View Filing Data

Print Document View Excel Document

Document and Entity Information Document - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2014	Jun. 30, 2014
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, 2014
Document Fiscal Year Focus	2014
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 - Successor - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$ 1,586	$ 51,041
Accounts receivable – trade, net	100,359	122,855
Derivative instruments	43,694	5,596
Other current assets	59,259	30,833
Total current assets	204,898	210,325
Noncurrent assets
Oil and natural gas properties (successful efforts method)	4,872,059	4,813,659
Less accumulated depletion and amortization	(525,007)	(10,394)
Oil and gas property, net (successful efforts method)	4,347,052	4,803,265
Other property and equipment	115,999	83,126
Less accumulated depreciation	(8,452)	(233)
Other property and equipment, net	107,547	82,893
Derivative instruments	0	2,511
Advance to affiliate	293,627	0
Other noncurrent assets	14,284	8,051
Noncurrent assets excluding property total	307,911	10,562
Total noncurrent assets	4,762,510	4,896,720
Total assets	4,967,408	5,107,045
Current liabilities:
Accounts payable and accrued expenses	242,350	264,271
Derivative instruments	0	20,393
Other accrued liabilities	19,087	28,993
Current portion of long-term debt	0	211,558
Total current liabilities	261,437	525,215
Noncurrent liabilities
Credit facility	1,173,175	1,173,175
Senior notes, net	913,777	916,428
Derivative instruments	0	4,649
Other noncurrent liabilities	200,015	192,091
Total noncurrent liabilities	2,286,967	2,286,343
Member’s equity:
Commitments and contingencies (Note 10)
Additional paid-in capital	2,416,381	2,315,460
Accumulated income (deficit)	2,623	(19,973)
Total member's equity	2,419,004	2,295,487
Total liabilities and member’s equity	$ 4,967,408	$ 5,107,045

Statements of Operations - USD ($) $ in Thousands		12 Months Ended
Statements of Operations - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2014	Dec. 16, 2013	Dec. 31, 2012
Successor
Revenues and other:
Oil, natural gas and natural gas liquids sales	$ 50,324	$ 1,298,402
Electricity sales	1,444	40,022
Gains (losses) on oil and natural gas derivatives	(5,049)	78,784
Marketing revenues	399	10,889
Other revenues	0	3,192
Total revenues and other	47,118	1,431,289
Expenses:
Lease operating expenses	15,410	364,540
Electricity generation expenses	1,257	28,171
Transportation expenses	2,576	41,842
Marketing expenses	376	8,084
General and administrative expenses	20,298	102,787
Exploration costs	0	0
Depreciation, depletion and amortization	10,845	302,353
Impairment of long-lived assets	0	253,362
Taxes, other than income taxes	2,130	97,708
(Gains) losses on sale of assets and other, net	10,208	120,786
Total expenses	63,100	1,319,633
Other income and (expenses)
Interest expense, net of amounts capitalized	(3,963)	(87,948)
Loss on extinguishment of debt	0	0
Other, net	(28)	(1,043)
Total other income and (expenses)	(3,991)	(88,991)
Income (loss) before income taxes	(19,973)	22,665
Income tax expense	0	69
Net income (loss)	$ (19,973)	$ 22,596
Predecessor
Revenues and other:
Oil, natural gas and natural gas liquids sales			$ 1,103,245	$ 937,261
Electricity sales			33,992	29,940
Gains (losses) on oil and natural gas derivatives			(34,711)	64,620
Marketing revenues			7,827	7,631
Other revenues			949	1,674
Total revenues and other			1,111,302	1,041,126
Expenses:
Lease operating expenses			295,811	232,266
Electricity generation expenses			22,485	19,975
Transportation expenses			46,774	39,531
Marketing expenses			7,593	6,873
General and administrative expenses			122,991	71,564
Exploration costs			24,048	21,010
Depreciation, depletion and amortization			279,757	227,700
Impairment of long-lived assets			0	0
Taxes, other than income taxes			57,063	39,757
(Gains) losses on sale of assets and other, net			(23)	(1,782)
Total expenses			856,499	656,894
Other income and (expenses)
Interest expense, net of amounts capitalized			(96,127)	(83,136)
Loss on extinguishment of debt			0	(41,545)
Other, net			51	109
Total other income and (expenses)			(96,076)	(124,572)
Income (loss) before income taxes			158,727	259,660
Income tax expense			65,280	88,121
Net income (loss)			$ 93,447	$ 171,539

Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2014	Dec. 16, 2013	Dec. 31, 2012
Successor
Net income (loss)	$ (19,973)	$ 22,596
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income tax benefit of $3,382 for the year ended December 31, 2012	0	0
Other comprehensive income	0	0
Comprehensive income (loss)	$ (19,973)	$ 22,596
Predecessor
Net income (loss)			$ 93,447	$ 171,539
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income tax benefit of $3,382 for the year ended December 31, 2012			0	5,517
Other comprehensive income			0	5,517
Comprehensive income (loss)			$ 93,447	$ 177,056

- Definition

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

+ References + Details

Statements of Comprehensive Income (Loss) Parentheticals $ in Thousands	12 Months Ended
	Dec. 31, 2013 USD ($)
Predecessor
Income tax benefit from amortization of accumulated other comprehensive loss related to de-designated hedges	$ 3,382

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, 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	0	0	3	0
Stock-based compensation expense	9,819	9,819	0	0	0	0
Income tax effect of stock option exercises	1,049	1,049	0	0	0	0
Dividends ($0.32 per share)	(17,549)	0	(17,549)	0	0	0
Net income (loss)	171,539	0	171,539	0	0	0
Amortization of accumulated other comprehensive loss related to de-designated hedges, net of income taxes	5,517	0	0	5,517	0	0
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	0	0	3	0
Stock-based compensation expense	12,576	12,576	0	0	0	0
Income tax effect of stock option exercises	2,345	2,345	0	0	0	0
Dividends ($0.32 per share)	(17,612)	0	(17,612)	0	0	0
Net income (loss)	93,447	0	93,447	0	0	0
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

- Definition

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

+ References + Details

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

Statements of Member's Equity (Successor) Statement - 12 months ended Dec. 31, 2014 - Successor - USD ($) $ in Thousands	Total	Additional Paid-in Capital	Accumulated Deficit
Balance beginning at Dec. 31, 2013	$ 2,295,487	$ 2,315,460	$ (19,973)
Capital contribution from affiliate	220,000	220,000	0
Distributions to affiliate	(119,079)	(119,079)	0
Net income (loss)	22,596	0	22,596
Balance ending at Dec. 31, 2014	$ 2,419,004	$ 2,416,381	$ 2,623

- 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. 31, 2014	Dec. 16, 2013	Dec. 31, 2012
Successor
Cash flow from operating activities:
Net income (loss)	$ (19,973)	$ 22,596
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	10,845	302,353
Impairment of long-lived assets	0	253,362
Stock-based compensation expense	0	0
Loss on extinguishment of debt	0	0
Amortization and write-off of deferred financing fees	(615)	(4,913)
Change in book overdraft	0	0
Losses on sale of assets and other, net	0	111,374
Deferred income taxes	0	69
Derivatives activities:
Total (gains) losses	5,049	(78,784)
Cash settlements	0	6,738
Cash settlements on canceled derivatives	0	12,281
Amortization of accumulated other comprehensive loss	0	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	71,434	16,483
(Increase) decrease in other assets	10,613	(15,949)
Increase (decrease) in accounts payable and accrued expenses	(8,078)	(3,719)
Increase (decrease) in other liabilities	(12,597)	(38,411)
Net cash provided by operating activities	56,678	583,480
Cash flow from investing activities:
Property acquisitions	0	0
Development of oil and natural gas properties	(17,478)	(523,889)
Proceeds from sale of properties and equipment and other	0	7,667
Net cash used in investing activities	(17,478)	(516,222)
Cash flow from financing activities:
Proceeds from borrowings	0	0
Repayments of debt	0	(206,124)
Dividends paid	(4,272)	0
Financing fees and other, net	0	(11,510)
Proceeds from stock option exercises	0	0
Capital contribution from affiliate	0	220,000
Distributions to affiliate	(435,000)	(119,079)
Excess tax benefit from stock-based compensation	0	0
Net cash provided by (used in) financing activities	(439,272)	(116,713)
Net increase (decrease) in cash and cash equivalents	(400,072)	(49,455)
Cash and cash equivalents:
Beginning	451,113	51,041
Ending	51,041	$ 1,586	$ 451,113
Predecessor
Cash flow from operating activities:
Net income (loss)			93,447	$ 171,539
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			279,757	227,700
Impairment of long-lived assets			0	0
Stock-based compensation expense			12,576	9,819
Loss on extinguishment of debt			0	6,842
Amortization and write-off of deferred financing fees			6,685	7,031
Change in book overdraft			(14,885)	(1,220)
Losses on sale of assets and other, net			14,907	12,028
Deferred income taxes			76,644	82,881
Derivatives activities:
Total (gains) losses			34,711	(64,620)
Cash settlements			182	4,927
Cash settlements on canceled derivatives			0	14,659
Amortization of accumulated other comprehensive loss			0	8,899
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net			(97,653)	(6,740)
(Increase) decrease in other assets			996	(6,203)
Increase (decrease) in accounts payable and accrued expenses			28,187	23,507
Increase (decrease) in other liabilities			7,414	10,390
Net cash provided by operating activities			442,968	501,439
Cash flow from investing activities:
Property acquisitions			(3,933)	(78,313)
Development of oil and natural gas properties			(594,579)	(693,866)
Proceeds from sale of properties and equipment and other			11,530	14,007
Net cash used in investing activities			(586,982)	(758,172)
Cash flow from financing activities:
Proceeds from borrowings			1,225,475	2,067,200
Repayments of debt			(615,200)	(1,785,799)
Dividends paid			(13,204)	(17,549)
Financing fees and other, net			(459)	(11,841)
Proceeds from stock option exercises			730	3,687
Capital contribution from affiliate			0	0
Distributions to affiliate			0	0
Excess tax benefit from stock-based compensation			2,345	1,049
Net cash provided by (used in) financing activities			599,687	256,747
Net increase (decrease) in cash and cash equivalents			455,673	14
Cash and cash equivalents:
Beginning	$ 455,985		312	298
Ending			$ 455,985	$ 312

Basis of Presentation and Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

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 December 2013. On December 16, 2013, the Company completed the 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 (see Note 2). Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, is currently the Company’s sole member.

The Company’s properties are located in the United States (“U.S.”), in California (San Joaquin Valley and Los Angeles basins), Kansas and the Oklahoma Panhandle (Hugoton Basin), Utah (Uinta Basin), east Texas and Colorado (Piceance Basin). The Company previously had properties in the Permian Basin that were divested during 2014.

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.

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’ or member’s 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 the Company 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 the Company, resulting in assets and liabilities of the Company being recorded at their fair values at December 16, 2013. See Note 2 for additional information.

The Company’s statements of operations subsequent to the transaction include 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 a 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. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU will be applied either retrospectively or as a cumulative-effect adjustment as of the date of adoption and is effective for fiscal years beginning after December 15, 2016, and interim periods within those years (early adoption prohibited). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its financial statements and related disclosures.

In April 2014, the FASB issued an ASU that changes the criteria for reporting discontinued operations and enhances disclosures in this area. This ASU is effective for annual and interim periods beginning after December 15, 2014, with early adoption permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Company early adopted this ASU on a prospective basis beginning with the third quarter of 2014. The adoption had no effect on the Company’s financial statements.

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 Company had no allowance for doubtful accounts at December 31, 2014. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $473,000 at December 31, 2013.

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 of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $6 million, $41,000, $6 million and $18 million for the year ended December 31, 2014, the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, respectively.

Impairment of Proved Properties

Based on the analysis described above, for the year ended December 31, 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $253 million associated with proved oil and natural gas properties related to the Uinta Basin operating area. The impairment was due to a steep decline in commodity prices. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas forward price curves decreased approximately 24% and 12%, respectively. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the statement of operations. 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.

Subsequent to December 31, 2014, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results of operations.

Unproved Properties

Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past.

Exploration Costs

Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded no exploration costs during the year ended December 31, 2014, or for 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 and $79,000 for the period from January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, 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 39 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 portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices.

In prior years, the Company entered into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price.

Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the balance sheets as assets and/or liabilities. In January 2010, the Company elected to prospectively discontinue 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 (as defined in Note 3) are estimated to be substantially the same as their fair values at December 31, 2014, and December 31, 2013. 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, 2014, and December 31, 2013, net deferred financing fees of approximately $12 million and $5 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 year ended December 31, 2014, the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, amortization expense of approximately $3 million, $83,000, $5 million and $5 million, respectively, is included in “interest expense, net of amounts capitalized” on the statements of operations.

Other Current Assets

The components of other current assets are as follows:



	December 31,
	2014		2013
	(in thousands)

Prepaid expenses	$	1,210	$	3,652
California carbon allowance inventories	38,409		15,895
Oil inventories	4,034		7,436
Materials inventories	1,747		3,036
Receivables from exchanges of properties and divestitures, and other	13,859		814
Other current assets	$	59,259	$	30,833

Other Accrued Liabilities

The components of other accrued liabilities are as follows:



	December 31,
	2014		2013
	(in thousands)

Accrued interest	$	15,803	$	18,926
Accrued compensation	—		6,749
Asset retirement obligations	3,101		3,318
Other	183		—
Other accrued liabilities	$	19,087	$	28,993

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. In addition, the Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses.

