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Document and Entity Information Document - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Jun. 30, 2015
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, 2015
Document Fiscal Year Focus	2015
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, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 1,023	$ 1,586
Accounts receivable – trade, net	46,053	100,359
Derivative instruments	13,218	43,694
Other current assets	20,897	59,259
Total current assets	81,191	204,898
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	5,011,061	4,872,059
Less accumulated depletion and amortization	(1,596,165)	(525,007)
Oil and natural gas properties, net (successful efforts method)	3,414,896	4,347,052
Other property and equipment	111,495	115,999
Less accumulated depreciation	(12,522)	(8,452)
Other property and equipment, net	98,973	107,547
Advance to affiliate	0	293,627
Restricted cash	250,359	125
Other noncurrent assets	16,057	14,159
Noncurrent assets, excluding property, total	266,416	307,911
Total noncurrent assets	3,780,285	4,762,510
Total assets	3,861,476	4,967,408
Current liabilities:
Accounts payable and accrued expenses	125,748	242,350
Derivative instruments	2,241	0
Current portion of long-term debt	873,175	0
Other accrued liabilities	16,736	19,087
Total current liabilities	1,017,900	261,437
Noncurrent liabilities:
Long-term debt, net	845,368	2,086,952
Other noncurrent liabilities	212,049	200,015
Total noncurrent liabilities	1,057,417	2,286,967
Commitments and contingencies (Note 11)
Member’s equity:
Additional paid-in capital	2,798,713	2,416,381
Accumulated income (deficit)	(1,012,554)	2,623
Total member's equity	1,786,159	2,419,004
Total liabilities and member’s equity	$ 3,861,476	$ 4,967,408

Statements of Operations - USD ($) $ in Thousands		12 Months Ended
Statements of Operations - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 16, 2013
Successor
Revenues and other:
Oil, natural gas and natural gas liquids sales	$ 50,324	$ 575,031	$ 1,298,402
Electricity sales	1,444	24,544	40,022
Gains (losses) on oil and natural gas derivatives	(5,049)	29,175	78,784
Marketing revenues	399	5,709	10,889
Other revenues	0	7,195	3,192
Total revenues and other	47,118	641,654	1,431,289
Expenses:
Lease operating expenses	15,410	245,155	364,540
Electricity generation expenses	1,257	18,057	28,171
Transportation expenses	2,576	52,160	41,842
Marketing expenses	376	3,809	8,084
General and administrative expenses	20,298	85,993	102,787
Exploration costs	0	0	0
Depreciation, depletion and amortization	10,845	251,371	302,353
Impairment of long-lived assets	0	853,810	253,362
Taxes, other than income taxes	2,130	70,593	97,708
(Gains) losses on sale of assets and other, net	10,208	(1,919)	120,786
Total expenses	63,100	1,579,029	1,319,633
Other income and (expenses):
Interest expense, net of amounts capitalized	(3,963)	(85,818)	(87,948)
Gain on extinguishment of debt	0	11,209	0
Other, net	(28)	(3,261)	(1,043)
Total other income and (expenses)	(3,991)	(77,870)	(88,991)
Income (loss) before income taxes	(19,973)	(1,015,245)	22,665
Income tax expense (benefit)	0	(68)	69
Net income (loss)	$ (19,973)	$ (1,015,177)	$ 22,596
Predecessor
Revenues and other:
Oil, natural gas and natural gas liquids sales				$ 1,103,245
Electricity sales				33,992
Gains (losses) on oil and natural gas derivatives				(34,711)
Marketing revenues				7,827
Other revenues				949
Total revenues and other				1,111,302
Expenses:
Lease operating expenses				295,811
Electricity generation expenses				22,485
Transportation expenses				46,774
Marketing expenses				7,593
General and administrative expenses				122,991
Exploration costs				24,048
Depreciation, depletion and amortization				279,757
Impairment of long-lived assets				0
Taxes, other than income taxes				57,063
(Gains) losses on sale of assets and other, net				(23)
Total expenses				856,499
Other income and (expenses):
Interest expense, net of amounts capitalized				(96,127)
Gain on extinguishment of debt				0
Other, net				51
Total other income and (expenses)				(96,076)
Income (loss) before income taxes				158,727
Income tax expense (benefit)				65,280
Net income (loss)				$ 93,447

Statement of Shareholders' Equity (Predecessor) - 12 months ended Dec. 16, 2013 - Predecessor - USD ($)
$ in Thousands

Total

Additional Paid-In Capital

Accumulated Income

Class A

Common Stock

Class B

Common Stock

Balances, beginning of period at Dec. 31, 2012

$ 1,014,791

$ 364,710

$ 649,539

$ 524

$ 18

Increase (Decrease) in Shareholders' Equity

Stock options and restricted stock issued

730

727

Stock-based compensation expense

12,576

Income tax effect of stock option exercises

2,345

Dividends ($0.32 per share)

(17,612)

Net income

93,447

Balances, end of period at Dec. 16, 2013

^[1]

$ 1,106,277

$ 380,358

$ 725,374

$ 527

$ 18

[1]	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

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

Statements of Member's Equity (Successor) Statement - Successor - USD ($)
$ in Thousands

Total

Additional Paid-In Capital

Accumulated Income (Deficit)

Members' Equity at Dec. 17, 2013

^[1]

$ 2,781,888

$ 0

Increase (Decrease) in Member's Equity

Distributions to affiliate

(435,000)

Transfer of derivative liability from affiliate

(31,428)

Net income (loss)

(19,973)

Members' Equity at Dec. 31, 2013

2,295,487

2,315,460

(19,973)

Increase (Decrease) in Member's Equity

Capital contributions from affiliate

220,000

Distributions to affiliate

(119,079)

Net income (loss)

22,596

Members' Equity at Dec. 31, 2014

2,419,004

2,416,381

2,623

Increase (Decrease) in Member's Equity

Capital contributions from affiliate

221,278

Capital contributions from affiliate

471,278

Distributions to affiliate

(88,946)

Net income (loss)

(1,015,177)

Members' Equity at Dec. 31, 2015

$ 1,786,159

$ 2,798,713

$ (1,012,554)

