contractual term of exercisable options		2 years 6 months
Weighted average exercise price of exercisable options	$ 31.70	$ 31.70
Exercise Prices 38.00 to 53.02
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Range of exercise prices, lower range limit		38.00
Range of exercise prices, upper range limit		$ 53.02
Number of stock options outstanding	451,242	451,242
Weighted average remaining contractual term of outstanding options		5 years 5 months 4 days
Weighted average exercise price of stock options outstanding	$ 45.66	$ 45.66
Number of stock options exercisable	345,022	345,022
Weighted average remaining contractual term of exercisable options		4 years 8 months 16 days
Weighted average exercise price of exercisable options	$ 43.98	$ 43.98

Equity Incentive Compensation Plans (Restricted Stock Units and Performance Share Program) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity Incentive Compensation Plans
Expected volatility		50.00%	45.00%
Risk free rate		0.95%	2.54%
Restricted Stock Units
Other than stock options activity
Outstanding shares at the beginning of the period	981,877	915,022	857,360
Granted	286,344	164,112	159,333
Issued	(853,169)	(79,068)	(62,127)
Canceled/expired	(22,511)	(18,189)	(39,544)
Outstanding shares at the end of the period	392,541	981,877	915,022
Weighted-average intrinsic value at grant-date
Outstanding at the beginning of the period (in dollars per share)	$ 26.72	$ 23.88	$ 19.67
Granted (in dollars per share)	45.51	50.60	47.98
Issued (in dollars per share)	23.94	33.10	26.18
Canceled/expired (in dollars per share)	44.69	41.50	25.12
Outstanding at the end of the period (in dollars per share)	$ 46.86	$ 26.72	$ 23.88
Vest Date Fair Value - Issued (in dollars)	$ 39,513	$ 3,401	$ 2,588
Performance Based Restricted Stock Units
Other than stock options activity
Outstanding shares at the beginning of the period	222,587.000	162,849.000	103,794
Granted		59,738	65,620
Issued	(135,167)
Canceled/expired	(87,420)		(6,565)
Outstanding shares at the end of the period	0	222,587.000	162,849.000
Weighted-average intrinsic value at grant-date
Outstanding at the beginning of the period (in dollars per share)	$ 45.79	$ 39.00	$ 31.20
Granted (in dollars per share)		63.69	51.86
Issued (in dollars per share)	44.33
Canceled/expired (in dollars per share)	44.42		44.20
Outstanding at the end of the period (in dollars per share)	$ 0.00	$ 45.79	$ 39.00
Vest Date Fair Value - Issued (in dollars)	$ 6,308
Performance shares
Equity Incentive Compensation Plans
Number of simulations		100,000	100,000
Expected volatility		50.00%	44.00%
Risk free rate		0.42%	1.15%

Equity Incentive Compensation Plans and Other Benefit Plans (Director Fees and Other Employee Benefits-401(k) Plan) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Other employee benefits—401(k) plan
Company match of employee's contributions (as a percent)	100.00%
Employee participation in 401(k) Plan (as a percent)	93.00%
Company's contributions to 401(k) Plan, net of forfeitures	$ 2	$ 2	$ 2
Maximum
Other employee benefits—401(k) plan
Company match of employee's eligible compensation (as a percent)	8.00%
Non-employee directors
Director fees
Shares earned and deferred in accordance with the plan (in shares)	10,758	12,797	13,647