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 the loss of any one of its major purchasers would not have a material adverse effect on its financial condition, results of operations or net cash provided by operating activities.

For the year ended December 31, 2014, the Company’s two largest customers represented approximately 49% and 12% of the Company’s oil, natural gas and NGL sales. For the period from December 17, 2013 through December 31, 2013, the Company’s two largest customers represented approximately 50% and 10% 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% 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% of the Company’s oil, natural gas and NGL sales. For the years ended December 31, 2014, December 31, 2013, and December 31, 2012, 100% of electricity sales were attributable to two customers.

At December 31, 2014, trade accounts receivable from two customers represented approximately 36% and 10% of the Company’s receivables. At December 31, 2013, trade accounts receivable from one customer represented approximately 48% 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, 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 of producing steam. A portion of the costs of operating the cogeneration facilities is also allocated to depreciation, depletion and amortization.

Supplemental Disclosures to Statements of Cash Flows

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



	Successor				Predecessor
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31, 2012
(in thousands)
Cash payments for interest, net of amounts capitalized	$	95,915	$	—	$	87,495	$	64,602
Cash payments for income taxes	$	—	$	—	$	622	$	4,227

Noncash investing activities:
Accrued capital expenditures	$	59,884	$	77,001	$	70,866	$	98,020

On November 21, 2014, and August 15, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, completed noncash exchanges of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates in exchange for properties in California’s South Belridge Field and the Hugoton Basin, respectively.

Exchanges of Properties, Divestitures and LINN Energy Transaction	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Exchanges of Properties, Divestitures and LINN Energy Transaction	Exchanges of Properties, Divestitures and LINN Energy Transaction Exchanges of Properties On November 21, 2014, the Company, along with a subsidiary of its indirect parent LINN Energy, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation in exchange for properties in California’s South Belridge Field. The noncash exchange was accounted for at fair value and the Company recognized a net loss of approximately $30 million, equal to the difference between the carrying value and the fair value of the assets exchanged, which is included in “(gains) losses on sale of assets and other, net” on the statement of operations. On August 15, 2014, the Company, along with a subsidiary of LINN Energy, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., in exchange for properties in the Hugoton Basin. The noncash exchange was accounted for at fair value and the Company recognized a net loss of approximately $34 million, equal to the difference between the carrying value and the fair value of the assets exchanged, which is included in “(gains) losses on sale of assets and other, net” on the statement of operations. In connection with the exchanges, 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 exchange dates, while transaction and integration costs associated with the exchanges were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. LINN Energy Transaction On December 16, 2013, the Company completed the 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 was valued at approximately $4.6 billion, including the assumption of approximately $2.3 billion of Berry’s debt and net of cash acquired of approximately $451 million. 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. 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. On December 16, 2013, the Company was formed as a limited liability company and ceased to be subject to federal and state income taxes, with the exception of the state of Texas. 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 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. Divestitures On November 14, 2014, the Company, along with a subsidiary of LINN Energy, completed the sale of certain of its Wolfberry properties in Ector and Midland counties in the Permian Basin to Fleur de Lis Energy, LLC (the “Permian Basin Assets Sale”). Cash proceeds from the sale of these properties were approximately $351 million, net of costs to sell of approximately $2 million, and the Company recognized a net loss of approximately $50 million. The loss is included in “(gains) losses on sale of assets and other, net” on the statement of operations. The net cash proceeds from the Permian Basin Assets Sale were advanced by the Company to a subsidiary of LINN Energy. These proceeds must be used by LINN Energy on capital expenditures in respect of Berry’s operations, to repay Berry’s indebtedness or as otherwise permitted under the terms of Berry’s indentures and Credit Facility. On January 31, 2012, the Company completed the sale of certain properties in Elko, Eureka and Nye counties in Nevada (the “Nevada Assets”) for total cash consideration of approximately $16 million, and recognized a net gain of approximately $2 million which is included in “(gains) losses on sale of assets and other, net” on the statement of operations for the year ended December 31, 2012.

Debt

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt

The following summarizes the Company’s outstanding debt:



	December 31,
	2014		2013
	(in thousands, except percentages)

Credit facility ⁽¹⁾	$	1,173,175	$	1,173,175
10.25% senior notes due June 2014	—		205,257
6.75% senior notes due November 2020	299,970		300,000
6.375% senior notes due September 2022	599,163		600,000
Net unamortized premiums	14,644		22,729
Total debt, net	2,086,952		2,301,161
Less current maturities	—		(211,558		)
Total long-term debt, net	$	2,086,952	$	2,089,603


⁽¹⁾	Variable interest rate of 2.67% at both December 31, 2014, and December 31, 2013.

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, as defined below, 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.



	December 31, 2014				December 31, 2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)

Credit facility	$	1,173,175	$	1,173,175	$	1,173,175	$	1,173,175
Senior notes, net	913,777		699,462		1,127,986		1,128,527
Total debt, net	$	2,086,952	$	1,872,637	$	2,301,161	$	2,301,702

Credit Facility

The Company’s Second Amended and Restated Credit Agreement (“Credit Facility”) has a borrowing base of $1.4 billion, subject to lender commitments. At December 31, 2014, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit. In February 2014, the Company entered into an amendment to the Credit Facility to amend the terms of certain financial and reporting covenants, among other items. In April 2014, the Company entered into an amendment to the Credit Facility to extend the maturity date from May 2016 to April 2019 and to amend the terms of certain financial covenants and definitions, among other items.

Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. A super-majority of the lenders under the Credit Facility and Berry also have the right to request interim borrowing base redeterminations once between scheduled redeterminations. Significant declines in commodity prices may result in a decrease in the borrowing base. Berry’s obligations under the Credit Facility are secured by mortgages on its oil and natural gas properties and other personal property. Berry is required to maintain mortgages on properties representing at least 80% of the present value of its oil and natural gas proved reserves. The Company is in compliance with all financial and other covenants of the Credit Facility.

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.

The next semi-annual redetermination of the borrowing base is scheduled to occur in April 2015. Continued lower commodity prices may result in a decrease in the borrowing base at that time. In February 2015, LINN Energy and Berry entered into a parent support agreement under which LINN Energy agreed, in the event the borrowing base is reduced below the amount of borrowings outstanding, to either make principal repayments or provide additional collateral to the lenders, including through posting restricted cash on Berry’s behalf to address the shortfall, subject to LINN Energy’s credit facility.

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 including a $10 million premium which is being amortized to interest expense over the life of the related notes.

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

The Company has $599 million in aggregate principal amount of 6.375% senior notes due September 2022 (the “September 2022 Senior Notes”). The September 2022 Senior Notes were recorded at their fair value of $607 million on the acquisition date including a $7 million premium which 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 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.

Redemption and Repurchases of Senior Notes

In February 2014, in accordance with the indentures related to the senior notes, the Company repurchased through cash tender offers $321,000, $30,000 and $837,000 of its 10.25% senior notes due June 2014 (the “June 2014 Senior Notes”), November 2020 Senior Notes and September 2022 Senior Notes, respectively.

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 $215 million and $181 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.

Payment of Senior Notes Due June 2014

On May 30, 2014, in accordance with the provisions of the indenture related to its June 2014 Senior Notes, the Company paid in full the remaining outstanding principal amount of approximately $205 million using a cash capital contribution from LINN Energy (see Note 12).

Senior Notes Covenants

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 or dividends 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.

In addition, any cash generated by the Company is currently being used by the Company to fund its activities. To the extent that the Company generates cash in excess of its needs, the indentures governing its senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and the Company may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Company’s indentures. The Company’s restricted payments basket may be increased in accordance with the terms of the Company’s indentures by, among other things, 50% of the Company’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions.

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.

Income Taxes

12 Months Ended

Dec. 31, 2014

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 are reported in “income tax expense” on the statements of operations.

Income tax expense consisted of the following:



	Successor				Predecessor
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			Year Ended December 31, 2012
(in thousands)
Current taxes:
Federal	$	—	$	—	$	(225	)	$	286
State	—		—		(11,043		)	4,954
Deferred taxes:
Federal	—		—		56,620			80,083
State	69		—		19,928			2,798
	$	69	$	—	$	65,280		$	88,121

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



	Successor				Predecessor
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31, 2012

Federal statutory rate	35	%	35	%	35	%	35	%
State, net of federal tax benefit	—		—		3		3
Income excluded from nontaxable entities	(35	)	(35	)	—		—
Deferred state rate impact	—		—		—		(1	)
Research and development credits	—		—		—		(3	)
Net impact to uncertain income tax positions	—		—		(2	)	—
Transaction costs	—		—		4		—
Other	—		—		1		—
Effective rate	—	%	—	%	41	%	34	%

The effective tax rate was zero for the year ended December 31, 2014, and for the successor period from December 17, 2013 through December 31, 2013, 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 are as follows:



	Successor		Predecessor
	December 31, 2014		December 31, 2013
(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	—	$	—
Other	—		—
	—		—
Deferred tax liabilities:
Property and equipment principally due to differences in depreciation	—		—
Other	69		—
	69		—
Net deferred tax liabilities	$	69	$	—

On December 16, 2013, the Company was formed as a limited liability company and 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.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2014, the Company is in a net deferred tax liability position and has no deferred tax assets.

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



	Successor				Predecessor
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			Year Ended December 31, 2012
(in thousands)
Unrecognized tax benefits at beginning of period	$	—	$	—	$	22,553		$	2,864
Increases for positions taken in current year	—		—		50			21
Increases (decreases) for positions taken in a prior year	—		—		(635		)	20,458
Decreases for settlements with taxing authorities	—		—		—			—
Decreases for lapses in the applicable statute of limitations	—		—		(1,862		)	(790		)
Unrecognized tax benefits at end of period	$	—	$	—	$	20,106		$	22,553

In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules, and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2014, and December 31, 2013.

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 2011 – 2013 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 $2 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, 2014
Equity [Abstract]
Memeber's and Shareholders' 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
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21484-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SAB TOPIC 4.E)
-URI http://asc.fasb.org/extlink&oid=27010918&loc=d3e74512-122707

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21488-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.29-31)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 4
-Subparagraph (SAB TOPIC 4.C)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187143-122770

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 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187085-122770

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 30
-Section 50
-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
-Topic 505
-SubTopic 10
-Section 50
-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
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21463-112644

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21564-112644

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph d
-Article 4

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 29, 30, 31
-Article 5

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section E

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Article 4

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-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, 2014

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

Equity Incentive Compensation Plans and Other Benefit Plans

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.

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 and $9 million for the period from January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, 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 year ended December 31, 2012:



	Number of Shares		Weighted Average Exercise Price		Aggregate Intrinsic Value (in thousands) ⁽¹⁾		Weighted Average Remaining Contractual Term (Years)

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

Expected volatility	50.00%
Risk-free rate	0.95%
Dividend yield	0.57%
Expected term (in years)	5.2

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 year ended December 31, 2012:



	RSUs		Weighted Average Intrinsic Value at Grant Date		Vest Date Fair Value (in thousands)

Outstanding at 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 year ended December 31, 2012:



	Performance Share Awards		Weighted Average Grant Date Fair Value		Vest Date Fair Value (in thousands)

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

Number of simulations	100,000
Expected volatility	50%
Risk-free rate	0.42%

The total grant date fair value of the market-based portion of the performance share awards issued during the year ended December 31, 2012, 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 year ended December 31, 2012, were 10,758 and 12,797, 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 both the period from January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012.

At December 31, 2014, and December 31, 2013, the Company had no employees. All former employees of the Company that were retained after the LINN Energy transaction became employees of Linn Operating, Inc. (“LOI”), a subsidiary of LINN Energy, and along with other LOI personnel, 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, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

In prior years, the Company hedged a significant portion of its forecasted oil production to reduce exposure to commodity price fluctuations and provide long-term cash flow predictability to manage its business. The Company also, from time to time, entered into derivative contracts for a portion of its natural gas consumption. The direct NGL hedging market has been constrained in terms of price, volume, duration and number of counterparties, which limited the Company’s ability to effectively hedge its NGL production. As a result, the Company has not directly hedged its NGL production.

The Company entered 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 entered 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 its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

The following table summarizes derivative positions for the period indicated as of December 31, 2014:



	2015

Oil positions:
Three-way collars (NYMEX WTI):
Hedged volume (MBbls)	1,095
Short put ($/Bbl)	$	70.00
Long put ($/Bbl)	$	90.00
Short call ($/Bbl)	$	101.62

During the fourth quarter of 2014, the Company canceled all of its ICE Brent – NYMEX WTI basis swaps for 2015 and received cash settlements of approximately $12 million. Currently, the Company has no outstanding ICE Brent – NYMEX WTI basis swaps.

The Company did not enter into any commodity derivative contracts during the period from December 17, 2013 through December 31, 2013. During the period from January 1, 2013 through December 16, 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.

Settled derivatives on oil production for the year ended December 31, 2014, included volumes of 9,125 MBbls at an average contract price of $92.16 per Bbl. The oil derivatives are settled based on the average closing price of NYMEX light crude oil for each day of the delivery month.