[1]	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

Statements of Cash Flows - USD ($) $ in Thousands		12 Months Ended
Statements of Cash Flows - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 16, 2013
Successor
Cash flow from operating activities:
Net income (loss)	$ (19,973)	$ (1,015,177)	$ 22,596
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	10,845	251,371	302,353
Impairment of long-lived assets	0	853,810	253,362
Stock-based compensation expense	0	0	0
Gain on extinguishment of debt	0	(11,209)	0
Amortization and write-off of deferred financing fees	(615)	3,750	(4,913)
Change in book overdraft	0	0	0
(Gains) losses on sale of assets and other, net	0	(961)	111,374
Deferred income taxes	0	(68)	69
Derivatives activities:
Total (gains) losses	5,049	(36,068)	(78,784)
Cash settlements	0	68,770	6,738
Cash settlements on canceled derivatives	0	0	12,281
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	71,434	59,941	16,483
(Increase) decrease in other assets	10,613	18,724	(15,949)
Increase (decrease) in accounts payable and accrued expenses	(8,078)	(62,755)	(3,719)
Increase (decrease) in other liabilities	(12,597)	(7,610)	(38,411)
Net cash provided by operating activities	56,678	122,518	583,480
Cash flow from investing activities:
Property acquisitions	0	0	0
Development of oil and natural gas properties	(17,478)	(32,633)	(512,419)
Purchases of other property and equipment	0	(17,741)	(11,470)
Settlement of advance to affiliate	0	129,217	0
Proceeds from sale of properties and equipment and other	0	22,525	7,667
Net cash provided by (used in) investing activities	(17,478)	101,368	(516,222)
Cash flow from financing activities:
Proceeds from borrowings	0	0	0
Repayments of debt	0	(355,418)	(206,124)
Dividends paid	(4,272)	0	0
Financing fees and other, net	0	(1,363)	(11,510)
Proceeds from stock option exercises	0	0	0
Capital contributions from affiliate	0	221,278	220,000
Distributions to affiliate	(435,000)	(88,946)	(119,079)
Excess tax benefit from stock-based compensation	0	0	0
Net cash provided by (used in) financing activities	(439,272)	(224,449)	(116,713)
Net increase (decrease) in cash and cash equivalents	(400,072)	(563)	(49,455)
Cash and cash equivalents:
Beginning	451,113	1,586	51,041
Ending	51,041	$ 1,023	$ 1,586	$ 451,113
Predecessor
Cash flow from operating activities:
Net income (loss)				93,447
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization				279,757
Impairment of long-lived assets				0
Stock-based compensation expense				12,576
Gain on extinguishment of debt				0
Amortization and write-off of deferred financing fees				6,685
Change in book overdraft				(14,885)
(Gains) losses on sale of assets and other, net				14,907
Deferred income taxes				76,644
Derivatives activities:
Total (gains) losses				34,711
Cash settlements				182
Cash settlements on canceled derivatives				0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net				(97,653)
(Increase) decrease in other assets				996
Increase (decrease) in accounts payable and accrued expenses				28,187
Increase (decrease) in other liabilities				7,414
Net cash provided by operating activities				442,968
Cash flow from investing activities:
Property acquisitions				(3,933)
Development of oil and natural gas properties				(588,829)
Purchases of other property and equipment				(5,750)
Settlement of advance to affiliate				0
Proceeds from sale of properties and equipment and other				11,530
Net cash provided by (used in) investing activities				(586,982)
Cash flow from financing activities:
Proceeds from borrowings				1,225,475
Repayments of debt				(615,200)
Dividends paid				(13,204)
Financing fees and other, net				(459)
Proceeds from stock option exercises				730
Capital contributions from affiliate				0
Distributions to affiliate				0
Excess tax benefit from stock-based compensation				2,345
Net cash provided by (used in) financing activities				599,687
Net increase (decrease) in cash and cash equivalents				455,673
Cash and cash equivalents:
Beginning	$ 455,985			312
Ending				$ 455,985

Basis of Presentation and Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

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), Colorado (Piceance Basin) and east Texas. In August and November of 2014, the Company divested all of its properties located in the Permian Basin.

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

Going Concern Uncertainty

The Company’s liquidity outlook has changed since the third quarter of 2015 due to continued low commodity prices. In addition, the Company’s Credit Facility is subject to scheduled redeterminations of its borrowing base, semi-annually in April and October, based primarily on reserve reports using lender commodity price expectations at such time. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs are expected to adversely impact the upcoming April redetermination and will likely have a significant negative impact on the Company’s liquidity.

As a result of these and other factors, the following issues have adversely impacted the Company’s ability to continue as a going concern:

•

the Company’s ability to comply with financial covenants and ratios in its Credit Facility and indentures has been affected by continued low commodity prices. Absent a waiver or amendment, failure to meet these covenants and ratios would result in a default and, to the extent the applicable lenders so elect, an acceleration of the Company’s existing indebtedness, causing such debt of approximately $873 million to be immediately due and payable. Based on the Company’s current estimates and expectations for commodity prices in 2016, the Company does not expect to remain in compliance with all of the restrictive covenants contained in its Credit Facility throughout 2016 unless those requirements are waived or amended. The Company does not currently have adequate liquidity to repay all of its outstanding debt in full if such debt were accelerated;


•	because the Credit Facility is effectively fully drawn, any reduction of the borrowing base under the Company’s Credit Facility would require mandatory prepayments to the extent existing indebtedness exceeds the new borrowing base. The Company may not have sufficient cash on hand to be able to make any such mandatory prepayments; and


•	the Company’s ability to make interest payments as they become due and repay indebtedness upon maturities (whether under existing terms or as a result of acceleration) is impacted by the Company’s liquidity. As of February 29, 2016, there was less than $1 million of available borrowing capacity under the Credit Facility.

The Company’s Credit Facility contains the requirement to deliver audited financial statements without a going concern or like qualification or exception. Consequently, as of the filing date, March 28, 2016, the Company is in default under the Credit Facility. If the Company is unable to obtain a waiver or other suitable relief from the lenders under the Credit Facility prior to the expiration of the 30 day grace period, an Event of Default (as defined in the applicable agreements) will result and the lenders holding a majority of the commitments under the Credit Facility could accelerate the outstanding indebtedness, which would make it immediately due and payable. If the Company is unable to obtain a waiver from or otherwise reach an agreement with the lenders under the Credit Facility and the indebtedness under the Credit Facility is accelerated, then an Event of Default under the Company’s senior notes would occur, which, if it continues beyond any applicable cure periods, would, to the extent the applicable lenders so elect, result in the acceleration of those obligations.

Furthermore, the Company has decided to defer making an interest payment totaling approximately $18 million due March 15, 2016, on the Company’s senior notes due September 2022, which resulted in the Company being in default under these senior notes. The indenture governing the notes permits the Company a 30 day grace period to make the interest payments. If the Company fails to make the interest payments within the grace period, or is otherwise unable to obtain a waiver or suitable relief from the holders of these senior notes, an Event of Default will result and if the trustee or noteholders holding at least 25% in the aggregate outstanding principal amount of the notes so elect would accelerate the notes causing them to be immediately due and payable.

An Event of Default under any of the indentures governing the senior notes triggers a cross-default under the Credit Facility and, as discussed above, if the applicable lenders so elect would result in acceleration under the Credit Facility. In addition, as discussed above, an acceleration of the obligations under the Credit Facility, if the applicable lenders so elect, would result in cross-acceleration under the senior notes.

See Note 3 for additional details about the Company’s debt.

If lenders, and subsequently noteholders, accelerate the Company’s outstanding indebtedness (approximately $1.7 billion as of December 31, 2015), it will become immediately due and payable and the Company will not have sufficient liquidity to repay those amounts. If the Company is unable to reach an agreement with its creditors prior to any of the above described accelerations, the Company could be required to immediately file for protection under Chapter 11 of the U.S. Bankruptcy Code.

The significant risks and uncertainties described above raise substantial doubt about the Company’s ability to continue as a going concern. The financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

The Company is currently in discussions with various stakeholders and is pursuing or considering a number of actions including: (i) obtaining additional sources of capital from asset sales, private issuances of equity or equity-linked securities, debt for equity swaps, or any combination thereof; (ii) pursuing in- and out-of-court restructuring transactions; (iii) obtaining waivers or amendments from its lenders; and (iv) continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations. There can be no assurance that sufficient liquidity can be obtained from one or more of these actions or that these actions can be consummated within the period needed.

Principles of Reporting

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 regarding the LINN Energy transaction.

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 November 2015, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to simplify the presentation of deferred taxes by requiring that all deferred taxes be presented as noncurrent. This ASU will be applied either prospectively or retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2016, and interim periods within those years (early adoption permitted). The Company does not expect the adoption of this ASU to have a material impact on its financial statements.

In April 2015, the FASB issued an ASU that is intended to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2015, and interim periods within those years (early adoption permitted). The Company does not expect the adoption of this ASU to have a material impact on its financial statements.

In August 2014, the FASB issued an ASU that provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter (early adoption permitted). The Company does not expect the adoption of this ASU to have a material impact on its financial statements or related disclosures.

In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU will be applied either retrospectively or as a cumulative-effect adjustment as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those years (early adoption permitted for fiscal years beginning after December 15, 2016, including interim periods within that year). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its financial statements and related disclosures.