Derivative Instruments Derivative Instruments (Commodity Derivatives) (Details)	Dec. 31, 2013 $ / mmbls mmbls
2014 \| Oil Derivative Instruments \| Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	4,928
Weighted Average Fixed Price (in usd per energy unit)	91.26
2014 \| Oil Derivative Instruments \| Collars
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	730
Derivative, Floor Price	90.00
Derivative, Cap Price	102.87
2014 \| Oil Derivative Instruments \| Three-way collars (NYMEX WTI)
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	3,103
2014 \| Oil Derivative Instruments \| Three-way collars (NYMEX WTI) \| Short
Derivative [Line Items]
Derivative, Floor Price	72.11
Derivative, Cap Price	109.79
2014 \| Oil Derivative Instruments \| Three-way collars (NYMEX WTI) \| Long
Derivative [Line Items]
Derivative, Floor Price	93.76
2014 \| Oil Derivative Instruments \| Three-way collars (ICE Brent)
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	365
2014 \| Oil Derivative Instruments \| Three-way collars (ICE Brent) \| Short
Derivative [Line Items]
Derivative, Floor Price	80.00
Derivative, Cap Price	114.05
2014 \| Oil Derivative Instruments \| Three-way collars (ICE Brent) \| Long
Derivative [Line Items]
Derivative, Floor Price	100.00
2014 \| Oil Basis Differential Commodity Contract \| ICE Brent - NYMEX WTI basis swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	3,650
Hedged Differential (in usd per energy unit)	11.60
2014 \| Oil Timing Differential Positions \| Trade month roll swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	1,825
Hedged Differential (in usd per energy unit)	0.32
2015 \| Oil Derivative Instruments \| Fixed price swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	0
Weighted Average Fixed Price (in usd per energy unit)	0
2015 \| Oil Derivative Instruments \| Collars
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	0
Derivative, Floor Price	0
Derivative, Cap Price	0
2015 \| Oil Derivative Instruments \| Three-way collars (NYMEX WTI)
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	1,095
2015 \| Oil Derivative Instruments \| Three-way collars (NYMEX WTI) \| Short
Derivative [Line Items]
Derivative, Floor Price	70.00
Derivative, Cap Price	101.62
2015 \| Oil Derivative Instruments \| Three-way collars (NYMEX WTI) \| Long
Derivative [Line Items]
Derivative, Floor Price	90.00
2015 \| Oil Derivative Instruments \| Three-way collars (ICE Brent)
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	0
2015 \| Oil Derivative Instruments \| Three-way collars (ICE Brent) \| Short
Derivative [Line Items]
Derivative, Floor Price	0
Derivative, Cap Price	0
2015 \| Oil Derivative Instruments \| Three-way collars (ICE Brent) \| Long
Derivative [Line Items]
Derivative, Floor Price	0
2015 \| Oil Basis Differential Commodity Contract \| ICE Brent - NYMEX WTI basis swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	2,920
Hedged Differential (in usd per energy unit)	11.60
2015 \| Oil Timing Differential Positions \| Trade month roll swaps
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| mmbls	0
Hedged Differential (in usd per energy unit)	0

Derivative Instruments (Details) - USD ($) $ in Thousands			12 Months Ended
Derivative Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative
Notional amount of derivative instruments
Maximum loss upon all counterparties failing to perform		$ 28,000
Oil, natural gas and NGL sales \| Commodity contract
Notional amount of derivative instruments
Amortization of AOCL into earnings				$ 11,000	$ 61,000
Interest expense \| Interest rate contract
Notional amount of derivative instruments
Amortization of AOCL into earnings				2,000	1,000
Successor
Notional amount of derivative instruments
Derivative asset, gross	$ 28,291	28,291
Derivative liability, gross	45,226	$ 45,226
Gains (losses) on oil and natural gas derivatives	$ (5,049)
Predecessor
Notional amount of derivative instruments
Derivative asset, gross				27,277
Derivative liability, gross				4,075
Gains (losses) on oil and natural gas derivatives			$ (34,711)	$ 64,620	$ 13,908

Fair Value Measurements on a Recurring Basis (Details) - Commodity Contracts - USD ($)
$ in Thousands

Dec. 31, 2013

Dec. 31, 2012

Successor

Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions

Fair value assets measured on recurring basis, derivative financial instruments, assets

$ 8,107

Fair value assets measured on recurring basis, derivative financial instruments, liabilities

25,042

Predecessor

Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions

Fair value assets measured on recurring basis, derivative financial instruments, assets

$ 25,552

Fair value assets measured on recurring basis, derivative financial instruments, liabilities

2,350

Fair Value, Inputs, Level 2 | Successor

Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions

Fair value assets measured on recurring basis, derivative financial instruments, assets

28,291

Fair value assets measured on recurring basis, derivative financial instruments, liabilities

45,226

Fair Value, Inputs, Level 2 | Predecessor

Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions

Fair value assets measured on recurring basis, derivative financial instruments, assets

27,277

Fair value assets measured on recurring basis, derivative financial instruments, liabilities

4,075

Counterparty netting under agreements governing derivatives | Successor

Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions

Fair value assets measured on recurring basis, derivative financial instruments, assets

(20,184)

Fair value assets measured on recurring basis, derivative financial instruments, liabilities

$ (20,184)

Counterparty netting under agreements governing derivatives | Predecessor

Fair Value Assets And Liabilities Measured On Recurring Basis Financial Statement Captions

Fair value assets measured on recurring basis, derivative financial instruments, assets

^[1]

(1,725)

Fair value assets measured on recurring basis, derivative financial instruments, liabilities

^[1]

$ (1,725)

[1]	Represents counterparty netting under agreements governing such derivatives.