Balance Sheet Presentation

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



	December 31,
	2014		2013
	(in thousands)
Assets:
Commodity derivatives	$	60,843	$	28,291
Liabilities:
Commodity derivatives	$	17,149	$	45,226

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, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $61 million at December 31, 2014. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Gains (Losses) on Derivatives

Gains and losses on oil and natural gas derivatives were net gains of approximately $79 million for the year ended December 31, 2014, and net losses of approximately $5 million and $35 million for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, respectively. Gains and losses on oil and natural gas derivatives were net gains of approximately $65 million for the year ended December 31, 2012. For the year ended December 31, 2014, period from January 1, 2013 through December 16, 2013, and year ended December 31, 2012, the Company received cash settlements of approximately $19 million, $182,000 and $20 million, respectively.

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. As of 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
-Topic 815
-SubTopic 30
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6441202&loc=d3e80720-113993

Reference 2: 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=35706170&loc=SL5624171-113959

Reference 3: 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=35706170&loc=d3e41620-113959

Reference 4: 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=35706170&loc=SL5624163-113959

Reference 5: 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=35706170&loc=SL5579240-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4D
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624177-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80784-113994

Reference 8: 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=35706170&loc=d3e41641-113959

Reference 9: 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=35706170&loc=SL5579245-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4H
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624258-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80748-113994

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5708775-113959

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5708773-113959

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5618551-113959

Reference 15: 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=35706170&loc=SL5580258-113959

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4E
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624181-113959

Reference 17: 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 18: 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=35706170&loc=d3e41638-113959

Reference 19: 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))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurements on a Recurring Basis

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

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).


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

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

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



	December 31, 2014
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	60,843	$	(17,149	)	$	43,694
Liabilities:
Commodity derivatives	$	17,149	$	(17,149	)	$	—



	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


⁽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

Other Property and Equipment

12 Months Ended

Dec. 31, 2014

Other Property and Equipment [Abstract]

Other Property and Equipment

Other property and equipment consists of the following:



	December 31,
	2014			2013
	(in thousands)

Plant and pipeline, drilling and other equipment	$	101,655		$	74,155
Buildings and leasehold improvements	10,585			6,515
Vehicles	3,759			2,456
	115,999			83,126
Less accumulated depreciation	(8,452		)	(233		)
	$	107,547		$	82,893

Commitments and Contingencies

12 Months Ended

Dec. 31, 2014

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 $6 million, $302,000, $5 million and $3 million for the year ended December 31, 2014, the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, respectively.

The table below presents the Company’s future minimum payments under noncancelable operating leases and other commitments as of December 31, 2014:



	Total		2015		2016		2017		2018		2019		Thereafter
(in thousands)
Operating leases⁽¹⁾	$	13,865	$	4,384	$	3,801	$	2,258	$	1,269	$	1,174	$	979
Other commitments ⁽²⁾	5,294		2,852		2,442		—		—		—		—
Firm natural gas transportation contracts⁽³⁾	180,399		33,418		33,446		33,417		23,972		22,527		33,619
Total	$	199,558	$	40,654	$	39,689	$	35,675	$	25,241	$	23,701	$	34,598


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


⁽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 is party to certain long-term natural gas gathering agreements for its East Texas production. The agreements contain embedded leases and the transaction was accounted for as a financing obligation. The fair value of the property associated with this transaction was recorded in the amount of 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 third party, by January 31, 2020, all of the interest acquired by the Company from the third party 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 entered into in April 2014, if by September 30, 2015, 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. Under the terms of the 2014 amendment, this deadline is subject to further extension to no later than December 31, 2015. 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 to the Company.

Legal Matters

Department of the Interior Notice of Proposed Debarment

In June 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 the DOI intends to make follow-up inquiries to the Company in the near future, but has not received any further communications to date.

Royalty Class Action

The Company is a defendant in a certain statewide royalty class action case. The parties entered into a settlement agreement to settle past claims for approximately $2.4 million, which the Court approved on October 29, 2014. On December 17, 2014, the Company made a one-time lump sum payment of $2.4 million for damages related to production through April 30, 2014. On December 29, 2014, the Court issued an Order dismissing the matter with prejudice. Per the parties’ settlement agreement, the Company has agreed to a new methodology for calculating royalty payments beginning May 1, 2014.

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 adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

During the year ended December 31, 2014, the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other noncurrent liabilities” on the 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
	Year Ended December 31, 2014			December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013
(in thousands)
Asset retirement obligations at beginning of period ⁽¹⁾	$	94,830		$	94,612	$	86,746
Liabilities added from drilling	5,124			—		10,097
Settlements	(5,260		)	—		(3,882		)
Liabilities added from acquisitions	25,223			—		—
Liabilities associated with assets divested	(5,460		)	—		(40		)
Current year accretion expense	5,670			218		7,136
Revision of estimates	1,633			—		5,900
Asset retirement obligations at end of period	$	121,760		$	94,830	$	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 (Notes)	12 Months Ended
Related Party Transactions (Notes)	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions LINN Energy On December 16, 2013, the Company completed the 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. All former employees of the Company that were retained after the LINN Energy transaction became employees of Linn Operating, Inc. (“LOI”), a subsidiary of LINN Energy, and along with other LOI personnel, provide services and support to the Company in accordance with an agency agreement and power of attorney between the Company and LOI. For the year ended December 31, 2014, and for the period from December 17, 2013 through December 31, 2013, the Company incurred management fee expenses of approximately $86 million and $20 million, respectively, for services provided by LOI. In May 2014, LINN Energy made a cash capital contribution of $220 million to the Company which was used to pay in full the remaining outstanding principal amount of its approximate $205 million June 2014 Senior Notes plus accrued interest. For the year ended December 31, 2014, the Company made cash distributions of approximately $119 million to LINN Energy. In addition, the net cash proceeds from the Permian Basin Assets Sale of approximately $351 million were advanced by the Company to a subsidiary of LINN Energy. These proceeds must be used by LINN Energy on capital expenditures in respect of Berry’s operations, to repay Berry’s indebtedness or as otherwise permitted under the terms of Berry’s indentures and Credit Facility. For the year ended December 31, 2014, LINN Energy incurred approximately $59 million in capital expenditures in respect of Berry’s operations, which resulted in a reduction of the advance. On December 19, 2013, the Company made a distribution of $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 had affiliated accounts payable due to LOI of approximately $13 million and $17 million at December 31, 2014, and December 31, 2013, respectively, included in “accounts payable and accrued expenses” on the balance sheets. In February 2015, LINN Energy and Berry entered into a parent support agreement under which LINN Energy agreed, in the event the borrowing base of Berry’s Credit Facility is reduced below the amount of borrowings outstanding, to either make principal repayments or provide additional collateral to the lenders, including through posting restricted cash on Berry’s behalf to address the shortfall, subject to LINN Energy’s credit facility. Other One of LINN Energy’s directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the year ended December 31, 2014, the Company paid approximately $176,000 to Superior or its subsidiaries for services rendered to the Company. The transactions associated with these payments were consummated on terms equivalent to those that prevail in arm’s-length transactions.

- 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, 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Oil & Natural Gas Data (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
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31, 2012
(in thousands)
Property acquisition costs:
Proved	$	478,311	$	—	$	3,457	$	70,700
Unproved	—		—		463		10,686
Exploration costs	148		—		868		16,405
Development costs	555,629		22,266		577,568		696,095
Asset retirement costs	6,064		—		15,998		18,248
Total costs incurred ⁽¹⁾	$	1,040,152	$	22,266	$	598,354	$	812,134


⁽¹⁾	The total above does not reflect approximately $6 million, $41,000, $6 million and $18 million of capitalized interest incurred for the year ended December 31, 2014, for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, 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:



	December 31,
	2014			2013
	(in thousands)

Oil and natural gas:
Proved properties	$	4,025,595		$	3,397,785
Unproved properties	846,464			1,415,874
	4,872,059			4,813,659
Less accumulated depletion and amortization	(525,007		)	(10,394		)
	$	4,347,052		$	4,803,265

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
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013			Year Ended December 31, 2012
(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	1,298,402	$	50,324		$	1,103,245		$	937,261
Gains (losses) on oil and natural gas derivatives	78,784		(5,049		)	(34,711		)	64,620
	1,377,186		45,275			1,068,534			1,001,881
Production costs:
Lease operating expenses	364,540		15,410			295,811			232,266
Transportation expenses	41,842		2,576			46,774			39,531
Severance taxes, ad valorem taxes and California carbon allowances	97,683		2,130			57,063			39,374
	504,065		20,116			399,648			311,171
Other costs:
Exploration costs	—		—			24,048			21,010
Depletion and amortization	294,107		10,612			275,927			224,836
Impairment of long-lived assets	253,362		—			—			—
(Gains) losses on sale of assets and other, net	112,303		10,208			(23		)	(1,782		)
	659,772		20,820			299,952			244,064
Income tax expense	69		—			65,280			88,121
Results of operations	$	213,280	$	4,339		$	303,654		$	358,525

There is no federal tax provision included in the results above for the year ended December 31, 2014, and for the period from December 17, 2013 through December 31, 2013, because the Company was not subject to federal income taxes during those periods. The income tax amount included in the results above for the year ended December 31, 2014, relates to Texas margin tax expense. Limited liability companies are subject to Texas margin tax. 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, 2014, December 31, 2013, and December 31, 2012, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the U.S., is shown below:



	Successor
	Year Ended December 31, 2014
	Oil MBbls		Natural Gas MMcf		Total MBOE

Total proved reserves:
Beginning of year	187,362		280,117		234,048
Revisions of previous estimates	(10,647	)	42,514		(3,561	)
Extensions, discoveries and other additions	20,435		35,552		26,360
Purchases of minerals in place	22,533		408,857		90,676
Sales of minerals in place	(41,216	)	(51,065	)	(49,727	)
Production	(14,065	)	(28,938	)	(18,888	)
End of year	164,402		687,037		278,908

Proved developed reserves	119,039		552,184		211,069
Proved undeveloped reserves	45,363		134,853		67,839
Total proved reserves	164,402		687,037		278,908



	Successor						Predecessor
	December 17, 2013 through December 31, 2013						January 1, 2013 through December 16, 2013
	Oil MBbls		Natural Gas MMcf		Total MBOE		Oil MBbls		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
	Oil MBbls		Natural Gas MMcf		Total MBOE

Total proved reserves:
Beginning of year	185,880		534,279		274,926
Revisions of previous estimates	12,145		(205,845	)	(22,162	)
Extensions, discoveries and other additions	8,459		100,129		25,148
Purchases of minerals in place	8,304		16,740		11,094
Sales of minerals in place	(556	)	—		(556	)
Production	(10,024	)	(19,784	)	(13,321	)
End of year	204,208		425,519		275,129

Proved developed reserves	118,937		187,668		150,216
Proved undeveloped reserves	85,271		237,851		124,913
Total proved reserves	204,208		425,519		275,129

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.

Since the reserves were estimated in accordance with SEC regulations, using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, the Company had positive price revisions for the year ended December 31, 2014, even though there was a steep decline in commodity prices during the fourth quarter of 2014. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas prices decreased approximately 42% and 30%, respectively, to $53.27 per Bbl for oil and $2.89 per MMBtu for natural gas at December 31, 2014. For information about potential risks that could affect the Company if lower commodity prices were to continue, see Item 1A. “Risk Factors.”

Proved reserves increased by approximately 44,860 MBOE to approximately 278,908 MBOE for the year ended December 31, 2014, from 234,048 MBOE for the year ended December 31, 2013. The year ended December 31, 2014, includes approximately 3,561 MBOE of negative revisions of previous estimates, due primarily to negative revisions due to asset performance and the SEC five-year development limitation on PUDs partially offset by positive revisions primarily due to higher natural gas prices. During the year ended December 31, 2014, properties acquired in the exchanges with Exxon Mobil Corporation increased proved reserves by approximately 90,676 MBOE and the Permian Basin Assets Sale and properties relinquished in the exchanges with Exxon Mobil Corporation decreased proved reserves by approximately 49,727 MBOE. In addition, extensions and discoveries, primarily from 411 productive wells drilled during the year, contributed approximately 26,360 MBOE to the increase in proved reserves. 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.