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.

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, 2015, or December 31, 2014.

Inventories

Materials, supplies and commodity inventories are valued at the lower of average cost or market. Inventories also include California carbon allowance instruments.

Oil and Natural Gas Properties

Proved Properties

The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $2 million, $6 million, $41,000 and $6 million for the years ended December 31, 2015, and December 31, 2014, and for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, respectively.

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices.

Based on the analysis described above, the Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties:



	Year Ended December 31,
	2015		2014
	(in thousands)

California operating area	$	537,511	$	22
Uinta Basin operating area	111,339		253,340
East Texas operating area	78,437		—
Piceance Basin operating area	55,344		—
	$	782,631	$	253,362

The impairment charges in 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The impairment charges in 2014 were due to a steep decline in commodity prices during the fourth quarter of 2014. The Company recorded no impairment charges for proved properties for the periods from December 17, 2013 through December 31, 2013, or January 1, 2013 through December 16, 2013.

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 statements of operations.

Subsequent to December 31, 2015, the prices of oil, natural gas and NGL have continued to be volatile. In the future, if forward price curves continue to decline, the Company may have additional impairments which could have a material impact on its results of operations.

Unproved Properties

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

For the year ended December 31, 2015, the Company recorded noncash impairment charges (before and after tax) of approximately $71 million associated with unproved oil and natural gas properties in California. The Company recorded no impairment charges for unproved properties for the year ended December 31, 2014, or for the periods from December 17, 2013 through December 31, 2013, or January 1, 2013 through December 16, 2013.

The impairment charges in 2015 were primarily due to changes in the Company’s future planned capital development in certain operating areas as a result of declines in commodity prices. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the statement of operations.

Exploration Costs

Geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded no exploration costs during the years ended December 31, 2015, and 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 for the period from January 1, 2013 through December 16, 2013, which is included in “exploration costs” on the statement 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. Limited liability companies are subject to Texas margin tax. 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 17, 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

Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices. The Company also, from time to time, has entered into derivative contracts for a portion of its natural gas consumption. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company has also hedged its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials. By removing a portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices.

The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts, collars and three-way collars, and may enter into put option contracts in the future. The Company does not enter into derivative contracts for trading purposes.

A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. 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. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date.

Derivative instruments are recorded at fair value and included on the balance sheets as assets or liabilities. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads are applied to the Company’s commodity derivatives. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.

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, 2015, and December 31, 2014. 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, 2015, net deferred financing fees of approximately $8 million are included in “other current assets” on the balance sheet. At December 31, 2014, net deferred financing fees of approximately $12 million are included in “other noncurrent assets” on the balance sheet. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense. For the years ended December 31, 2015, and December 31, 2014, and for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, amortization expense of approximately $3 million, $3 million, $83,000 and $5 million, respectively, is included in “interest expense, net of amounts capitalized” on the statements of operations. For the years ended December 31, 2015, and December 31, 2014, approximately $3 million and $256,000, respectively, were written off to expense and included in “other, net” on the statements of operations related to amendments of the Credit Facility.

Other Current Assets

The components of other current assets are as follows:



	December 31,
	2015		2014
	(in thousands)

Prepaid expenses	$	1,903	$	1,210
California carbon allowance inventories	7,073		38,409
Oil inventories	3,446		4,034
Materials inventories	—		1,747
Deferred financing fees	8,108		—
Receivables from exchanges of properties and divestitures, and other	367		13,859
Other current assets	$	20,897	$	59,259

Other Accrued Liabilities

The components of other accrued liabilities are as follows:



	December 31,
	2015		2014
	(in thousands)

Accrued interest	$	14,096	$	15,803
Asset retirement obligations	2,548		3,101
Other	92		183
Other accrued liabilities	$	16,736	$	19,087

Restricted Cash

At December 31, 2015, “restricted cash” on the balance sheet includes $250 million that LINN Energy borrowed under the LINN credit facility and contributed to Berry in May 2015 to post with Berry’s lenders in connection with the reduction in its borrowing base. See Note 3 for additional details.

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, 2015, the Company’s three largest customers represented approximately 24%, 23% and 20% of the Company’s oil, natural gas and NGL sales. 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 years ended December 31, 2015, December 31, 2014, and December 31, 2013, 100% of electricity sales were attributable to two customers.

At December 31, 2015, trade accounts receivable from three customers represented approximately 24%, 22% and 11% of the Company’s receivables. At December 31, 2014, trade accounts receivable from two customers represented approximately 36% and 10% of the Company’s receivables.

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.

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, 2015		Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013
(in thousands)
Cash payments for interest, net of amounts capitalized	$	86,226	$	95,915	$	—	$	87,495
Cash payments for income taxes	$	—	$	—	$	—	$	622

Noncash investing activities:
Accrued capital expenditures	$	10,551	$	59,884	$	77,001	$	70,866

For the year ended December 31, 2015, LINN Energy spent approximately $165 million of capital expenditures in respect of Berry’s operations. Berry recorded the $165 million to oil and natural gas properties with an offset to the advance due from LINN Energy. On September 30, 2015, LINN Energy repaid in full the remaining advance of approximately $129 million to Berry.

In addition, in May 2015, LINN Energy made a capital contribution of $250 million to Berry which was deposited on Berry’s behalf and posted as restricted cash with Berry’s lenders in connection with the reduction in its borrowing base (see Note 3).

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 ExxonMobil and Exxon XTO (each as defined in Note 2) in exchange for properties in California’s South Belridge Field and the Hugoton Basin, respectively.

Exchanges of Properties, Divestiture and LINN Energy Transaction	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Exchanges of Properties, Divestiture and LINN Energy Transaction	Exchanges of Properties, Divestiture and LINN Energy Transaction Exchanges of Properties – 2014 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 (“ExxonMobil”) in exchange for properties in California’s South Belridge Field. The noncash exchange was accounted for at fair value and the Company recognized a net loss of approximately $30 million. 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. (“Exxon XTO”), in exchange for properties in the Hugoton Basin. The noncash exchange was accounted for at fair value and the Company recognized a net loss of approximately $34 million. 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 losses on the exchanges are equal to the difference between the carrying value and the fair value of the assets exchanged less costs to sell, and are included in “(gains) losses on sale of assets and other, net” on the statement of operations. The fair value measurements were based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. 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. Divestiture – 2014 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 (“Permian Basin Assets Sale”). Cash proceeds from the sale of these properties were approximately $352 million, net of costs to sell of approximately $2 million, and the Company recognized a net loss of approximately $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 were required to 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. During the twelve months ended September 30, 2015, LINN Energy spent approximately $223 million, including approximately $58 million in 2014, of capital expenditures in respect of Berry’s operations. On September 30, 2015, LINN Energy repaid in full the remaining advance of approximately $129 million to Berry. In October 2015, Berry used that cash to repay borrowings under its Credit Facility. 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.

Debt

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Debt

The following summarizes the Company’s outstanding debt:



	December 31,
	2015			2014
	(in thousands, except percentages)

Credit facility ⁽¹⁾	$	873,175		$	1,173,175
6.75% senior notes due November 2020	261,100			299,970
6.375% senior notes due September 2022	572,700			599,163
Net unamortized premiums	11,568			14,644
Total debt, net	1,718,543			2,086,952
Less current portion ⁽²⁾	(873,175		)	—
Total long-term debt, net	$	845,368		$	2,086,952


⁽¹⁾	Variable interest rates of 3.17% and 2.67% at December 31, 2015, and December 31, 2014, respectively.


⁽²⁾	Due to existing and anticipated covenant violations, the Company’s credit facility was classified as current at December 31, 2015.