Commitments and Contingencies (Details) - USD ($)		12 Months Ended
Commitments and Contingencies (Details) - USD ($)	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies
Gathering System, Fair Value	$ 13,000,000	$ 13,000,000
Operating leases
Rent expense related to lease commitments	302,000	5,000,000	$ 3,000,000	$ 3,000,000
Operating Leases, Future Minimum Payments Due
Operating leases, future minimum payments due	21,000,000	21,000,000
Operating leases, future minimum payments due, current	6,000,000	6,000,000
Operating leases, future minimum payments, due in two years	5,000,000	5,000,000
Operating leases, future minimum payments, due in three years	4,000,000	4,000,000
Operating leases, future minimum payments, due in four years	2,000,000	2,000,000
Operating leases, future minimum payments, due in five years	2,000,000	2,000,000
Operating leases, future minimum payments, due after fifth year	2,000,000	2,000,000
Recorded Unconditional Purchase Obligation and Operating Leases, Future Minimum Payments Due
Unrecorded unconditional purchase obligation and operating leases, future minimum payments due	251,000,000	251,000,000
Unrecorded unconditional purchase obligation and operating leases, future minimum payments due, current	51,000,000	51,000,000
Unrecorded unconditional purchase obligation and operating leases, future minimum payments due in second year	42,000,000	42,000,000
Unrecorded unconditional purchase obligation and operating leases, future minimum payments due in third year	39,000,000	39,000,000
Unrecorded unconditional purchase obligation and operating leases, future minimum payments due in fourth year	35,000,000	35,000,000
Unrecorded unconditional purchase obligation and operating leases, future minimum payments due in fifth year	26,000,000	26,000,000
Unrecorded unconditional purchase obligation and operating leases, future minimum payments due after fifth year	58,000,000	58,000,000
Other commitments
Unrecorded Unconditional Purchase Obligation Payment Schedule
Unrecorded unconditional purchase obligation due	16,000,000	16,000,000
Unrecorded unconditional purchase obligation due, current	11,000,000	11,000,000
Unrecorded unconditional purchase obligation due in second year	3,000,000	3,000,000
Unrecorded unconditional purchase obligation due in third year	2,000,000	2,000,000
Unrecorded unconditional purchase obligation due in fourth year	0	0
Unrecorded unconditional purchase obligation due in fifth year	0	0
Unrecorded unconditional purchase obligation due after fifth year	0	0
Firm natural gas transportation contracts
Unrecorded Unconditional Purchase Obligation Payment Schedule
Unrecorded unconditional purchase obligation due	214,000,000	214,000,000
Unrecorded unconditional purchase obligation due, current	34,000,000	34,000,000
Unrecorded unconditional purchase obligation due in second year	34,000,000	34,000,000
Unrecorded unconditional purchase obligation due in third year	33,000,000	33,000,000
Unrecorded unconditional purchase obligation due in fourth year	33,000,000	33,000,000
Unrecorded unconditional purchase obligation due in fifth year	24,000,000	24,000,000
Unrecorded unconditional purchase obligation due after fifth year	$ 56,000,000	$ 56,000,000

Commitments and Contingencies (Details 2)	12 Months Ended
Commitments and Contingencies (Details 2)	Dec. 31, 2011 USD ($)	Jan. 14, 2011 USD ($) a
Carry and Earning Agreement
Commitments
Contractual obligation amount, penalty waived per well		$ 200,000
Contractual obligation, acre of tracts \| a		160
Contractual obligation, contingent construction expense		$ 9,000,000
Penalty payable as a percentage of difference between specified amount and actual expended (as a percent)		50.00%
Contractual obligation, specified amount for penalty calculation		$ 12,000,000
Third party share of construction costs, percentage		50.00%
Bureau of Land Management
Commitments
Litigation settlement expense	$ 2,000,000

Other Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Other property and equipment
Other property and equipment	$ 83,126	$ 37,408
Less accumulated depreciation	233	25,340
Other property and equipment, net	82,893	12,068
Pipe and pipeline, drilling and other equipment
Other property and equipment
Other property and equipment	74,155	18,131
Building and leasehold improvements
Other property and equipment
Other property and equipment	6,515	10,110
Vehicles
Other property and equipment
Other property and equipment	$ 2,456	$ 9,167