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, 2014, and 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, 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
	December 31, 2014			December 31, 2013			December 31, 2012
(in thousands)
Future estimated revenues	$	16,844,678		$	17,863,984		$	19,738,729
Future estimated production costs	(7,742,035		)	(6,654,536		)	(5,884,891		)
Future estimated development costs	(1,132,807		)	(1,854,849		)	(2,164,780		)
Future estimated income tax expense	—			—			(3,344,024		)
Future net cash flows	7,969,836			9,354,599			8,345,034
10% annual discount for estimated timing of cash flows	(3,639,459		)	(4,719,267		)	(4,511,619		)
Standardized measure of discounted future net cash flows	$	4,330,377		$	4,635,332		$	3,833,415

Representative NYMEX prices:⁽¹⁾
Oil (Bbl)	$	95.27		$	96.89		$	90.66
Natural gas (MMBtu)	4.35			3.67			2.88


⁽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
	December 31, 2014
(in thousands)
Standardized measure—beginning of year	$	4,635,332
Sales and transfers of oil, natural gas and NGL produced during the period	(794,337		)
Changes in estimated future development costs	68,290
Net change in sales and transfer prices and production costs related to future production	(1,020,605		)
Extensions, discoveries and improved recovery	674,392
Purchases of minerals in place	548,256
Sales of minerals in place	(486,903		)
Previously estimated development costs incurred during the period	269,473
Net change due to revisions in quantity estimates	(66,696		)
Accretion of discount	463,533
Changes in production rates and other	39,642
Net decrease	(304,955		)
Standardized measure—end of year	$	4,330,377



	Successor			Predecessor
	December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013
(in thousands)
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
	December 31, 2012
(in thousands)
Standardized measure—beginning of year	$	4,035,279
Sales and transfers of oil, natural gas and NGL produced during the period	(625,707		)
Changes in estimated future development costs	(331,498		)
Net change in sales and transfer prices and production costs related to future production	(786,022		)
Extensions, discoveries and improved recovery	124,466
Purchases of minerals in place	114,094
Sales of minerals in place	(15,283		)
Previously estimated development costs incurred during the period	497,036
Net change due to revisions in quantity estimates	743
Accretion of discount	570,505
Income taxes	323,128
Changes in production rates and other	(73,326		)
Net decrease	(201,864		)
Standardized measure—end of year	$	3,833,415

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

Supplemental Quarterly Data (Unaudited)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Supplemental Quarterly Data (Unaudited)

Quarterly Financial Data



	Successor
	Quarters Ended
	March 31		June 30			September 30		December 31
(in thousands)
2014:
Oil, natural gas and natural gas liquids sales	$	333,116	$	360,380		$	350,863	$	254,043
Electricity sales	9,969		10,192			11,300		8,561
Gains (losses) on oil and natural gas derivatives	3,465		(25,562		)	44,990		55,891
Total revenues and other, net	351,380		347,261			409,416		323,232
Total expenses ⁽¹⁾	244,156		240,116			225,834		488,741
Losses on sale of assets and other, net	3,367		4,257			49,011		64,151
Net income (loss)	79,698		79,008			115,165		(251,275		)



	Predecessor											Successor
	Periods Ended											Period Ended
	March 31			June 30		September 30			October 1, 2013 through December 16, 2013			December 17, 2013 through December 31, 2013
(in thousands)
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 sale of assets and other, net	(23		)	—		—			—			10,208
Net income (loss)	32,434			61,364		28,178			(28,529		)	(19,973		)


⁽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, 2014
Accounting Policies [Abstract]
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 December 2013. On December 16, 2013, the Company completed the 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 (see Note 2). Linn Acquisition Company, LLC, a direct subsidiary of LINN Energy, is currently the Company’s sole member. The Company’s properties are located in the United States (“U.S.”), in California (San Joaquin Valley and Los Angeles basins), Kansas and the Oklahoma Panhandle (Hugoton Basin), Utah (Uinta Basin), east Texas and Colorado (Piceance Basin). The Company previously had properties in the Permian Basin that were divested during 2014. 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. 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’ or member’s equity or cash flows.
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 the Company 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 the Company, resulting in assets and liabilities of the Company being recorded at their fair values at December 16, 2013. See Note 2 for additional information. The Company’s statements of operations subsequent to the transaction include 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 a different basis of accounting between the periods presented.
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. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU will be applied either retrospectively or as a cumulative-effect adjustment as of the date of adoption and is effective for fiscal years beginning after December 15, 2016, and interim periods within those years (early adoption prohibited). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its financial statements and related disclosures. In April 2014, the FASB issued an ASU that changes the criteria for reporting discontinued operations and enhances disclosures in this area. This ASU is effective for annual and interim periods beginning after December 15, 2014, with early adoption permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Company early adopted this ASU on a prospective basis beginning with the third quarter of 2014. The adoption had no effect on the Company’s financial statements.
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 Company had no allowance for doubtful accounts at December 31, 2014. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $473,000 at December 31, 2013.
Inventories	Inventories Materials, supplies and commodity inventories are valued at the lower of average cost or market. Inventories also include California carbon allowance instruments.
Oil and Natural Gas Properties	Oil and Natural Gas Properties Proved Properties The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $6 million, $41,000, $6 million and $18 million for the year ended December 31, 2014, the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, respectively. Impairment of Proved Properties Based on the analysis described above, for the year ended December 31, 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $253 million associated with proved oil and natural gas properties related to the Uinta Basin operating area. The impairment was due to a steep decline in commodity prices. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas forward price curves decreased approximately 24% and 12%, respectively. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the statement of operations. 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. Subsequent to December 31, 2014, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results of operations. Unproved Properties Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses unproved properties for impairment quarterly on the basis of its experience in similar situations and other factors such as the primary lease terms of the properties, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past. Exploration Costs Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded no exploration costs during the year ended December 31, 2014, or for 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 and $79,000 for the period from January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, 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.
Impairment of Proved Properties	Impairment of Proved Properties Based on the analysis described above, for the year ended December 31, 2014, the Company recorded noncash impairment charges, before and after tax, of approximately $253 million associated with proved oil and natural gas properties related to the Uinta Basin operating area. The impairment was due to a steep decline in commodity prices. From September 30, 2014 to December 31, 2014, NYMEX oil and natural gas forward price curves decreased approximately 24% and 12%, respectively. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the statement of operations. 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. Subsequent to December 31, 2014, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results of operations.
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 39 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	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 portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices. In prior years, the Company entered into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price. Derivative instruments (including certain derivative instruments embedded in other contracts that require bifurcation) are recorded at fair value and included on the balance sheets as assets and/or liabilities. In January 2010, the Company elected to prospectively discontinue 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 (as defined in Note 3) are estimated to be substantially the same as their fair values at December 31, 2014, and December 31, 2013. 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	Deferred Financing Fees The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2014, and December 31, 2013, net deferred financing fees of approximately $12 million and $5 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 year ended December 31, 2014, the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, amortization expense of approximately $3 million, $83,000, $5 million and $5 million, respectively, is included in “interest expense, net of amounts capitalized” on the statements of operations.
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. In addition, the Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses.
Business and Credit Concentrations	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 the loss of any one of its major purchasers would not have a material adverse effect on its financial condition, results of operations or net cash provided by operating activities. For the year ended December 31, 2014, the Company’s two largest customers represented approximately 49% and 12% of the Company’s oil, natural gas and NGL sales. For the period from December 17, 2013 through December 31, 2013, the Company’s two largest customers represented approximately 50% and 10% 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% 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% of the Company’s oil, natural gas and NGL sales. For the years ended December 31, 2014, December 31, 2013, and December 31, 2012, 100% of electricity sales were attributable to two customers. At December 31, 2014, trade accounts receivable from two customers represented approximately 36% and 10% of the Company’s receivables. At December 31, 2013, trade accounts receivable from one customer represented approximately 48% of the Company’s receivables.
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, 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 of producing steam. A portion of the costs of operating the cogeneration facilities is also allocated to depreciation, depletion and amortization.

Basis of Presentation and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Supplemental Cash Flow Disclosures

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



	Successor				Predecessor
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31, 2012
(in thousands)
Cash payments for interest, net of amounts capitalized	$	95,915	$	—	$	87,495	$	64,602
Cash payments for income taxes	$	—	$	—	$	622	$	4,227

Noncash investing activities:
Accrued capital expenditures	$	59,884	$	77,001	$	70,866	$	98,020

Other Current Assets

The components of other current assets are as follows:



	December 31,
	2014		2013
	(in thousands)

Prepaid expenses	$	1,210	$	3,652
California carbon allowance inventories	38,409		15,895
Oil inventories	4,034		7,436
Materials inventories	1,747		3,036
Receivables from exchanges of properties and divestitures, and other	13,859		814
Other current assets	$	59,259	$	30,833

Other Accrued Liabilities

The components of other accrued liabilities are as follows:



	December 31,
	2014		2013
	(in thousands)

Accrued interest	$	15,803	$	18,926
Accrued compensation	—		6,749
Asset retirement obligations	3,101		3,318
Other	183		—
Other accrued liabilities	$	19,087	$	28,993

Debt (Tables)

12 Months Ended

Dec. 31, 2014

Debt Instrument

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



	December 31,
	2014		2013
	(in thousands, except percentages)

Credit facility ⁽¹⁾	$	1,173,175	$	1,173,175
10.25% senior notes due June 2014	—		205,257
6.75% senior notes due November 2020	299,970		300,000
6.375% senior notes due September 2022	599,163		600,000
Net unamortized premiums	14,644		22,729
Total debt, net	2,086,952		2,301,161
Less current maturities	—		(211,558		)
Total long-term debt, net	$	2,086,952	$	2,089,603


⁽¹⁾	Variable interest rate of 2.67% at both December 31, 2014, and December 31, 2013.

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



	December 31, 2014				December 31, 2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)

Credit facility	$	1,173,175	$	1,173,175	$	1,173,175	$	1,173,175
Senior notes, net	913,777		699,462		1,127,986		1,128,527
Total debt, net	$	2,086,952	$	1,872,637	$	2,301,161	$	2,301,702

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	%

6.75% Senior notes due 2020

Debt Instrument

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	%

- 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=34725769&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, 2014

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

Income tax expense consisted of the following:



	Successor				Predecessor
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			Year Ended December 31, 2012
(in thousands)
Current taxes:
Federal	$	—	$	—	$	(225	)	$	286
State	—		—		(11,043		)	4,954
Deferred taxes:
Federal	—		—		56,620			80,083
State	69		—		19,928			2,798
	$	69	$	—	$	65,280		$	88,121

Schedule of Effective Income Tax Rate Reconciliation

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



	Successor				Predecessor
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31, 2012

Federal statutory rate	35	%	35	%	35	%	35	%
State, net of federal tax benefit	—		—		3		3
Income excluded from nontaxable entities	(35	)	(35	)	—		—
Deferred state rate impact	—		—		—		(1	)
Research and development credits	—		—		—		(3	)
Net impact to uncertain income tax positions	—		—		(2	)	—
Transaction costs	—		—		4		—
Other	—		—		1		—
Effective rate	—	%	—	%	41	%	34	%

Schedule of Deferred Tax Assets and Liabilities

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



	Successor		Predecessor
	December 31, 2014		December 31, 2013
(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	—	$	—
Other	—		—
	—		—
Deferred tax liabilities:
Property and equipment principally due to differences in depreciation	—		—
Other	69		—
	69		—
Net deferred tax liabilities	$	69	$	—

Summary of Income Tax Contingencies

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



	Successor				Predecessor
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013			Year Ended December 31, 2012
(in thousands)
Unrecognized tax benefits at beginning of period	$	—	$	—	$	22,553		$	2,864
Increases for positions taken in current year	—		—		50			21
Increases (decreases) for positions taken in a prior year	—		—		(635		)	20,458
Decreases for settlements with taxing authorities	—		—		—			—
Decreases for lapses in the applicable statute of limitations	—		—		(1,862		)	(790		)
Unrecognized tax benefits at end of period	$	—	$	—	$	20,106		$	22,553

Equity Incentive Compensation Plans and Other Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2014

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 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

The key assumptions used in computing the weighted average fair market value of stock options granted were as follows:



	2012

Expected volatility	50.00%
Risk-free rate	0.95%
Dividend yield	0.57%
Expected term (in years)	5.2

Schedule of Range of Exercise Prices

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

Summary of restricted stock units activity

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 year ended December 31, 2012:



	RSUs		Weighted Average Intrinsic Value at Grant Date		Vest Date Fair Value (in thousands)

Outstanding at 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 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

The key assumptions used in valuing the market-based portion of the performance share awards were as follows:



	2012

Number of simulations	100,000
Expected volatility	50%
Risk-free rate	0.42%

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of derivative instruments

The following table summarizes derivative positions for the period indicated as of December 31, 2014:



	2015

Oil positions:
Three-way collars (NYMEX WTI):
Hedged volume (MBbls)	1,095
Short put ($/Bbl)	$	70.00
Long put ($/Bbl)	$	90.00
Short call ($/Bbl)	$	101.62

Schedule of derivative assets and liabilities



	December 31,
	2014		2013
	(in thousands)
Assets:
Commodity derivatives	$	60,843	$	28,291
Liabilities:
Commodity derivatives	$	17,149	$	45,226

- 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=35706170&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=35706170&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=35706170&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=35706170&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=35706170&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=35706170&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=35706170&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=35706170&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=35706170&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, 2014

Fair Value Disclosures [Abstract]

Fair value, assets measured on recurring and nonrecurring basis

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



	December 31, 2014
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	60,843	$	(17,149	)	$	43,694
Liabilities:
Commodity derivatives	$	17,149	$	(17,149	)	$	—



	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


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

Other Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2014

Other Property and Equipment [Abstract]

Other Property and Equiment

Other property and equipment consists of the following:



	December 31,
	2014			2013
	(in thousands)

Plant and pipeline, drilling and other equipment	$	101,655		$	74,155
Buildings and leasehold improvements	10,585			6,515
Vehicles	3,759			2,456
	115,999			83,126
Less accumulated depreciation	(8,452		)	(233		)
	$	107,547		$	82,893

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Schedule of future minimum rental payments for operating leases

The table below presents the Company’s future minimum payments under noncancelable operating leases and other commitments as of December 31, 2014:



	Total		2015		2016		2017		2018		2019		Thereafter
(in thousands)
Operating leases⁽¹⁾	$	13,865	$	4,384	$	3,801	$	2,258	$	1,269	$	1,174	$	979
Other commitments ⁽²⁾	5,294		2,852		2,442		—		—		—		—
Firm natural gas transportation contracts⁽³⁾	180,399		33,418		33,446		33,417		23,972		22,527		33,619
Total	$	199,558	$	40,654	$	39,689	$	35,675	$	25,241	$	23,701	$	34,598


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


⁽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.