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, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)

Credit facility	$	873,175	$	873,175	$	1,173,175	$	1,173,175
Senior notes, net	845,368		200,249		913,777		699,462
Total debt, net	$	1,718,543	$	1,073,424	$	2,086,952	$	1,872,637

Credit Facility

The Company’s Second Amended and Restated Credit Agreement (“Credit Facility”) had a borrowing base of $900 million, subject to lender commitments, as of December 31, 2015. The maturity date is April 2019. At December 31, 2015, lender commitments under the facility were also $900 million but there was less than $1 million of available borrowing capacity, including outstanding letters of credit.

In October 2015, the Company entered into an amendment to the Credit Facility to provide for, among other things: (i) a springing maturity based on the maturity of any outstanding junior lien debt; (ii) the ability of the Company to incur junior lien debt to refinance its senior notes or as additional indebtedness, but such additional indebtedness issued may not exceed $500 million outstanding at any one time and is subject to a borrowing base reduction; (iii) a decrease in the Company’s covenant requiring the maintenance of an EBITDA to Interest Expense ratio of 2.5 to 1.0, such that the permissible ratio is decreased to 2.0 to 1.0 from December 31, 2015 through December 31, 2016, to 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and returning to 2.5 to 1.0 thereafter; (iv) an increase in the mortgage requirement on the total value of the oil and natural gas properties included in the Company’s most recent reserve report from 80% to 90%; (v) an increase to the applicable margin charged on borrowings under the Credit Facility by 0.25% and increase the commitment fee under the Credit Facility to 0.5% per annum; and (vi) permission to prepay or exchange the Company’s senior notes with notes issued by LINN Energy.

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. The spring 2015 semi-annual borrowing base redetermination was completed in May 2015, and as a result of lower commodity prices, the borrowing base under the Credit Facility decreased from $1.4 billion to $1.2 billion. The fall 2015 semi-annual redetermination was completed in October 2015 and the borrowing base under the Credit Facility decreased from $1.2 billion to $900 million. In connection with the reduction in Berry’s borrowing base in October 2015, Berry repaid $300 million of borrowings outstanding under the Credit Facility. Continued low commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs are expected to adversely impact future redeterminations.

In connection with the reduction in Berry’s borrowing base in May 2015, LINN Energy contributed $250 million to Berry to post as restricted cash with Berry’s lenders. As directed by LINN Energy, the $250 million was deposited on Berry’s behalf in a security account with the administrative agent subject to a security control agreement. Berry’s ability to withdraw funds from this account is subject to a concurrent reduction of the borrowing base under the Credit Facility or lender’s consent in connection with a redetermination of such borrowing base. The $250 million may be used to satisfy obligations under the Credit Facility or, subject to restrictions in the indentures governing Berry’s senior notes, may be returned to LINN Energy in the future. The amount is included in “restricted cash” on the balance sheet.

The Company’s obligations under the Credit Facility, as amended, are secured by mortgages on its oil and natural gas properties and other personal property. The Company is required to maintain mortgages on properties representing at least 90% of the present value of its oil and natural gas proved reserves.

At the Company’s election, interest on borrowings under the Credit Facility, as amended, is determined by reference to either the LIBOR plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the Credit Facility) or a Base Rate (as defined in the Credit Facility) plus an applicable margin between 0.75% and 1.75% 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 the LIBOR. The Company is required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the maximum commitment amount of the lenders.

Senior Notes Due November 2020

The Company has approximately $261 million in aggregate principal amount of 6.75% senior notes due November 2020 (“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 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 approximately $573 million in aggregate principal amount of 6.375% senior notes due September 2022 (“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.

At any time prior to March 15, 2017, the Company may 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

During the year ended December 31, 2015, the Company repurchased, on the open market and through a privately negotiated transaction, approximately $65 million of its outstanding senior notes including approximately $39 million of its 6.75% senior notes due November 2020 and approximately $26 million of its 6.375% senior notes due September 2022. In connection with the repurchases, the Company paid approximately $55 million in cash and recorded a gain on extinguishment of debt of approximately $11 million for the year ended December 31, 2015.

On May 30, 2014, in accordance with the provisions of the indenture related to its 10.25% senior notes due June 2014 (“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).

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 June 2014 Senior Notes, November 2020 Senior Notes and September 2022 Senior Notes, respectively.

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. As of December 31, 2015, the Company was 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 and determines to distribute such amounts to LINN Energy, the indentures governing the Company’s 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.

Covenant Violations

The audit report the Company received with respect to its financial statements contains an explanatory paragraph expressing uncertainty as to the Company’s ability to continue as a going concern, the delivery of which constitutes a default under the Credit Facility. The Company also deferred making an interest payment totaling approximately $18 million due March 15, 2016, on the Company’s senior notes due September 2022, which resulted in the Company being in default under these senior notes. See “Going Concern Uncertainty” in Note 1 for additional information.

Income Taxes

12 Months Ended

Dec. 31, 2015

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. Limited liability companies are subject to Texas margin tax. 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 in December 2013, 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 (benefit)” on the statements of operations.

Income tax expense (benefit) consisted of the following:



	Successor							Predecessor
	Year Ended December 31, 2015			Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013
(in thousands)
Current taxes:
Federal	$	—		$	—	$	—	$	(225	)
State	—			—		—		(11,043		)
Deferred taxes:
Federal	—			—		—		56,620
State	(68		)	69		—		19,928
	$	(68	)	$	69	$	—	$	65,280

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



	Successor						Predecessor
	Year Ended December 31, 2015		Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013

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

The effective tax rate was zero for the years ended December 31, 2015, and December 31, 2014, and for the 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:



	December 31, 2015		December 31, 2014
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	—	$	—
Other	—		—
	—		—
Deferred tax liabilities:
Property and equipment principally due to differences in depreciation	—		—
Other	1		69
	1		69
Net deferred tax liabilities	$	1	$	69

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2015, 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, 2015		Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013
(in thousands)
Unrecognized tax benefits at beginning of period	$	—	$	—	$	—	$	22,553
Increases for positions taken in current year	—		—		—		50
Decreases for positions taken in a prior year	—		—		—		(635		)
Decreases for settlements with taxing authorities	—		—		—		—
Decreases for lapses in the applicable statute of limitations	—		—		—		(1,862		)
Unrecognized tax benefits at end of period	$	—	$	—	$	—	$	20,106

In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules, and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2015, or December 31, 2014.

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 2013 – 2015 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.

Member's and Shareholders' Equity	12 Months Ended
Member's and Shareholders' Equity	Dec. 31, 2015
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 at such time 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
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
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-Section E

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

+ 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, (“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 statement of operations for grants under the Equity Incentive Plans was approximately $12 million for the period from January 1, 2013 through December 16, 2013.

Stock Options

The following table presents stock option activity under the predecessor’s Equity Incentive Plans for the period from January 1, 2013 through December 16, 2013:



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

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 following table presents 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 presents RSU activity under the predecessor’s Equity Incentive Plans for the period from January 1, 2013 through December 16, 2013:



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

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 presents performance share award activity under the predecessor’s Equity Incentive Plans for the period from January 1, 2013 through December 16, 2013:



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

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.

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 were 10,758 for the period from January 1, 2013 through December 16, 2013.

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 and the Company’s contributions to the 401(k) Plan, net of forfeitures, were approximately $2 million for the period from January 1, 2013 through December 16, 2013.

At December 31, 2015, and December 31, 2014, 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, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

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

The following table presents derivative positions for the period indicated as of December 31, 2015:



	2016

Natural gas basis differential positions: ⁽¹⁾
NWPL Rockies basis swaps: ⁽²⁾
Hedged volume (MMMBtu)	11,712
Hedged differential ($/MMBtu)	$	(0.34	)
SoCal basis swaps: ⁽³⁾
Hedged volume (MMMBtu)	32,940
Hedged differential ($/MMBtu)	$	(0.03	)


⁽¹⁾	Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.