Asset Retirement Obligations (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 16, 2013

Dec. 31, 2012

Change in the asset retirement obligations

Asset retirement obligations at beginning of year

$ 86,746

$ 64,019

Current year accretion expense

$ 218

7,136

5,858

Revisions of estimates

5,900

10,999

Asset retirement obligations at end of year

94,830

86,746

Liabilities added from drilling

Change in the asset retirement obligations

Liabilities incurred

10,097

7,249

Settlements

Change in the asset retirement obligations

Liabilities settled

(3,882)

(3,325)

Liabilities added from acquisitions

Change in the asset retirement obligations

Liabilities incurred

2,651

Liabilities associated with assets sold

Change in the asset retirement obligations

Liabilities settled

(40)

$ (705)

Successor

Change in the asset retirement obligations

Asset retirement obligations at beginning of year

^[1]

94,612

Asset retirement obligations at end of year

^[1]

94,612

Predecessor

Change in the asset retirement obligations

Asset retirement obligations at beginning of year

^[1]

$ 105,957

Asset retirement obligations at end of year

^[1]

$ 105,957

[1]	As a result of the application of pushdown accounting, the Company remeasured its asset retirement obligations on the LINN Energy transaction date.

Related Party Transactions (Details) - USD ($)	Dec. 31, 2013	Dec. 16, 2013
Related Party Transaction
Transfer of derivative liability from affiliate	$ 31,428,000
Due to Affiliate	17,000,000
Payments to related party	$ 39,000
Berry and LinnCo
Related Party Transaction
Exchange ratio		168.00%
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares		93,756,674
Linn Energy LLC and LinnCo
Related Party Transaction
Exchange ratio		100.13%
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares		93,756,674

- Definition

Amount of payable due to an entity that is affiliated with the reporting entity by means of direct or indirect ownership.

+ References + Details

Supplemental Oil & Natural Gas Data (Unaudited) (Costs Incurred and Capitalized Costs) (Details) - USD ($)		12 Months Ended
	Dec. 31, 2013	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Property acquisition costs
Proved	$ 0	$ 3,457,000	$ 70,700,000	$ 149,158,000
Unproved	0	463,000	10,686,000	6,632,000
Exploration costs	0	868,000	16,405,000	627,000
Development costs	22,266,000	577,568,000	696,095,000	536,666,000
Asset retirement costs	0	15,998,000	18,248,000	7,448,000
Total costs incurred	22,266,000	598,354,000	812,134,000	700,531,000
Capitalized interest	41,000	$ 6,000,000	18,000,000	$ 29,000,000
Oil and Natural Gas Capitalized Costs
Proved properties	3,397,785,000		4,060,106,000
Unproved properties	1,415,874,000		236,626,000
Oil and natural gas property, gross	4,813,659,000		4,296,732,000
Accumulated depletion and amortization	(10,394,000)		(1,180,298,000)
Oil and natural gas capitalized costs, net	$ 4,803,265,000		$ 3,116,434,000

Supplemental Oil & Natural Gas Data (Unaudited) (Results of Oil and Natural Gas Producing Activities) (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
	Dec. 31, 2013	Dec. 16, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 16, 2013	Dec. 31, 2012	Dec. 31, 2011
Results of Operations for Oil and Gas Producing Activities
Income tax expense (benefit)	$ 0									$ 65,280	$ 88,121	$ (142,228)
Successor
Results of Operations for Oil and Gas Producing Activities
Oil, natural gas and NGL sales	50,324
Gains (losses) on oil and natural gas derivatives	(5,049)
Gains (losses) on oil and natural gas derivatives	(5,049)
Lease operating expenses	15,410
Transportation expenses	2,576
Severance and ad valorem taxes	2,130
Total production costs	20,116
Exploration costs	0
Depletion and amortization	10,612
Impairment of long-lived assets	0
Gains (losses) on sales of assets and other, net	(10,208)
Total other costs	20,820
Income tax expense (benefit)	0
Results of operations	4,339
Total revenue from oil and gas producing activities	$ 45,275
Predecessor
Results of Operations for Oil and Gas Producing Activities
Oil, natural gas and NGL sales		$ 255,575	$ 306,183	$ 274,715	$ 266,772	$ 248,911	$ 232,916	$ 221,781	$ 233,653	1,103,245	937,261	870,773
Gains (losses) on oil and natural gas derivatives		(24,303)	(45,293)	35,622	(737)	8,306	(28,287)	113,082	(28,481)
Gains (losses) on oil and natural gas derivatives										(34,711)	64,620	13,908
Lease operating expenses										325,209	243,173	215,854
Transportation expenses										32,930	28,624	21,442
Severance and ad valorem taxes										41,509	39,374	33,617
Total production costs										399,648	311,171	270,913
Exploration costs										24,048	21,010	1,794
Depletion and amortization										275,927	224,836	212,125
Impairment of long-lived assets										0	0	629,252
Gains (losses) on sales of assets and other, net		$ 0	$ 0	$ 0	$ (23)	$ (12)	$ (170)	$ 163	$ (1,763)	23	1,782	1,046
Total other costs										299,952	244,064	842,125
Income tax expense (benefit)										65,280	88,121	(142,228)
Results of operations										303,654	358,525	(86,129)
Total revenue from oil and gas producing activities										$ 1,068,534	$ 1,001,881	$ 884,681