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Summary of change in asset retirement obligations

The following presents a reconciliation of the Company’s asset retirement obligations:



	Successor					Predecessor
	Year Ended December 31, 2014			December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013
(in thousands)
Asset retirement obligations at beginning of period ⁽¹⁾	$	94,830		$	94,612	$	86,746
Liabilities added from drilling	5,124			—		10,097
Settlements	(5,260		)	—		(3,882		)
Liabilities added from acquisitions	25,223			—		—
Liabilities associated with assets divested	(5,460		)	—		(40		)
Current year accretion expense	5,670			218		7,136
Revision of estimates	1,633			—		5,900
Asset retirement obligations at end of period	$	121,760		$	94,830	$	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.

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

12 Months Ended

Dec. 31, 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of Cost Incurred in Oil and 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
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013		Year Ended December 31, 2012
(in thousands)
Property acquisition costs:
Proved	$	478,311	$	—	$	3,457	$	70,700
Unproved	—		—		463		10,686
Exploration costs	148		—		868		16,405
Development costs	555,629		22,266		577,568		696,095
Asset retirement costs	6,064		—		15,998		18,248
Total costs incurred ⁽¹⁾	$	1,040,152	$	22,266	$	598,354	$	812,134


⁽¹⁾	The total above does not reflect approximately $6 million, $41,000, $6 million and $18 million of capitalized interest incurred for the year ended December 31, 2014, for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, respectively.

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure

Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:



	December 31,
	2014			2013
	(in thousands)

Oil and natural gas:
Proved properties	$	4,025,595		$	3,397,785
Unproved properties	846,464			1,415,874
	4,872,059			4,813,659
Less accumulated depletion and amortization	(525,007		)	(10,394		)
	$	4,347,052		$	4,803,265

Results of Operations for Oil and Gas Producing Activities Disclosure

The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below:



	Successor					Predecessor
	Year Ended December 31, 2014		December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013			Year Ended December 31, 2012
(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquid sales	$	1,298,402	$	50,324		$	1,103,245		$	937,261
Gains (losses) on oil and natural gas derivatives	78,784		(5,049		)	(34,711		)	64,620
	1,377,186		45,275			1,068,534			1,001,881
Production costs:
Lease operating expenses	364,540		15,410			295,811			232,266
Transportation expenses	41,842		2,576			46,774			39,531
Severance taxes, ad valorem taxes and California carbon allowances	97,683		2,130			57,063			39,374
	504,065		20,116			399,648			311,171
Other costs:
Exploration costs	—		—			24,048			21,010
Depletion and amortization	294,107		10,612			275,927			224,836
Impairment of long-lived assets	253,362		—			—			—
(Gains) losses on sale of assets and other, net	112,303		10,208			(23		)	(1,782		)
	659,772		20,820			299,952			244,064
Income tax expense	69		—			65,280			88,121
Results of operations	$	213,280	$	4,339		$	303,654		$	358,525

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities

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
	Year Ended December 31, 2014
	Oil MBbls		Natural Gas MMcf		Total MBOE

Total proved reserves:
Beginning of year	187,362		280,117		234,048
Revisions of previous estimates	(10,647	)	42,514		(3,561	)
Extensions, discoveries and other additions	20,435		35,552		26,360
Purchases of minerals in place	22,533		408,857		90,676
Sales of minerals in place	(41,216	)	(51,065	)	(49,727	)
Production	(14,065	)	(28,938	)	(18,888	)
End of year	164,402		687,037		278,908

Proved developed reserves	119,039		552,184		211,069
Proved undeveloped reserves	45,363		134,853		67,839
Total proved reserves	164,402		687,037		278,908



	Successor						Predecessor
	December 17, 2013 through December 31, 2013						January 1, 2013 through December 16, 2013
	Oil MBbls		Natural Gas MMcf		Total MBOE		Oil MBbls		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
	Oil MBbls		Natural Gas MMcf		Total MBOE

Total proved reserves:
Beginning of year	185,880		534,279		274,926
Revisions of previous estimates	12,145		(205,845	)	(22,162	)
Extensions, discoveries and other additions	8,459		100,129		25,148
Purchases of minerals in place	8,304		16,740		11,094
Sales of minerals in place	(556	)	—		(556	)
Production	(10,024	)	(19,784	)	(13,321	)
End of year	204,208		425,519		275,129

Proved developed reserves	118,937		187,668		150,216
Proved undeveloped reserves	85,271		237,851		124,913
Total proved reserves	204,208		425,519		275,129

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.

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

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
	December 31, 2014			December 31, 2013			December 31, 2012
(in thousands)
Future estimated revenues	$	16,844,678		$	17,863,984		$	19,738,729
Future estimated production costs	(7,742,035		)	(6,654,536		)	(5,884,891		)
Future estimated development costs	(1,132,807		)	(1,854,849		)	(2,164,780		)
Future estimated income tax expense	—			—			(3,344,024		)
Future net cash flows	7,969,836			9,354,599			8,345,034
10% annual discount for estimated timing of cash flows	(3,639,459		)	(4,719,267		)	(4,511,619		)
Standardized measure of discounted future net cash flows	$	4,330,377		$	4,635,332		$	3,833,415

Representative NYMEX prices:⁽¹⁾
Oil (Bbl)	$	95.27		$	96.89		$	90.66
Natural gas (MMBtu)	4.35			3.67			2.88


⁽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.

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

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



	Successor
	December 31, 2014
(in thousands)
Standardized measure—beginning of year	$	4,635,332
Sales and transfers of oil, natural gas and NGL produced during the period	(794,337		)
Changes in estimated future development costs	68,290
Net change in sales and transfer prices and production costs related to future production	(1,020,605		)
Extensions, discoveries and improved recovery	674,392
Purchases of minerals in place	548,256
Sales of minerals in place	(486,903		)
Previously estimated development costs incurred during the period	269,473
Net change due to revisions in quantity estimates	(66,696		)
Accretion of discount	463,533
Changes in production rates and other	39,642
Net decrease	(304,955		)
Standardized measure—end of year	$	4,330,377



	Successor			Predecessor
	December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013
(in thousands)
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
	December 31, 2012
(in thousands)
Standardized measure—beginning of year	$	4,035,279
Sales and transfers of oil, natural gas and NGL produced during the period	(625,707		)
Changes in estimated future development costs	(331,498		)
Net change in sales and transfer prices and production costs related to future production	(786,022		)
Extensions, discoveries and improved recovery	124,466
Purchases of minerals in place	114,094
Sales of minerals in place	(15,283		)
Previously estimated development costs incurred during the period	497,036
Net change due to revisions in quantity estimates	743
Accretion of discount	570,505
Income taxes	323,128
Changes in production rates and other	(73,326		)
Net decrease	(201,864		)
Standardized measure—end of year	$	3,833,415

- 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=34713648&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

Supplemental Quarterly Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data



	Successor
	Quarters Ended
	March 31		June 30			September 30		December 31
(in thousands)
2014:
Oil, natural gas and natural gas liquids sales	$	333,116	$	360,380		$	350,863	$	254,043
Electricity sales	9,969		10,192			11,300		8,561
Gains (losses) on oil and natural gas derivatives	3,465		(25,562		)	44,990		55,891
Total revenues and other, net	351,380		347,261			409,416		323,232
Total expenses ⁽¹⁾	244,156		240,116			225,834		488,741
Losses on sale of assets and other, net	3,367		4,257			49,011		64,151
Net income (loss)	79,698		79,008			115,165		(251,275		)



	Predecessor											Successor
	Periods Ended											Period Ended
	March 31			June 30		September 30			October 1, 2013 through December 16, 2013			December 17, 2013 through December 31, 2013
(in thousands)
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 sale of assets and other, net	(23		)	—		—			—			10,208
Net income (loss)	32,434			61,364		28,178			(28,529		)	(19,973		)


⁽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)			3 Months Ended	12 Months Ended
	Dec. 31, 2013 USD ($)	Dec. 16, 2013 shares	Dec. 31, 2014 USD ($)	Dec. 31, 2014 USD ($) Cogeneration_facilities	Dec. 31, 2013 USD ($)	Dec. 16, 2013 USD ($)	Dec. 31, 2012 USD ($)
Accounting Policies
Impairment of Leasehold						$ 16,000,000	$ 0
Allowance for doubtful accounts receivable	$ 473,000		$ 0	$ 0	$ 473,000
Decline in forward oil prices			24.00%
Decline in forward gas prices			12.00%
Deferred financing fees	5,000,000		$ 12,000,000	12,000,000	$ 5,000,000
Amortization of deferred financing fees	$ 83,000			$ 3,000,000		$ 5,000,000	5,000,000
Number of cogeneration facilities (in ones) \| Cogeneration_facilities				3
Results of Operations, Dry Hole Costs							15,000,000
Plugging and Abandonment Expense							$ 4,000,000
Minimum \| Buildings and leasehold improvements
Accounting Policies
Property, plant and equipment, useful life				10 years
Minimum \| Plant and pipeline, drilling and other equipment
Accounting Policies
Property, plant and equipment, useful life				2 years
Maximum \| Buildings and leasehold improvements
Accounting Policies
Property, plant and equipment, useful life				39 years
Maximum \| Plant 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%
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 \| Oil, natural gas and NGL sales
Accounting Policies
Concentration risk, percentage	10.00%			12.00%		10.00%	13.00%
Major Customer 1 \| Oil, natural gas and NGL sales
Accounting Policies
Concentration risk, percentage	50.00%			49.00%		45.00%	43.00%
Successor
Accounting Policies
Capitalized interest	$ 41,000			$ 6,000,000
Impairment of long-lived assets	0			253,362,000
Exploration costs	$ 0			$ 0
Predecessor
Accounting Policies
Capitalized interest						$ 6,000,000	$ 18,000,000
Impairment of long-lived assets						0	0
Exploration costs						$ 24,048,000	$ 21,010,000
Credit Concentration Risk [Member] \| Major Customer 2
Accounting Policies
Concentration risk, percentage				10.00%
Credit Concentration Risk [Member] \| Major Customer 1
Accounting Policies
Concentration risk, percentage				36.00%	48.00%

Basis of Presentation and Significant Accounting Policies (Other Current Assets) (Details) - Successor - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Other Current Assets [Line Items]
Prepaid expenses	$ 1,210	$ 3,652
California carbon allowance inventories	38,409	15,895
Oil inventories	4,034	7,436
Materials inventories	1,747	3,036
Receivables from exchanges of properties and divestitures, and other	13,859	814
Other current assets	$ 59,259	$ 30,833

Basis of Presentation and Significant Accounting Policies (Other Accrued Liabilities) (Details) - Successor - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Accrued interest	$ 15,803	$ 18,926
Accrued compensation	0	6,749
Asset retirement obligations	3,101	3,318
Other	183	0
Other accrued liabilities	$ 19,087	$ 28,993

Basis of Presentation and Significant Accounting Policies (Supplemental Cash Flow Data) (Details) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2014	Dec. 16, 2013	Dec. 31, 2012
Successor
Supplemental disclosures to the statements of cash flows [Line Items]
Cash payments for interest, net of amounts capitalized	$ 0	$ 95,915
Cash payments for income taxes	0	0
Accrued capital expenditures	$ 77,001	$ 59,884
Predecessor
Supplemental disclosures to the statements of cash flows [Line Items]
Cash payments for interest, net of amounts capitalized			$ 87,495	$ 64,602
Cash payments for income taxes			622	4,227
Accrued capital expenditures			$ 70,866	$ 98,020

LINN Energy Transaction (Details) - USD ($) $ in Millions			12 Months Ended
LINN Energy Transaction (Details) - USD ($) $ in Millions	Dec. 31, 2013	Dec. 16, 2013	Dec. 16, 2013
LINN Energy Merger, Acquisitions, and Divestitures
Business Combination, Acquisition Related Costs	$ 16		$ 45
Linn Merger
LINN Energy Merger, Acquisitions, and Divestitures
Preliminary value of acquisition		$ 4,600
Long-term debt assumed		2,300	2,300
Cash acquired		$ 451	$ 451
Berry and LinnCo
LINN Energy Merger, Acquisitions, and Divestitures
Exchange ratio		168.00%
Number of shares issued in merger		93,756,674
Linn Energy LLC and LinnCo
LINN Energy Merger, Acquisitions, and Divestitures
Exchange ratio		100.13%
Number of shares issued in merger		93,756,674

Acquisitions and Divestitures (Details ) a in Thousands, $ in Millions				3 Months Ended	12 Months Ended
	Sep. 12, 2012 USD ($) a	Apr. 13, 2012 USD ($) a Wells	Jan. 31, 2012 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2014 USD ($)
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
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
Purchase price paid, net of customary post-closing adjustments	$ 40
Exxon Exchange II [Member]
LINN Energy Merger, Acquisitions, and Divestitures
Gain (loss) on sale of oil and natural gas property			$ 30
Exxon Exchange I [Member]
LINN Energy Merger, Acquisitions, and Divestitures
Gain (loss) on sale of oil and natural gas property			34
Permian basin assets [Member]
LINN Energy Merger, Acquisitions, and Divestitures
Proceeds from sale of assets			351		$ 351
Costs associated with the sale of oil and natural gas property and equipment				$ 2
Gain (loss) on sale of oil and natural gas property			50
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