⁽²⁾	For positions which hedge exposure to differentials in producing areas, the Company receives the NYMEX Henry Hub natural gas price plus the respective spread and pays the specified index price. Cash settlements are made on a net basis.


⁽³⁾	For positions which hedge exposure to differentials in consuming areas, the Company pays the NYMEX Henry Hub natural gas price plus the respective spread and receives the specified index price. Cash settlements are made on a net basis.

During the year ended December 31, 2015, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for May 2015 through December 2016 to hedge exposure to differentials in certain producing areas and oil swaps for April 2015 through December 2015. In addition, the Company entered into natural gas basis swaps for May 2015 through December 2016 to hedge exposure to the differential in California, where it consumes natural gas in its heavy oil development operations.

During the fourth quarter of 2014, the Company canceled all of its ICE Brent – NYMEX WTI basis swaps for 2015 and received cash settlements of approximately $12 million.

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, 2015, included volumes of 3,859 MBbls at an average contract price of $67.66 per Bbl. 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 WTI crude oil for each day of the delivery month.

Balance Sheet Presentation

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



	December 31,
	2015		2014
	(in thousands)
Assets:
Commodity derivatives	$	13,807	$	60,843
Liabilities:
Commodity derivatives	$	2,830	$	17,149

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 $14 million at December 31, 2015. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Gains (Losses) on Derivatives

A summary of gains and losses on the derivatives included on the statements of operations is presented below:



	Successor							Predecessor
	Year Ended December 31, 2015		Year Ended December 31, 2014		December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013
(in thousands)
Gains (losses) on oil and natural gas derivatives	$	29,175	$	78,784	$	(5,049	)	$	(34,711	)
Lease operating expenses ⁽¹⁾	6,893		—		—			—
Total gains (losses) on oil and natural gas derivatives	$	36,068	$	78,784	$	(5,049	)	$	(34,711	)


⁽¹⁾	Consists of gains and (losses) on derivatives used to hedge exposure to differentials in consuming areas, which were entered into in March 2015.

- 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.

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-SubTopic 10
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=56946850&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=56946850&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=56946850&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=56946850&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, 2015

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, 2015
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	13,807	$	(589	)	$	13,218
Liabilities:
Commodity derivatives	$	2,830	$	(589	)	$	2,241



	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	)	$	—


⁽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, 2015

Other Property and Equipment [Abstract]

Other Property and Equipment

Other property and equipment consists of the following:



	December 31,
	2015			2014
	(in thousands)

Natural gas plant and pipeline	$	96,771		$	101,626
Buildings and leasehold improvements	5,884			6,559
Vehicles	4,647			3,759
Drilling and other equipment	113			28
Furniture and office equipment	3,879			3,826
Land	201			201
	111,495			115,999
Less accumulated depreciation	(12,522		)	(8,452		)
	$	98,973		$	107,547

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2015

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



	December 31,
	2015			2014
	(in thousands)

Asset retirement obligations at beginning of year	$	121,760		$	94,830
Liabilities added from drilling	1,270			5,124
Settlements	(683		)	(5,260		)
Liabilities added from acquisitions	—			25,223
Liabilities associated with assets divested	—			(5,460		)
Current year accretion expense	6,897			5,670
Revision of estimates	8,319			1,633
Asset retirement obligations at end of year	$	137,563		$	121,760

Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

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 for each of the years ending December 31, 2015, and December 31, 2014, and $302,000 and $5 million for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, respectively.

The following table presents the Company’s future minimum payments under noncancelable operating leases and other commitments as of December 31, 2015:



	Total		2016		2017		2018		2019		2020		Thereafter
(in thousands)
Operating leases⁽¹⁾	$	9,377	$	3,710	$	2,234	$	1,279	$	1,175	$	979	$	—
Firm natural gas transportation contracts⁽²⁾	146,981		33,446		33,417		23,972		22,528		19,123		14,495
Other commitments ⁽³⁾	2,442		2,442		—		—		—		—		—
Total	$	158,800	$	39,598	$	35,651	$	25,251	$	23,703	$	20,102	$	14,495


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


⁽²⁾	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 two to eight years and require a minimum monthly charge regardless of whether the contracted capacity is used or not


⁽³⁾	Other commitments relate primarily to cogeneration facility management services and equipment rental obligations.

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 asset is being depreciated over the remaining useful life and has a net book value of approximately $5 million at December 31, 2015. 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 effective September 30, 2015, if by September 30, 2017, the Company does not expend $9 million on the construction of either the extension of the existing access road or a new access 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 2015 amendment, this deadline is subject to further extension to no later than December 31, 2017. 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 of the 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

The Company is involved in various 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 years ended December 31, 2015, and December 31, 2014, and the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2015
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 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 years ended December 31, 2015, and December 31, 2014, and for the period from December 17, 2013 through December 31, 2013, the Company incurred management fee expenses of approximately $78 million, $86 million and $20 million, respectively, for services provided by LOI. The Company also had affiliated accounts payable due to LINN Energy of approximately $9 million and $13 million at December 31, 2015, and December 31, 2014, respectively, included in “accounts payable and accrued expenses” on the balance sheets. During the year ended December 31, 2015, Linn Energy made capital contributions of approximately $471 million to Berry, including $250 million that was deposited on Berry’s behalf and posted as restricted cash with Berry’s lenders in connection with the reduction in its borrowing base in May 2015 (see Note 3). The $250 million may be used to satisfy obligations under the Credit Facility or may be returned to LINN Energy in the future if commodity prices improve. During the second quarter of 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 10.25% senior notes due June 2014 plus accrued interest. During the year ended December 31, 2015, the Company made cash distributions of approximately $89 million to LINN Energy. During the year ended December 31, 2014, the Company made cash distributions of approximately $119 million to LINN Energy. In addition, in 2014, the Company advanced approximately $352 million, to a subsidiary of LINN Energy, of net cash proceeds from the Permian Basin Assets Sale. These proceeds were required to 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. During the twelve months ended September 30, 2015, LINN Energy spent approximately $223 million, including approximately $58 million in 2014, of capital expenditures in respect of Berry’s operations. On September 30, 2015, LINN Energy repaid in full the remaining advance of approximately $129 million to Berry. In October 2015, Berry used that cash to repay borrowings under its Credit Facility. On December 19, 2013, the Company made a cash distribution of $435 million to LINN Energy. Also in 2013, in connection with the LINN Energy transaction, LINN Energy transferred a derivative liability of approximately $31 million to the Company. 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 years ended December 31, 2015, and December 31, 2014, the Company incurred expenditures of approximately $562,000 and $176,000, respectively, related to services rendered by Superior and its subsidiaries.