Supplemental Oil & Natural Gas Data (Unaudited) (Reserve Quantities) (Details)		12 Months Ended
	Dec. 31, 2013 MBoe MMcf	Dec. 16, 2013 MBoe Wells MMcf	Dec. 31, 2012 MBoe Wells MMcf	Dec. 31, 2011 MBoe Wells MMcf	Dec. 31, 2013 MBoe MMcf	Dec. 16, 2013 MBoe MMcf	Dec. 31, 2012 MBoe MMcf	Dec. 31, 2011 MBoe MMcf	Dec. 31, 2010 MBoe MMcf
Reserve Quantities
Proved developed reserves (BOE)					155,494	156,161	150,216	144,783
Proved undeveloped reserve (BOE)					78,554	78,554	124,913	130,143
Proved developed and undeveloped reserves, net BOE					234,048	234,715	275,129	274,926	271,213
Proved developed and undeveloped reserves, net \| MMcf			534,279	534,279				534,279
Proved Developed and Undeveloped Reserves
Beginning of period \| MMcf			534,279
Revisions of previous estimates BOE	0	(39,092)	(22,162)	(28,446)
Extensions, discoveries, and other additions BOE	0	15,913	25,148	30,600
Sales of minerals in place BOE	0	(2,775)	556	0
Production BOE	(667)	(14,460)	(13,321)	(13,025)
Purchase of minerals in place BOE			11,094	14,584
End of period \| MMcf				534,279
Change in proved reserves	(667)	(40,414)	203	3,713
Productive wells drilled \| Wells		340	467	404
Oil
Reserve Quantities
Proved developed reserves (BOE)					121,694	122,224	118,937	107,849
Proved undeveloped reserve (BOE)					65,668	65,668	85,271	78,031
Proved developed and undeveloped reserves, net BOE					187,362	187,892	204,208	185,880	166,181
Proved Developed and Undeveloped Reserves
Revisions of previous estimates BOE	0	(13,536)	12,145	(4,054)
Extensions, discoveries, and other additions BOE	0	10,955	8,459	19,601
Sales of minerals in place BOE	0	(2,263)	556	0
Production BOE	(530)	(11,472)	(10,024)	(9,041)
Purchase of minerals in place BOE			8,304	13,193
Natural gas
Reserve Quantities
Proved developed reserves (volume) \| MMcf					202,798	203,624	187,668	221,606
Proved undeveloped reserve (volume) \| MMcf					77,319	77,319	237,851	312,673
Proved developed and undeveloped reserves, net \| MMcf	280,943	425,519	425,519	630,192	280,117	280,943	425,519	534,279	630,192
Proved Developed and Undeveloped Reserves
Beginning of period \| MMcf	280,943	425,519	534,279	630,192
Revisions of previous estimates \| MMcf	0	(153,330)	(205,845)	(146,349)
Extensions and discoveries \| MMcf	0	29,756	100,129	65,992
Property sales \| MMcf	0	(3,071)	0	0
Production \| MMcf	(826)	(17,931)	(19,784)	(23,907)
Purchase of minerals in place \| MMcf			16,740	8,351
End of period \| MMcf	280,117	280,943	425,519	534,279

Supplemental Oil & Natural Gas Data (Unaudited) (Standardized Measure of Discounted Future Net Cash Flows) (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2013