Debt (Details) - USD ($) $ in Millions	12 Months Ended
Debt (Details) - USD ($) $ in Millions	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument
Remaining borrowing capacity available under the agreement	$ 1
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%
Credit Facility
Debt Instrument
Credit facility, maximum borrowing capacity	$ 1,400
Line of Credit Facility, Current Borrowing Capacity	$ 1,200
6.75% Senior notes due 2020
Debt Instrument
Interest rate on debt instrument (as a percent)	6.75%
6.375% Senior notes due 2022
Debt Instrument
Interest rate on debt instrument (as a percent)	6.375%
Minimum \| Credit Facility
Debt Instrument
Credit facility, unused capacity, commitment fee percentage	0.375%
Maximum \| Credit Facility
Debt Instrument
Credit facility, unused capacity, commitment fee percentage	0.50%
Credit Facility
Debt Instrument
Credit facility, variable interest rate	2.67%	2.67%
London Interbank Offered Rate (LIBOR) [Member] \| Minimum \| Credit Facility
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)	1.50%
London Interbank Offered Rate (LIBOR) [Member] \| Maximum \| Credit Facility
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)	2.50%
Base Rate [Member] \| Minimum \| Credit Facility
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)	0.50%
Base Rate [Member] \| Maximum \| Credit Facility
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)	1.50%

Debt 6.75% Senior Notes Due 2020 (Details) - 6.75% Senior notes due 2020 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 16, 2013
Debt Instrument
Interest rate on debt instrument (as a percent)	6.75%
Senior notes	$ 300
Long-term debt, fair value		$ 310
Net unamortized premiums		$ 10
Debt instrument redemption price percentage of principal amount plus make whole premium and accrued and unpaid interest	100.00%
November 1, 2015 through October 31, 2016
Debt Instrument
Debt Instrument, Redemption Price, Percentage	103.375%
November 1, 2016 through October 31, 2017
Debt Instrument
Debt Instrument, Redemption Price, Percentage	102.25%
November 1, 2017 through October 31, 2018
Debt Instrument
Debt Instrument, Redemption Price, Percentage	101.125%
November 1, 2018 and thereafter
Debt Instrument
Debt Instrument, Redemption Price, Percentage	100.00%

Debt 6.375% Senior Notes Due 2022 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 16, 2013
Debt Instrument
Percent of future net income allowable to increase Berry's restricted payments basket	50.00%
6.375% Senior notes due 2022
Debt Instrument
Interest rate on debt instrument (as a percent)	6.375%
Senior notes	$ 599
Long-term debt, fair value		$ 607
Net unamortized premiums		$ 7
March 9, 2012 Through March 14, 2015 \| 6.375% Senior notes due 2022
Debt Instrument
Debt Instrument, Redemption Price, Percentage	106.375%
Debt instrument redemption percentage, maximum	35.00%
March 15, 2017 through March 14, 2018 \| 6.375% Senior notes due 2022
Debt Instrument
Debt Instrument, Redemption Price, Percentage	103.188%
March 15, 2018 through March 14, 2019 \| 6.375% Senior notes due 2022
Debt Instrument
Debt Instrument, Redemption Price, Percentage	102.125%
March 15, 2019 through March 14, 2020 \| 6.375% Senior notes due 2022
Debt Instrument
Debt Instrument, Redemption Price, Percentage	101.063%
March 15, 2020 and thereafter \| 6.375% Senior notes due 2022
Debt Instrument
Debt Instrument, Redemption Price, Percentage	100.00%
March 9, 2012 through March 14, 2017 \| 6.375% Senior notes due 2022
Debt Instrument
Debt Instrument, Redemption Price, Percentage	100.00%
Minimum \| 6.375% Senior notes due 2022
Debt Instrument
Senior Notes Redemption Price, Notice Period Range in Days	30 days
Maximum \| 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 Thousands	1 Months Ended
	Feb. 28, 2014	Apr. 30, 2012	Dec. 31, 2014	May 30, 2014
Debt Instrument
Percent of future net income allowable to increase Berry's restricted payments basket			50.00%
8.25% Senior subordinated notes due 2016
Debt Instrument
Interest rate on debt instrument (as a percent)			8.25%
Debt repurchase amount		$ 200,000
Subordinated debt aggregate purchase price		215,000
Loss on extinguishment of debt		(42,000)
Write off of deferred debt issuance cost		7,000
10.25% Senior notes due 2014
Debt Instrument
Interest rate on debt instrument (as a percent)			10.25%
Debt repurchase amount	$ 321,000	150,000
Unsecured debt aggregate purchase price		181,000
Senior notes, net				$ 205,000
6.75% Senior notes due 2020
Debt Instrument
Interest rate on debt instrument (as a percent)			6.75%
Debt repurchase amount	30,000
6.375% Senior notes due 2022
Debt Instrument
Interest rate on debt instrument (as a percent)			6.375%
Debt repurchase amount	$ 837,000
Premium paid over par \| 8.25% Senior subordinated notes due 2016
Debt Instrument
Loss on extinguishment of debt		$ (35,000)

Debt Debt schedule of long term debt (Details) - USD ($)
$ in Thousands

Dec. 31, 2014

May 30, 2014

Dec. 31, 2013

Dec. 16, 2013

10.25% Senior notes due 2014

Debt Instrument

Senior notes, net

$ 205,000

6.75% Senior notes due 2020

Debt Instrument

Net unamortized premiums

$ 10,000

6.375% Senior notes due 2022

Debt Instrument

Net unamortized premiums

$ 7,000

Successor

Debt Instrument

Credit facility

^[1]

$ 1,173,175

Senior notes, net

913,777

1,127,986

Net unamortized premiums

14,644

22,729

Total debt, net

2,086,952

2,301,161

Less current maturities

211,558

Total long-term debt, net

2,086,952

2,089,603

Successor | 10.25% Senior notes due 2014

Debt Instrument

Senior notes, net

205,257

Successor | 6.75% Senior notes due 2020

Debt Instrument

Senior notes, net

299,970

300,000

Successor | 6.375% Senior notes due 2022

Debt Instrument

Senior notes, net

$ 599,163

$ 600,000

[1]	Variable interest rate of 2.67% at both December 31, 2014, and December 31, 2013.

Debt Debt fair value disclosure (Details) - Successor - USD ($)
$ in Thousands

Dec. 31, 2014

Dec. 31, 2013

Carrying Value

Credit facility

^[1]

$ 1,173,175

Senior notes, net

913,777

1,127,986

Total debt, net

2,086,952

2,301,161

Fair Value

Credit facility

1,173,175

Senior notes, net

699,462

1,128,527

Total debt, net

$ 1,872,637

$ 2,301,702

[1]	Variable interest rate of 2.67% at both December 31, 2014, and December 31, 2013.

- Definition

The carrying value as of the balance sheet date of the current and noncurrent portions of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

+ References + Details

Income Taxes (Details) - USD ($)	12 Months Ended
Income Taxes (Details) - USD ($)	Dec. 16, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Contingency [Line Items]
Deferred Tax Liabilities, Net		$ 69,000	$ 0	$ 256,000,000
Liability for Uncertain Tax Positions, Noncurrent		$ 0	$ 0
Unrecognized tax benefits, period decrease	$ 2,000,000
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. 31, 2014	Dec. 16, 2013	Dec. 31, 2012
Successor
Current taxes:
Federal	$ 0	$ 0
State	0	0
Deferred taxes:
Federal	0	0
State	0	69
Income tax expense	$ 0	$ 69
Predecessor
Current taxes:
Federal			$ (225)	$ 286
State			(11,043)	4,954
Deferred taxes:
Federal			56,620	80,083
State			19,928	2,798
Income tax expense			$ 65,280	$ 88,121

Income Taxes (Schedule of Effective Income Tax Rate Reconciliation) (Details)		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2014	Dec. 16, 2013	Dec. 31, 2012
Successor
Reconciliation of the federal statutory tax rate to the effective tax rate
Federal statutory rate	35.00%	35.00%
State, net of federal tax benefit	0.00%	0.00%
Income excluded from nontaxable entities	(35.00%)	(35.00%)
Deferred state rate impact	0.00%	0.00%
Research and development credits	(0.00%)	(0.00%)
Net impact to uncertain income tax positions	0.00%	0.00%
Transaction costs	0.00%	0.00%
Other	0.00%	0.00%
Effective rate	0.00%	0.00%
Predecessor
Reconciliation of the federal statutory tax rate to the effective tax rate
Federal statutory rate			35.00%	35.00%
State, net of federal tax benefit			3.00%	3.00%
Income excluded from nontaxable entities			(0.00%)	(0.00%)
Deferred state rate impact			0.00%	(1.00%)
Research and development credits			(0.00%)	(3.00%)
Net impact to uncertain income tax positions			(2.00%)	0.00%
Transaction costs			4.00%	0.00%
Other			1.00%	0.00%
Effective rate			41.00%	34.00%

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Deferred tax assets:
Net operating loss carryforwards	$ 0	$ 0
Other	0	0
Deferred tax assets, gross	0	0
Deferred tax liabilities:
Property and equipment principally due to differences in depreciation	0	0
Other	69	0
Deferred tax liabilities, gross	69	0
Net deferred tax liabilities	$ 69	$ 0	$ 256,000

Income Taxes (Summary of Income Tax Contingencies) (Details) - USD ($)		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2014	Dec. 16, 2013	Dec. 31, 2012
Successor
Income Tax Contingency [Line Items]
Unrecognized tax benefits at beginning of period		$ 0
Increases for positions taken in current year	$ 0	0
Increases (decreases) for positions taken in a prior year	0	0
Decreases for settlements with taxing authorities	0	0
Decreases for lapses in the applicable statute of limitations	0	0
Unrecognized tax benefits at end of period	0	$ 0
Predecessor
Income Tax Contingency [Line Items]
Unrecognized tax benefits at beginning of period	$ 20,106,000		$ 22,553,000	$ 2,864,000
Increases for positions taken in current year			50,000	21,000
Increases (decreases) for positions taken in a prior year				20,458,000
Increases (decreases) for positions taken in a prior year			(635,000)
Decreases for settlements with taxing authorities			0	0
Decreases for lapses in the applicable statute of limitations			(1,862,000)	(790,000)
Unrecognized tax benefits at end of period			$ 20,106,000	$ 22,553,000

Member's and Shareholders' Equity (Details) - USD ($)	12 Months Ended
Member's and Shareholders' Equity (Details) - USD ($)	Dec. 16, 2013	Dec. 31, 2012
Common Class A
Class of Stock [Line Items]
Common stock, voting rights	1
Common Class B
Class of Stock [Line Items]
Common stock, voting rights	.95
Common stock liquidation preference value	$ 0.50
Conversion of stock, shares	1
Predecessor
Class of Stock [Line Items]
Dividends per share	$ 0.32	$ 0.32
Dividend payments limited by covenants in Credit Facility
Class of Stock [Line Items]
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
Class of Stock [Line Items]
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

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	May 31, 2010	May 31, 2005
Share-based Compensation Arrangement by Share-based Payment Award
Company's contributions to 401(k) Plan, net of forfeitures		$ 2	$ 2
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grant Date Fair Value , Determined by Monte Carlo Valuation Model			1
Term of options granted under plan		10 years
Total compensation cost		$ 12	$ 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

Number of Shares

Outstanding shares at the beginning of the period

1,387,592.000

1,520,689

Shares granted

82,262

Shares exercised

(57,350)

(215,359)

Outstanding shares at the end of the period

1,330,242.000

1,387,592.000

Vested and expected to vest at December 16, 2013

1,328,771

Exercisable at December 16, 2013

1,224,022

Weighted Average Exercise Price

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

$ 33.71

$ 30.32

Granted (in dollars per share)

53.02

Exercised (in dollars per share)

12.74

17.12

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

$ 34.61

34.61

$ 33.71

Vested and expected to vest at December 16, 2013

34.60

Exercisable at December 16, 2013

$ 33.18

Aggregate Intrinsic Value (in thousands) (1)

Outstanding at the beginning of the period

^[1]

$ 4,681

$ 17,798

Exercised

^[1]

2,066

7,194

Outstanding at the end of the period

^[1]

$ 19,243

19,243

$ 4,681

Vested and expected to vest at December 16, 2014

^[1]

19,243

Exercisable at December 16, 2013

^[1]

$ 19,229

Weighted Average Remaining Contractual Term (Years)

Outstanding at December 16, 2013

3 years 2 months 16 days

Vested and expected to vest at December 16, 2013

3 years 2 months 16 days

Exercisable at December 16, 2013

2 years 9 months 23 days

Employee Stock Option [Member]

Share-based Compensation Arrangement by Share-based Payment Award

Expected term (in years)