- 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, 2015

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, 2015		Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013
(in thousands)
Property acquisition costs:
Proved	$	—	$	478,311	$	—	$	3,457
Unproved	—		—		—		463
Exploration costs	—		148		—		868
Development costs	130,276		555,629		22,266		577,568
Asset retirement costs	2,151		6,064		—		15,998
Total costs incurred ⁽¹⁾	$	132,427	$	1,040,152	$	22,266	$	598,354


⁽¹⁾	The total above does not reflect approximately $2 million, $6 million, $41,000 and $6 million of capitalized interest incurred for the years ended December 31, 2015, and December 31, 2014, and for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, 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,
	2015			2014
	(in thousands)

Oil and natural gas:
Proved properties	$	4,231,836		$	4,025,595
Unproved properties	779,225			846,464
	5,011,061			4,872,059
Less accumulated depletion and amortization	(1,596,165		)	(525,007		)
	$	3,414,896		$	4,347,052

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, 2015			Year Ended December 31, 2014		December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013
(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	575,031		$	1,298,402	$	50,324		$	1,103,245
Gains (losses) on oil and natural gas derivatives	29,175			78,784		(5,049		)	(34,711		)
	604,206			1,377,186		45,275			1,068,534
Production costs:
Lease operating expenses	245,155			364,540		15,410			295,811
Transportation expenses	52,160			41,842		2,576			46,774
Severance taxes, ad valorem taxes and California carbon allowances	70,591			97,683		2,130			57,063
	367,906			504,065		20,116			399,648
Other costs:
Exploration costs	—			—		—			24,048
Depletion and amortization	241,019			294,107		10,612			275,927
Impairment of long-lived assets	853,810			253,362		—			—
(Gains) losses on sale of assets and other, net	372			112,303		10,208			(23		)
	1,095,201			659,772		20,820			299,952
Income tax expense (benefit)	(68		)	69		—			65,280
Results of operations	$	(858,833	)	$	213,280	$	4,339		$	303,654

There is no federal tax provision included in the results above for the years ended December 31, 2015, and December 31, 2014, or 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 years ended December 31, 2015 and 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 Securities and Exchange Commission (“SEC”) regulations, reserves at December 31, 2015, December 31, 2014, and December 31, 2013, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the U.S., is shown below:



	Successor
	Year Ended December 31, 2015								Year Ended December 31, 2014
	Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE		Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of year	144,410		19,992		687,037		278,908		170,903		16,459		280,117		234,048
Revisions of previous estimates	(40,348	)	(2,012	)	(270,030	)	(87,365	)	(9,256	)	(1,391	)	42,514		(3,561	)
Extensions, discoveries and other additions	793		34		4,693		1,610		20,056		379		35,552		26,360
Purchases of minerals in place	—		—		—		—		4,991		17,542		408,857		90,676
Sales of minerals in place	—		—		—		—		(28,890	)	(12,326	)	(51,065	)	(49,727	)
Production	(10,963	)	(1,061	)	(33,852	)	(17,666	)	(13,394	)	(671	)	(28,938	)	(18,888	)
End of year	93,892		16,953		387,848		175,487		144,410		19,992		687,037		278,908

Proved developed reserves	93,892		16,953		387,848		175,487		104,337		14,702		552,184		211,069
Proved undeveloped reserves	—		—		—		—		40,073		5,290		134,853		67,839
Total proved reserves	93,892		16,953		387,848		175,487		144,410		19,992		687,037		278,908



	Successor								Predecessor
	December 17, 2013 through December 31, 2013								January 1, 2013 through December 16, 2013
	Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE		Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of period	171,399		16,493		280,943		234,715		184,468		19,740		425,519		275,129
Revisions of previous estimates	—		—		—		—		(10,301	)	(3,235	)	(153,330	)	(39,092	)
Extensions, discoveries and other additions	—		—		—		—		9,360		1,595		29,756		15,913
Sales of minerals in place	—		—		—		—		(1,416	)	(847	)	(3,071	)	(2,775	)
Production	(496	)	(34	)	(826	)	(667	)	(10,712	)	(760	)	(17,931	)	(14,460	)
End of period	170,903		16,459		280,117		234,048		171,399		16,493		280,943		234,715

Proved developed reserves	113,717		7,977		202,798		155,494		114,213		8,011		203,624		156,161
Proved undeveloped reserves	57,186		8,482		77,319		78,554		57,186		8,482		77,319		78,554
Total proved reserves	170,903		16,459		280,117		234,048		171,399		16,493		280,943		234,715

The tables above include changes in estimated quantities of natural gas reserves shown in BOE using the ratio of six Mcf to one barrel.

Proved reserves decreased by approximately 103,421 MBOE to approximately 175,487 MBOE for the year ended December 31, 2015, from 278,908 MBOE for the year ended December 31, 2014. The year ended December 31, 2015, includes approximately 87,365 MBOE of negative revisions of previous estimates (71,389 MBOE due to lower commodity prices, 15,067 MBOE due to uncertainty regarding the Company’s future commitment to capital and 10,733 MBOE due to the SEC five-year development limitation on PUDs, partially offset by 9,824 MBOE of positive revisions due to asset performance). In addition, extensions and discoveries, primarily from 196 productive wells drilled during the year, contributed approximately 1,610 MBOE to the increase in proved reserves.

As a result of the uncertainty regarding the Company’s future commitment to capital, the Company reclassified all of its PUDs to unproved as of December 31, 2015. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for details regarding the Company’s going concern uncertainty.

The prices of oil, natural gas and NGL have continued to be volatile in 2016. In the future, if commodity prices continue to decline, the Company may have additional negative revisions which could have a material impact on its estimated quantities of oil, natural gas and NGL reserves. For information about potential risks that could affect the Company if lower commodity prices were to continue, see Item 1A. “Risk Factors.”

Proved reserves increased by approximately 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 3,547 MBOE of negative revisions due to asset performance and 2,910 MBOE due to the SEC five-year development limitation on PUDs, partially offset by 2,896 MBOE of positive revisions primarily due to higher natural gas prices. During the year ended December 31, 2014, properties acquired in the exchanges with ExxonMobil and Exxon XTO increased proved reserves by approximately 90,676 MBOE and the Permian Basin Assets Sale and properties relinquished in the exchanges with ExxonMobil and Exxon XTO 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.

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 because the Company is not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts are not material. See Note 4 for additional information about income taxes.



	December 31,
	2015			2014			2013
	(in thousands)

Future estimated revenues	$	5,483,899		$	16,844,678		$	17,863,984
Future estimated production costs	(3,458,415		)	(7,742,035		)	(6,654,536		)
Future estimated development costs	(332,311		)	(1,132,807		)	(1,854,849		)
Future net cash flows	1,693,173			7,969,836			9,354,599
10% annual discount for estimated timing of cash flows	(697,801		)	(3,639,459		)	(4,719,267		)
Standardized measure of discounted future net cash flows	$	995,372		$	4,330,377		$	4,635,332

Representative NYMEX prices:⁽¹⁾
Oil (Bbl)	$	50.16		$	95.27		$	96.89
Natural gas (MMBtu)	2.59			4.35			3.67


⁽¹⁾	In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.

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



	Successor
	December 31, 2015			December 31, 2014
	(in thousands)

Standardized measure–beginning of year	$	4,330,377		$	4,635,332
Sales and transfers of oil, natural gas and NGL produced during the period	(207,125		)	(794,337		)
Changes in estimated future development costs	431,622			68,290
Net change in sales and transfer prices and production costs related to future production	(3,203,620		)	(1,020,605		)
Extensions, discoveries and improved recovery	20,345			674,392
Purchases of minerals in place	—			548,256
Sales of minerals in place	—			(486,903		)
Previously estimated development costs incurred during the period	67,529			269,473
Net change due to revisions in quantity estimates	(544,334		)	(66,696		)
Accretion of discount	433,038			463,533
Changes in production rates and other	(332,460		)	39,642
Net decrease	(3,335,005		)	(304,955		)
Standardized measure–end of year	$	995,372		$	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

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, 2015

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)
2015:
Oil, natural gas and natural gas liquids sales	$	156,586		$	173,381		$	140,252		$	104,812
Electricity sales	5,151			6,609			8,610			4,174
Gains (losses) on oil and natural gas derivatives	3,267			(4,474		)	27,664			2,718
Total revenues and other	169,281			177,890			179,307			115,176
Total expenses ⁽¹⁾	474,938			191,222			696,633			218,155
(Gains) losses on sale of assets and other, net	(4,473		)	(811		)	2,633			732
Net loss	(322,725		)	(28,832		)	(537,158		)	(126,462		)



	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	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		)


⁽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, 2015

Accounting Policies [Abstract]

Nature of Business

Going Concern Uncertainty

As a result of these and other factors, the following issues have adversely impacted the Company’s ability to continue as a going concern:

•


•	because the Credit Facility is effectively fully drawn, any reduction of the borrowing base under the Company’s Credit Facility would require mandatory prepayments to the extent existing indebtedness exceeds the new borrowing base. The Company may not have sufficient cash on hand to be able to make any such mandatory prepayments; and


•	the Company’s ability to make interest payments as they become due and repay indebtedness upon maturities (whether under existing terms or as a result of acceleration) is impacted by the Company’s liquidity. As of February 29, 2016, there was less than $1 million of available borrowing capacity under the Credit Facility.