USD ($)

Dec. 31, 2013

USD ($)

$ / boe

$ / Mcf

Dec. 16, 2013

USD ($)

Dec. 31, 2012

USD ($)

$ / boe

$ / Mcf

Dec. 31, 2011

USD ($)

$ / boe

$ / Mcf

Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

Future estimated revenues

$ 17,863,984

$ 19,738,729

$ 19,568,628

Future estimated production costs

(6,654,536)

(5,884,891)

(5,226,044)

Future estimated development costs

(1,854,849)

(2,164,780)

(1,975,429)

Future estimated income tax expense

(3,344,024)

(3,770,512)

Future net cash flows

9,354,599

8,345,034

8,596,643

10% annual discount for estimated timing of cash flows

(4,719,267)

(4,511,619)

(4,561,364)

Standardized measure of discounted future net cash flows

4,635,332

3,833,415

4,035,279

Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves

Standardized measure—beginning of year

$ 3,558,595

3,833,415

$ 3,833,415

4,035,279

Sales of oil and natural gas produced, net of production costs

30,208

(703,597)

(625,707)

(599,679)

Net changes in sales prices and production costs

(1,272)

(214,489)

(786,022)

1,473,454

Revisions of previous quantity estimates

(856,118)

743

(281,765)

Change in estimated future development costs

20,932

(331,498)

(274,122)

Purchases of reserves in place

114,094

164,383

Sales of reserves in place

(13,279)

(15,283)

Development costs incurred during the period

401,791

497,036

433,660

Accretion of discount

19,184

496,718

570,505

383,418

Income taxes

1,109,522

237,117

323,128

(634,747)

Other

(20,489)

166,480

(73,326)

(29,792)

Net increase (decrease)

1,076,737

(274,820)

(201,864)

1,236,123

Standardized measure—end of year

4,635,332

$ 4,635,332

3,558,595

$ 3,833,415

$ 4,035,279

Oil ($/Bbl)

Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

Average sales prices (in dollars per production type) | $ / boe

^[1]

96.89

90.66

93.72

Natural gas ($/Mcf)

Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

Average sales prices (in dollars per production type) | $ / Mcf

^[1]

3.67

2.88

4.02

Extensions and discoveries

Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves

Extensions, discoveries, additions and improved recovery, less related costs

$ 0

$ 189,625

$ 124,466

$ 601,313

[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.

Selected Quarterly Financial Data (Unaudited) (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 16, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 16, 2013

Dec. 31, 2012

Dec. 31, 2011

Predecessor

Selected Quarterly Financial Data

Oil, natural gas and NGL sales

$ 255,575

$ 306,183

$ 274,715

$ 266,772

$ 248,911

$ 232,916

$ 221,781

$ 233,653

$ 1,103,245

$ 937,261

$ 870,773

Electricity sales

6,844

10,046

9,513

7,589

8,586

9,514

5,860

5,980

33,992

29,940

34,953

Gains (losses) on oil and natural gas derivatives

(24,303)

(45,293)

35,622

(737)

8,306

(28,287)

113,082

(28,481)

Total revenues and other, net

239,827

273,014

322,338

276,123

268,355

216,352

342,790

213,629

1,111,302

1,041,126

935,235

Total expenses

254,305

^[1]

202,647

^[1]

201,331

^[1]

198,239

^[1]

201,291

^[1]

166,749

^[1]

149,760

^[1]

140,876

^[1]

856,499

656,894

1,217,081

Gains (losses) on sales of assets and other, net

170

(163)

1,763

(23)

(1,782)

(1,046)

Net income (loss)

$ (28,529)

$ 28,178

$ 61,364

$ 32,434

$ 38,499

$ 18,126

$ 81,016

$ 33,898

$ 93,447

$ 171,539

$ (228,063)

Successor

Selected Quarterly Financial Data

Oil, natural gas and NGL sales

$ 50,324

Electricity sales

1,444

Gains (losses) on oil and natural gas derivatives

(5,049)

Total revenues and other, net

47,118

Total expenses

63,100

Gains (losses) on sales of assets and other, net

10,208

Net income (loss)

(19,973)

Fourth Quarter | Successor

Selected Quarterly Financial Data

Total expenses

^[1]

$ 52,892

[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.

Label	Element	Value
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	us-gaap_StandardizedMeasureOfDiscountedFutureNetCashFlowsRelatingToProvedOilAndGasReserves	$ 2,799,156,000