5 years 2 months

Dividend yield

0.57%

Risk-free rate

0.95%

Expected volatility

50.00%

[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
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Number of Options	1,330,242	1,330,242
Weighted Average Remaining Contractual Term (Years)	3 years 2 months 16 days
Weighted Average Exercise Price	$ 34.61	$ 34.61	$ 33.71	$ 30.32
Number of Options	1,224,022	1,224,022
Weighted Average Remaining Contractual Term (Years)	2 years 9 months 23 days
Weighted Average Exercise Price	$ 33.18	$ 33.18
Exercise Prices 21.58 to 21.77
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Number of Options	240,000	240,000
Weighted Average Remaining Contractual Term (Years)		10 months 24 days
Weighted Average Exercise Price	$ 21.60	$ 21.60
Number of Options	240,000	240,000
Weighted Average Remaining Contractual Term (Years)		10 months 24 days
Weighted Average Exercise Price	$ 21.60	$ 21.60
Exercise Prices 30.65 to 32.57
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Number of Options	639,000	639,000
Weighted Average Remaining Contractual Term (Years)		2 years 6 months
Weighted Average Exercise Price	$ 31.70	$ 31.70
Number of Options	639,000	639,000
Weighted Average Remaining Contractual Term (Years)		2 years 6 months
Weighted Average Exercise Price	$ 31.70	$ 31.70
Exercise Prices 38.00 to 53.02
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range
Number of Options	451,242	451,242
Weighted Average Remaining Contractual Term (Years)		5 years 5 months 4 days
Weighted Average Exercise Price	$ 45.66	$ 45.66
Number of Options	345,022	345,022
Weighted Average Remaining Contractual Term (Years)		4 years 8 months 16 days
Weighted Average Exercise Price	$ 43.98	$ 43.98

Equity Incentive Compensation Plans (Restricted Stock Units and Performance Share Program) (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 16, 2013 USD ($) $ / shares shares	Dec. 31, 2012 USD ($) $ / shares shares
Restricted Stock Units (RSUs) [Member]
Performance Share Awards
Outstanding shares at the beginning of the period \| shares	981,877	915,022.000
Granted \| shares	286,344	164,112
Issued \| shares	(853,169)	(79,068)
Canceled/expired \| shares	(22,511)	(18,189)
Outstanding shares at the end of the period \| shares	392,541	981,877
Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per share) \| $ / shares	$ 26.72	$ 23.88
Granted (in dollars per share) \| $ / shares	45.51	50.60
Issued (in dollars per share) \| $ / shares	23.94	33.10
Canceled/expired (in dollars per share) \| $ / shares	44.69	41.50
Outstanding at the end of the period (in dollars per share) \| $ / shares	$ 46.86	$ 26.72
Vest Date Fair Value
Issued \| $	$ 39,513	$ 3,401
Performance Shares [Member]
Performance Share Awards
Outstanding shares at the beginning of the period \| shares	222,587.000	162,849.000
Granted \| shares		59,738
Issued \| shares	(135,167)
Canceled/expired \| shares	(87,420)
Outstanding shares at the end of the period \| shares	0	222,587.000
Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per share) \| $ / shares	$ 45.79	$ 39.00
Granted (in dollars per share) \| $ / shares		63.69
Issued (in dollars per share) \| $ / shares	44.33
Canceled/expired (in dollars per share) \| $ / shares	44.42
Outstanding at the end of the period (in dollars per share) \| $ / shares	$ 0.00	$ 45.79
Vest Date Fair Value
Issued \| $	$ 6,308
Number of simulations		100,000
Expected volatility		50.00%
Risk-free rate		0.42%

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
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
Maximum
Other employee benefits—401(k) plan
Company match of employee's eligible compensation (as a percent)	8.00%
Director [Member]
Director fees
Shares earned and deferred in accordance with the plan (in shares)	10,758	12,797

Derivative Instruments Derivative Instruments (Commodity Derivatives) (Details) - 2015 - Oil Derivative Instruments - Three-way collars (NYMEX WTI)	Dec. 31, 2014 MBbl $ / bbl
Derivative [Line Items]
Annual Hedged Volume (in energy unit) \| MBbl	1,095
Short
Derivative [Line Items]
Derivative, Floor Price	70.00
Derivative, Cap Price	101.62
Long
Derivative [Line Items]
Derivative, Floor Price	90.00

Derivative Instruments (Details) $ in Thousands		3 Months Ended								12 Months Ended
Derivative Instruments (Details) $ in Thousands	Dec. 31, 2013 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 16, 2013 USD ($)	Sep. 30, 2013 USD ($)	Jun. 30, 2013 USD ($)	Mar. 31, 2013 USD ($)	Dec. 31, 2014 USD ($) MBbl $ / bbl	Dec. 16, 2013 USD ($)	Dec. 31, 2012 USD ($)
Derivative Asset [Abstract]
Commodity derivatives	$ 28,291	$ 60,843								$ 60,843
Derivative Liability [Abstract]
Commodity derivatives	45,226	17,149								17,149
Oil, natural gas and NGL sales \| Commodity contract
Derivative Liability [Abstract]
Amortization of AOCL into earnings												$ 11,000
Interest expense \| Interest rate contract
Derivative Liability [Abstract]
Amortization of AOCL into earnings												2,000
Successor
Derivative Asset [Abstract]
Commodity derivatives		60,843								60,843
Derivative Liability [Abstract]
Commodity derivatives		17,149								17,149
Cash settlements on canceled derivatives	0	12,281								$ 12,281
Derivative, Nonmonetary Notional Amount, Volume \| MBbl										9,125
Maximum loss upon all counterparties failing to perform										$ 61,000
Gains (losses) on oil and natural gas derivatives	(5,049)	$ 55,891	$ 44,990	$ (25,562)	$ 3,465					78,784
Cash settlements on derivatives inclusive of canceled derivatives										$ 19,000
Average contract price on oil settled derivatives per unit \| $ / bbl										92.16
Predecessor
Derivative Asset [Abstract]
Commodity derivatives	28,291
Derivative Liability [Abstract]
Commodity derivatives	$ 45,226
Cash settlements on canceled derivatives											$ 0	14,659
Gains (losses) on oil and natural gas derivatives						$ (24,303)	$ (45,293)	$ 35,622	$ (737)		(34,711)	64,620
Cash settlements on derivatives inclusive of canceled derivatives											$ 182	$ 20,000

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

Dec. 31, 2014

Dec. 31, 2013

Derivative Asset [Abstract]

Commodity derivatives

$ 60,843

$ 28,291

Commodity derivatives

^[1]

(17,149)

(20,184)

Commodity derivatives

43,694

8,107

Derivative Liability [Abstract]

Commodity derivatives

17,149

45,226

Commodity derivatives

^[1]

(17,149)

(20,184)

Commodity derivatives

$ 0

$ 25,042

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

Other Property and Equipment (Details) - Successor - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 115,999	$ 83,126
Less accumulated depreciation	(8,452)	(233)
Other property and equipment, net	107,547	82,893
Plant and pipeline, drilling and other equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	101,655	74,155
Buildings and leasehold improvements
Property, Plant and Equipment [Line Items]
Other property and equipment	10,585	6,515
Vehicles
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 3,759	$ 2,456

Commitments and Contingencies (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2014

Dec. 16, 2013

Dec. 31, 2012

Operating leases

$ 302

$ 6,000

$ 5,000

$ 3,000

Operating Leases, Future Minimum Payments Due

Operating leases, future minimum payments due

^[1]

13,865

Operating leases, future minimum payments due, current

^[1]

4,384

Operating leases, future minimum payments, due in two years

^[1]

3,801

Operating leases, future minimum payments, due in three years

^[1]

2,258

Operating leases, future minimum payments, due in four years

^[1]

1,269

Operating leases, future minimum payments, due in five years

^[1]

1,174

Operating leases, future minimum payments, due after fifth year

^[1]

979

Recorded Unconditional Purchase Obligation and Operating Leases, Future Minimum Payments Due

Unrecorded unconditional purchase obligation and operating leases, future minimum payments due

199,558

Unrecorded unconditional purchase obligation and operating leases, future minimum payments due, current

40,654

Unrecorded unconditional purchase obligation and operating leases, future minimum payments due in second year

39,689

Unrecorded unconditional purchase obligation and operating leases, future minimum payments due in third year

35,675

Unrecorded unconditional purchase obligation and operating leases, future minimum payments due in fourth year

25,241

Unrecorded unconditional purchase obligation and operating leases, future minimum payments due in fifth year

23,701

Unrecorded unconditional purchase obligation and operating leases, future minimum payments due after fifth year

34,598

Other commitments

Unrecorded Unconditional Purchase Obligation Payment Schedule

Unrecorded unconditional purchase obligation due

^[2]

5,294

Unrecorded unconditional purchase obligation due, current

^[2]

2,852

Unrecorded unconditional purchase obligation due in second year

^[2]

2,442

Unrecorded unconditional purchase obligation due in third year

^[2]

Unrecorded unconditional purchase obligation due in fourth year

^[2]

Unrecorded unconditional purchase obligation due in fifth year

^[2]

Unrecorded unconditional purchase obligation due after fifth year

^[2]

Firm natural gas transportation contracts

Unrecorded Unconditional Purchase Obligation Payment Schedule

Unrecorded unconditional purchase obligation due

^[3]

180,399

Unrecorded unconditional purchase obligation due, current

^[3]

33,418

Unrecorded unconditional purchase obligation due in second year

^[3]

33,446

Unrecorded unconditional purchase obligation due in third year

^[3]

33,417

Unrecorded unconditional purchase obligation due in fourth year

^[3]

23,972

Unrecorded unconditional purchase obligation due in fifth year

^[3]

22,527

Unrecorded unconditional purchase obligation due after fifth year

^[3]

$ 33,619

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

Commitments and Contingencies Commitments and Contingencies 2 (Details)		12 Months Ended
	Dec. 31, 2013 USD ($)	Dec. 31, 2014 USD ($)	Dec. 16, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Apr. 22, 2014 USD ($)	Jan. 14, 2011 USD ($) a
Loss Contingencies [Line Items]
Gathering System, Fair Value		$ 13,000,000
Accrual for Environmental Loss Contingencies		0
Litigation Settlement, Amount		2,400,000
Payments for Legal Settlements		2,400,000
Material payments for legal environmental or tax settlements	$ 0	$ 0	$ 0	$ 0
Carry And Earning Agreement [Member]
Loss Contingencies [Line Items]
Contractual Obligation Amount, Penalty Waived Per Well							$ 200,000
Contractual Obligation, Acre Of Tracts \| a							160
Contractual Obligation, Contingent Construction Expense						$ 9,000,000
Third Party Share of Construction Costs, Percentage							50.00%
Contractual Obligation, Penalty as Percentage of Difference Between Specified Amount and Actual Expended						50.00%
Contractual Obligation, Specified Amount for Penalty Calculation						$ 12,000,000
Non Compliance To Regulations [Member]
Loss Contingencies [Line Items]
Litigation Settlement, Expense					$ 2,000,000

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2014

Dec. 16, 2013

Successor

Asset Retirement Obligations [Line Items]

Asset retirement obligations at beginning of year

^[1]

$ 94,830

Liabilities added from drilling

$ 0

5,124

Settlements

(5,260)

Liabilities added from acquisitions

25,223

Liabilities associated with assets divested

5,460

Current year accretion expense

218

5,670

Revision of estimates

$ 1,633

Asset retirement obligations at end of period

^[1]

94,830

Predecessor

Asset Retirement Obligations [Line Items]

Asset retirement obligations at beginning of year

^[1]

$ 105,957

$ 86,746

Liabilities added from drilling

10,097

Settlements

(3,882)

Liabilities added from acquisitions

Liabilities associated with assets divested

Current year accretion expense

7,136

Revision of estimates

5,900

Asset retirement obligations at end of period

^[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 ($)				1 Months Ended	12 Months Ended
Related Party Transactions (Details) - USD ($)	Dec. 31, 2013	Dec. 16, 2013	Jan. 31, 2012	May 31, 2014	Dec. 31, 2014	May 30, 2014
Related Party Transaction
Capital expenditures paid by affiliate					$ 59,000,000
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
Successor
Related Party Transaction
Distribution to affiliate	$ 435,000,000				119,079,000
Proceeds from sale of properties and equipment and other	0				7,667,000
Transfer of derivative liability from affiliate	31,428,000
Current portion of long-term debt	211,558,000				0
Capital contribution from affiliate	0			$ 220,000,000	220,000,000
Successor \| Linn Operating, Inc. [Member]
Related Party Transaction
Transfer of derivative liability from affiliate	31,000,000
Due to Affiliate	17,000,000				13,000,000
Management Fee Expense	$ 20,000,000				86,000,000
Successor \| Superior Energy Services, Inc. [Member]
Related Party Transaction
Payments to related party					176,000
Successor \| 10.25% Senior notes due 2014
Related Party Transaction
Senior notes						$ 205,000,000
Permian basin assets [Member]
Related Party Transaction
Proceeds from sale of properties and equipment and other			$ 351,000,000		$ 351,000,000

Supplemental Oil & Natural Gas Data (Unaudited) Costs incurred (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2013

Dec. 31, 2014

Dec. 16, 2013

Dec. 31, 2012

Successor

Property acquisition costs:

Proved

$ 0

$ 478,311

Unproved

Exploration costs

148

Development costs

22,266

555,629

Asset retirement costs

6,064

Total costs incurred (1)

^[1]

22,266

1,040,152

Capitalized interest

6,000

Oil and natural gas:

Proved properties

3,397,785

4,025,595

Unproved properties

1,415,874

846,464

Capitalized Costs, Oil and Gas Producing Activities, Gross

4,813,659

4,872,059

Less accumulated depletion and amortization

(10,394)

(525,007)

Capitalized costs, Oil and natural gas properties, net

$ 4,803,265

$ 4,347,052

Predecessor

Property acquisition costs:

Proved

$ 3,457

$ 70,700

Unproved

463

10,686

Exploration costs

868

16,405

Development costs

577,568

696,095

Asset retirement costs

15,998

18,248

Total costs incurred (1)

^[1]

598,354

812,134

Capitalized interest

$ 6,000

$ 18,000

[1]

The total above does not reflect approximately $6 million, $41,000, $6 million and $18 million of capitalized interest incurred for the year ended December 31, 2014, for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, and for the year ended December 31, 2012, respectively.