See Note 3 for additional details about the Company’s debt.

Principles of Reporting

Predecessor and Successor Reporting

Use of Estimates

Recently Issued Accounting Standards

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.

Accounts Receivable - Trade, Net

Accounts Receivable – Trade, Net

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

Based on the analysis described above, the Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties:



	Year Ended December 31,
	2015		2014
	(in thousands)

California operating area	$	537,511	$	22
Uinta Basin operating area	111,339		253,340
East Texas operating area	78,437		—
Piceance Basin operating area	55,344		—
	$	782,631	$	253,362

Unproved Properties

Exploration Costs

Oil and Natural Gas Properties

Proved Properties

Unproved Properties Disclosure

Unproved Properties

Other Property and Equipment

Income Taxes and Uncertain Tax Positions

Derivative Instruments

Fair Value of Financial Instruments

Deferred Financing Fees

Revenue Recognition

Restricted Cash

Business and Credit Concentrations

Electricity Cost Allocation

Basis of Presentation and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Details of Impairment of Long-Lived Assets Held and Used by Asset

Based on the analysis described above, the Company recorded the following noncash impairment charges (before and after tax) associated with proved oil and natural gas properties:



	Year Ended December 31,
	2015		2014
	(in thousands)

California operating area	$	537,511	$	22
Uinta Basin operating area	111,339		253,340
East Texas operating area	78,437		—
Piceance Basin operating area	55,344		—
	$	782,631	$	253,362

Other Current Assets

The components of other current assets are as follows:



	December 31,
	2015		2014
	(in thousands)

Prepaid expenses	$	1,903	$	1,210
California carbon allowance inventories	7,073		38,409
Oil inventories	3,446		4,034
Materials inventories	—		1,747
Deferred financing fees	8,108		—
Receivables from exchanges of properties and divestitures, and other	367		13,859
Other current assets	$	20,897	$	59,259

Other Accrued Liabilities

The components of other accrued liabilities are as follows:



	December 31,
	2015		2014
	(in thousands)

Accrued interest	$	14,096	$	15,803
Asset retirement obligations	2,548		3,101
Other	92		183
Other accrued liabilities	$	16,736	$	19,087

Supplemental Cash Flow Disclosures

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



	Successor						Predecessor
	Year Ended December 31, 2015		Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013
(in thousands)
Cash payments for interest, net of amounts capitalized	$	86,226	$	95,915	$	—	$	87,495
Cash payments for income taxes	$	—	$	—	$	—	$	622

Noncash investing activities:
Accrued capital expenditures	$	10,551	$	59,884	$	77,001	$	70,866

Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments



	December 31,
	2015			2014
	(in thousands, except percentages)

Credit facility ⁽¹⁾	$	873,175		$	1,173,175
6.75% senior notes due November 2020	261,100			299,970
6.375% senior notes due September 2022	572,700			599,163
Net unamortized premiums	11,568			14,644
Total debt, net	1,718,543			2,086,952
Less current portion ⁽²⁾	(873,175		)	—
Total long-term debt, net	$	845,368		$	2,086,952


⁽¹⁾	Variable interest rates of 3.17% and 2.67% at December 31, 2015, and December 31, 2014, respectively.

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments



	December 31, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)

Credit facility	$	873,175	$	873,175	$	1,173,175	$	1,173,175
Senior notes, net	845,368		200,249		913,777		699,462
Total debt, net	$	1,718,543	$	1,073,424	$	2,086,952	$	1,872,637

6.75% senior notes due November 2020

Debt Instrument [Line Items]

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



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

6.375% senior notes due September 2022

Debt Instrument [Line Items]

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



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

- Definition

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

+ References

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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
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-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
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-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
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-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 835
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-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=34725769&loc=d3e28878-108400

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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
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-Paragraph 1A
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
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-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

+ Details

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Income Tax Expense (Benefit)

Income tax expense (benefit) consisted of the following:



	Successor							Predecessor
	Year Ended December 31, 2015			Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013
(in thousands)
Current taxes:
Federal	$	—		$	—	$	—	$	(225	)
State	—			—		—		(11,043		)
Deferred taxes:
Federal	—			—		—		56,620
State	(68		)	69		—		19,928
	$	(68	)	$	69	$	—	$	65,280

Reconciliation of the Federal Statutory Tax Rate to the Effective Rate

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



	Successor						Predecessor
	Year Ended December 31, 2015		Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013

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

Deferred Tax Assets and Liabilities

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



	December 31, 2015		December 31, 2014
	(in thousands)
Deferred tax assets:
Net operating loss carryforwards	$	—	$	—
Other	—		—
	—		—
Deferred tax liabilities:
Property and equipment principally due to differences in depreciation	—		—
Other	1		69
	1		69
Net deferred tax liabilities	$	1	$	69

Unrecognized Tax Benefits

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, 2015		Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013
(in thousands)
Unrecognized tax benefits at beginning of period	$	—	$	—	$	—	$	22,553
Increases for positions taken in current year	—		—		—		50
Decreases for positions taken in a prior year	—		—		—		(635		)
Decreases for settlements with taxing authorities	—		—		—		—
Decreases for lapses in the applicable statute of limitations	—		—		—		(1,862		)
Unrecognized tax benefits at end of period	$	—	$	—	$	—	$	20,106

Equity Incentive Compensation Plans and Other Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2015

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

Schedule of stock options or units activity

The following table presents stock option activity under the predecessor’s Equity Incentive Plans for the period from January 1, 2013 through December 16, 2013:



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

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 Range of Exercise Prices

The following table presents 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 presents RSU activity under the predecessor’s Equity Incentive Plans for the period from January 1, 2013 through December 16, 2013:



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

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

The following table presents performance share award activity under the predecessor’s Equity Incentive Plans for the period from January 1, 2013 through December 16, 2013:



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

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	—		$	—

Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of derivative instruments

The following table presents derivative positions for the period indicated as of December 31, 2015:



	2016

Natural gas basis differential positions: ⁽¹⁾
NWPL Rockies basis swaps: ⁽²⁾
Hedged volume (MMMBtu)	11,712
Hedged differential ($/MMBtu)	$	(0.34	)
SoCal basis swaps: ⁽³⁾
Hedged volume (MMMBtu)	32,940
Hedged differential ($/MMBtu)	$	(0.03	)

Schedule of derivative assets and liabilities



	December 31,
	2015		2014
	(in thousands)
Assets:
Commodity derivatives	$	13,807	$	60,843
Liabilities:
Commodity derivatives	$	2,830	$	17,149

Derivative Instruments, Gain (Loss)

A summary of gains and losses on the derivatives included on the statements of operations is presented below:



	Successor							Predecessor
	Year Ended December 31, 2015		Year Ended December 31, 2014		December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013
(in thousands)
Gains (losses) on oil and natural gas derivatives	$	29,175	$	78,784	$	(5,049	)	$	(34,711	)
Lease operating expenses ⁽¹⁾	6,893		—		—			—
Total gains (losses) on oil and natural gas derivatives	$	36,068	$	78,784	$	(5,049	)	$	(34,711	)


⁽¹⁾	Consists of gains and (losses) on derivatives used to hedge exposure to differentials in consuming areas, which were entered into in March 2015.