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. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 16, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 16, 2013	Dec. 31, 2012
Results of Operations for Oil and Gas Producing Activities
Federal Income Tax Expense (Benefit), Continuing Operations	$ 0									$ 0
Successor
Revenues and other:
Oil, natural gas and natural gas liquids sales	50,324	$ 254,043	$ 350,863	$ 360,380	$ 333,116					1,298,402
Gains (losses) on oil and natural gas derivatives	(5,049)	$ 55,891	$ 44,990	$ (25,562)	$ 3,465					78,784
Total revenue from oil and gas producing activities	45,275									1,377,186
Production costs:
Lease operating expenses	15,410									364,540
Transportation expenses	2,576									41,842
Severance taxes, ad valorem taxes and California carbon allowances	2,130									97,683
Total production costs	20,116									504,065
Other costs:
Exploration costs	0									0
Depletion and amortization	10,612									294,107
Impairment of long-lived assets	0									253,362
(Gains) losses on sale of assets and other, net	10,208									112,303
Total other costs	20,820									659,772
Income tax expense	0									69
Results of operations	$ 4,339									$ 213,280
Predecessor
Revenues and other:
Oil, natural gas and natural gas liquids sales						$ 255,575	$ 306,183	$ 274,715	$ 266,772		$ 1,103,245	$ 937,261
Gains (losses) on oil and natural gas derivatives						$ (24,303)	$ (45,293)	$ 35,622	$ (737)		(34,711)	64,620
Total revenue from oil and gas producing activities											1,068,534	1,001,881
Production costs:
Lease operating expenses											295,811	232,266
Transportation expenses											46,774	39,531
Severance taxes, ad valorem taxes and California carbon allowances											57,063	39,374
Total production costs											399,648	311,171
Other costs:
Exploration costs											24,048	21,010
Depletion and amortization											275,927	224,836
Impairment of long-lived assets											0	0
(Gains) losses on sale of assets and other, net											(23)	(1,782)
Total other costs											299,952	244,064
Income tax expense											65,280	88,121
Results of operations											$ 303,654	$ 358,525

Supplemental Oil & Natural Gas Data (Unaudited) Reserve Quantities (Details) bbl in Thousands		3 Months Ended	12 Months Ended
	Dec. 31, 2013 MBoe bbl MMcf	Dec. 31, 2014 MBoe $ / bbl $ / MMBtu bbl MMcf	Dec. 31, 2014 MBoe Wells $ / bbl $ / MMBtu bbl MMcf	Dec. 16, 2013 MBoe Wells bbl MMcf	Dec. 31, 2012 MBoe Wells bbl MMcf
Reserve Quantities [Line Items]
Decline in NYMEX oil spot price		42.00%
Decline in NYMEX natural gas price		30.00%
NYMEX Oil price \| $ / bbl		53.27	53.27
NYMEX Natural gas price \| $ / MMBtu		2.89	2.89
Predecessor
Reserve Quantities [Line Items]
Wells Drilled Gross Productive \| Wells				340	467
ChangeInProvedReserves				40,414	203
Total proved reserves:
Beginning of year	234,715			275,129	274,926
Revisions of previous estimates				(39,092)	(22,162)
Extensions, discoveries and other additions				15,913	25,148
Purchases of minerals in place					11,094
Sales of minerals in place				2,775	556
Production				14,460	13,321
End of year				234,715	275,129
Proved developed reserves				156,161	150,216
Proved undeveloped reserves				78,554	124,913
Predecessor \| Oil
Total proved reserves:
Beginning of year \| bbl	187,892			204,208	185,880
Revisions of previous estimates \| bbl				(13,536)	12,145
Extensions, discoveries and other additions \| bbl				10,955	8,459
Purchases of minerals in place \| bbl					8,304
Sales of minerals in place \| bbl				(2,263)	(556)
Production \| bbl				11,472	10,024
End of year \| bbl				187,892	204,208
Proved developed reserves \| bbl				122,224	118,937
Proved undeveloped reserves \| bbl				65,668	85,271
Predecessor \| Natural gas
Total proved reserves:
Beginning of year \| MMcf	280,943			425,519	534,279
Revisions of previous estimates \| MMcf				(153,330)	(205,845)
Extensions, discoveries and other additions \| MMcf				29,756	100,129
Purchases of minerals in place \| MMcf					16,740
Sales of minerals in place \| MMcf				(3,071)	0
Production \| MMcf				17,931	19,784
End of year \| MMcf				280,943	425,519
Proved developed reserves \| MMcf				203,624	187,668
Proved undeveloped reserves \| MMcf				77,319	237,851
Successor
Reserve Quantities [Line Items]
Wells Drilled Gross Productive \| Wells			411
ChangeInProvedReserves	(667)		44,860
Total proved reserves:
Beginning of year	234,715		234,048
Revisions of previous estimates	0		(3,561)
Extensions, discoveries and other additions	0		26,360
Purchases of minerals in place			90,676
Sales of minerals in place	0		49,727
Production	667		18,888
End of year	234,048	278,908	278,908	234,715
Proved developed reserves	155,494	211,069	211,069
Proved undeveloped reserves	78,554	67,839	67,839
Successor \| Oil
Total proved reserves:
Beginning of year \| bbl	187,892		187,362
Revisions of previous estimates \| bbl	0		(10,647)
Extensions, discoveries and other additions \| bbl	0		20,435
Purchases of minerals in place \| bbl			22,533
Sales of minerals in place \| bbl	0		(41,216)
Production \| bbl	530		14,065
End of year \| bbl	187,362	164,402	164,402	187,892
Proved developed reserves \| bbl	121,694	119,039	119,039
Proved undeveloped reserves \| bbl	65,668	45,363	45,363
Successor \| Natural gas
Total proved reserves:
Beginning of year \| MMcf	280,943		280,117
Revisions of previous estimates \| MMcf	0		42,514
Extensions, discoveries and other additions \| MMcf	0		35,552
Purchases of minerals in place \| MMcf			408,857
Sales of minerals in place \| MMcf	0		(51,065)
Production \| MMcf	826		28,938
End of year \| MMcf	280,117	687,037	687,037	280,943
Proved developed reserves \| MMcf	202,798	552,184	552,184
Proved undeveloped reserves \| MMcf	77,319	134,853	134,853

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

Dec. 31, 2014

USD ($)

$ / boe

$ / MMBtu

Dec. 31, 2013

USD ($)

$ / boe

$ / MMBtu

Dec. 17, 2013

USD ($)

Dec. 16, 2013

USD ($)

Dec. 31, 2012

USD ($)

$ / boe

$ / MMBtu

Dec. 31, 2011

USD ($)

Successor

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

Future estimated revenues

$ 16,844,678

$ 17,863,984

Future estimated production costs

(7,742,035)

(6,654,536)

Future estimated development costs

(1,132,807)

(1,854,849)

Future estimated income tax expense

Future net cash flows

7,969,836

9,354,599

10% annual discount for estimated timing of cash flows

(3,639,459)

(4,719,267)

Standardized measure of discounted future net cash flows

$ 4,330,377

$ 4,635,332

$ 3,558,595

Successor | Crude Oil [Member]

Representative NYMEX prices: (1)

Oil (Bbl) | $ / boe

^[1]

95.27

96.89

Successor | Natural gas ($/Mcf)

Representative NYMEX prices: (1)

Natural gas (MMBtu) | $ / MMBtu

^[1]

4.35

3.67

Predecessor

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

Future estimated revenues

$ 19,738,729

Future estimated production costs

(5,884,891)

Future estimated development costs

(2,164,780)

Future estimated income tax expense

(3,344,024)

Future net cash flows

8,345,034

10% annual discount for estimated timing of cash flows

(4,511,619)

Standardized measure of discounted future net cash flows

$ 3,558,595

$ 3,833,415

$ 4,035,279

Predecessor | Crude Oil [Member]

Representative NYMEX prices: (1)

Oil (Bbl) | $ / boe

^[1]

90.66

Predecessor | Natural gas ($/Mcf)

Representative NYMEX prices: (1)

Natural gas (MMBtu) | $ / MMBtu

^[1]

2.88

[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.

Supplemental Oil & Natural Gas Data (Unaudited) Change in Standardized Measure of Discounted Net Cash Flows (Details) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2014	Dec. 16, 2013	Dec. 31, 2012
Predecessor
Change in Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Standardized measure—beginning of year	$ 3,558,595		$ 3,833,415	$ 4,035,279
Sales and transfers of oil, natural gas and NGL produced during the period			(703,597)	(625,707)
Changes in estimated future development costs			20,932	(331,498)
Net change in sales and transfer prices and production costs related to future production			(214,489)	(786,022)
Extensions, discoveries and improved recovery			189,625	124,466
Purchases of minerals in place				114,094
Sales of minerals in place			13,279	15,283
Previously estimated development costs incurred during the period			(401,791)	(497,036)
Net change due to revisions in quantity estimates			(856,118)	743
Accretion of discount			496,718	570,505
Income taxes			237,117	323,128
Changes in production rates and other			166,480	(73,326)
Net increase (decrease)			(274,820)	(201,864)
Standardized measure—end of year			$ 3,558,595	$ 3,833,415
Successor
Change in Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Standardized measure—beginning of year		$ 4,635,332
Sales and transfers of oil, natural gas and NGL produced during the period	(30,208)	(794,337)
Changes in estimated future development costs	0	68,290
Net change in sales and transfer prices and production costs related to future production	(1,272)	(1,020,605)
Extensions, discoveries and improved recovery	0	674,392
Purchases of minerals in place		548,256
Sales of minerals in place	0	486,903
Previously estimated development costs incurred during the period	0	(269,473)
Net change due to revisions in quantity estimates	0	(66,696)
Accretion of discount	19,184	463,533
Income taxes	1,109,522
Changes in production rates and other	(20,489)	39,642
Net increase (decrease)	1,076,737	(304,955)
Standardized measure—end of year	$ 4,635,332	$ 4,330,377

Supplemental Quarterly Data (Unaudited) (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 16, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 16, 2013

Dec. 31, 2012

Successor

Selected Quarterly Financial Data

Oil, natural gas and natural gas liquids sales

$ 50,324

$ 254,043

$ 350,863

$ 360,380

$ 333,116

$ 1,298,402

Electricity sales

1,444

8,561

11,300

10,192

9,969

40,022

Gains (losses) on oil and natural gas derivatives

(5,049)

55,891

44,990

(25,562)

3,465

78,784

Total revenues and other, net

47,118

323,232

409,416

347,261

351,380

1,431,289

Total expenses

^[1]

52,892

488,741

225,834

240,116

244,156

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

10,208

64,151

49,011

4,257

3,367

120,786

Net income (loss)

$ (19,973)

$ (251,275)

$ 115,165

$ 79,008

$ 79,698

$ 22,596

Predecessor

Selected Quarterly Financial Data

Oil, natural gas and natural gas liquids sales

$ 255,575

$ 306,183

$ 274,715

$ 266,772

$ 1,103,245

$ 937,261

Electricity sales

6,844

10,046

9,513

7,589

33,992

29,940

Gains (losses) on oil and natural gas derivatives

(24,303)

(45,293)

35,622

(737)

(34,711)

64,620

Total revenues and other, net

239,827

273,014

322,338

276,123

1,111,302

1,041,126

Total expenses

^[1]

254,305

202,647

201,331

198,239

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

(23)

(1,782)

Net income (loss)

$ (28,529)

$ 28,178

$ 61,364

$ 32,434

$ 93,447

$ 171,539

[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

Successor [Member]

Unrecognized Tax Benefits

us-gaap_UnrecognizedTaxBenefits

$ 0

Asset Retirement Obligation

us-gaap_AssetRetirementObligation

94,612,000

^[1]

Additional Paid-in Capital [Member] | Successor [Member]

Net Income (Loss) Attributable to Parent

us-gaap_NetIncomeLoss

Payments of Distributions to Affiliates

us-gaap_PaymentsOfDistributionsToAffiliates

435,000,000

Adjustments to additional paid in capital related party derivative liability transfer

bry_Adjustmentstoadditionalpaidincapitalrelatedpartyderivativeliabilitytransfer

31,428,000

Stockholders' Equity Attributable to Parent

us-gaap_StockholdersEquity

2,781,888,000

^[2]

Accumulated Income (Deficit) [Member] | Successor [Member]

Net Income (Loss) Attributable to Parent

us-gaap_NetIncomeLoss

(19,973,000)

Payments of Distributions to Affiliates

us-gaap_PaymentsOfDistributionsToAffiliates

Adjustments to additional paid in capital related party derivative liability transfer

bry_Adjustmentstoadditionalpaidincapitalrelatedpartyderivativeliabilitytransfer

Stockholders' Equity Attributable to Parent

us-gaap_StockholdersEquity

$ 0

^[2]

[1]	As a result of the application of pushdown accounting, the Company remeasured its asset retirement obligations on the LINN Energy transaction date.
[2]	The differences in equity balances at December 16, 2013, and December 17, 2013, are due to the application of pushdown accounting reflecting the LINN Energy transaction.

- Definition

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

+ References + Details