- 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=56946850&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 815
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-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, 2015

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, 2015
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	13,807	$	(589	)	$	13,218
Liabilities:
Commodity derivatives	$	2,830	$	(589	)	$	2,241



	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	)	$	—


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

Other Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Other Property and Equipment [Abstract]

Other Property and Equiment

Other property and equipment consists of the following:



	December 31,
	2015			2014
	(in thousands)

Natural gas plant and pipeline	$	96,771		$	101,626
Buildings and leasehold improvements	5,884			6,559
Vehicles	4,647			3,759
Drilling and other equipment	113			28
Furniture and office equipment	3,879			3,826
Land	201			201
	111,495			115,999
Less accumulated depreciation	(12,522		)	(8,452		)
	$	98,973		$	107,547

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Summary of change in asset retirement obligations

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



	December 31,
	2015			2014
	(in thousands)

Asset retirement obligations at beginning of year	$	121,760		$	94,830
Liabilities added from drilling	1,270			5,124
Settlements	(683		)	(5,260		)
Liabilities added from acquisitions	—			25,223
Liabilities associated with assets divested	—			(5,460		)
Current year accretion expense	6,897			5,670
Revision of estimates	8,319			1,633
Asset retirement obligations at end of year	$	137,563		$	121,760

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Schedule of future minimum rental payments for operating leases

The following table presents the Company’s future minimum payments under noncancelable operating leases and other commitments as of December 31, 2015:



	Total		2016		2017		2018		2019		2020		Thereafter
(in thousands)
Operating leases⁽¹⁾	$	9,377	$	3,710	$	2,234	$	1,279	$	1,175	$	979	$	—
Firm natural gas transportation contracts⁽²⁾	146,981		33,446		33,417		23,972		22,528		19,123		14,495
Other commitments ⁽³⁾	2,442		2,442		—		—		—		—		—
Total	$	158,800	$	39,598	$	35,651	$	25,251	$	23,703	$	20,102	$	14,495


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


⁽²⁾	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 two to eight years and require a minimum monthly charge regardless of whether the contracted capacity is used or not


⁽³⁾	Other commitments relate primarily to cogeneration facility management services and equipment rental obligations.

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

12 Months Ended

Dec. 31, 2015

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, 2015		Year Ended December 31, 2014		December 17, 2013 through December 31, 2013		January 1, 2013 through December 16, 2013
(in thousands)
Property acquisition costs:
Proved	$	—	$	478,311	$	—	$	3,457
Unproved	—		—		—		463
Exploration costs	—		148		—		868
Development costs	130,276		555,629		22,266		577,568
Asset retirement costs	2,151		6,064		—		15,998
Total costs incurred ⁽¹⁾	$	132,427	$	1,040,152	$	22,266	$	598,354


⁽¹⁾	The total above does not reflect approximately $2 million, $6 million, $41,000 and $6 million of capitalized interest incurred for the years ended December 31, 2015, and December 31, 2014, and for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, 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,
	2015			2014
	(in thousands)

Oil and natural gas:
Proved properties	$	4,231,836		$	4,025,595
Unproved properties	779,225			846,464
	5,011,061			4,872,059
Less accumulated depletion and amortization	(1,596,165		)	(525,007		)
	$	3,414,896		$	4,347,052

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, 2015			Year Ended December 31, 2014		December 17, 2013 through December 31, 2013			January 1, 2013 through December 16, 2013
(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	575,031		$	1,298,402	$	50,324		$	1,103,245
Gains (losses) on oil and natural gas derivatives	29,175			78,784		(5,049		)	(34,711		)
	604,206			1,377,186		45,275			1,068,534
Production costs:
Lease operating expenses	245,155			364,540		15,410			295,811
Transportation expenses	52,160			41,842		2,576			46,774
Severance taxes, ad valorem taxes and California carbon allowances	70,591			97,683		2,130			57,063
	367,906			504,065		20,116			399,648
Other costs:
Exploration costs	—			—		—			24,048
Depletion and amortization	241,019			294,107		10,612			275,927
Impairment of long-lived assets	853,810			253,362		—			—
(Gains) losses on sale of assets and other, net	372			112,303		10,208			(23		)
	1,095,201			659,772		20,820			299,952
Income tax expense (benefit)	(68		)	69		—			65,280
Results of operations	$	(858,833	)	$	213,280	$	4,339		$	303,654

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, 2015								Year Ended December 31, 2014
	Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE		Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of year	144,410		19,992		687,037		278,908		170,903		16,459		280,117		234,048
Revisions of previous estimates	(40,348	)	(2,012	)	(270,030	)	(87,365	)	(9,256	)	(1,391	)	42,514		(3,561	)
Extensions, discoveries and other additions	793		34		4,693		1,610		20,056		379		35,552		26,360
Purchases of minerals in place	—		—		—		—		4,991		17,542		408,857		90,676
Sales of minerals in place	—		—		—		—		(28,890	)	(12,326	)	(51,065	)	(49,727	)
Production	(10,963	)	(1,061	)	(33,852	)	(17,666	)	(13,394	)	(671	)	(28,938	)	(18,888	)
End of year	93,892		16,953		387,848		175,487		144,410		19,992		687,037		278,908

Proved developed reserves	93,892		16,953		387,848		175,487		104,337		14,702		552,184		211,069
Proved undeveloped reserves	—		—		—		—		40,073		5,290		134,853		67,839
Total proved reserves	93,892		16,953		387,848		175,487		144,410		19,992		687,037		278,908



	Successor								Predecessor
	December 17, 2013 through December 31, 2013								January 1, 2013 through December 16, 2013
	Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE		Oil MBbls		NGL MBbls		Natural Gas MMcf		Total MBOE
Total proved reserves:
Beginning of period	171,399		16,493		280,943		234,715		184,468		19,740		425,519		275,129
Revisions of previous estimates	—		—		—		—		(10,301	)	(3,235	)	(153,330	)	(39,092	)
Extensions, discoveries and other additions	—		—		—		—		9,360		1,595		29,756		15,913
Sales of minerals in place	—		—		—		—		(1,416	)	(847	)	(3,071	)	(2,775	)
Production	(496	)	(34	)	(826	)	(667	)	(10,712	)	(760	)	(17,931	)	(14,460	)
End of period	170,903		16,459		280,117		234,048		171,399		16,493		280,943		234,715

Proved developed reserves	113,717		7,977		202,798		155,494		114,213		8,011		203,624		156,161
Proved undeveloped reserves	57,186		8,482		77,319		78,554		57,186		8,482		77,319		78,554
Total proved reserves	170,903		16,459		280,117		234,048		171,399		16,493		280,943		234,715

The tables above include changes in estimated quantities of natural gas reserves shown in BOE using the ratio of six Mcf to one barrel.

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

See Note 4 for additional information about income taxes.



	December 31,
	2015			2014			2013
	(in thousands)

Future estimated revenues	$	5,483,899		$	16,844,678		$	17,863,984
Future estimated production costs	(3,458,415		)	(7,742,035		)	(6,654,536		)
Future estimated development costs	(332,311		)	(1,132,807		)	(1,854,849		)
Future net cash flows	1,693,173			7,969,836			9,354,599
10% annual discount for estimated timing of cash flows	(697,801		)	(3,639,459		)	(4,719,267		)
Standardized measure of discounted future net cash flows	$	995,372		$	4,330,377		$	4,635,332

Representative NYMEX prices:⁽¹⁾
Oil (Bbl)	$	50.16		$	95.27		$	96.89
Natural gas (MMBtu)	2.59			4.35			3.67


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



	Successor
	December 31, 2015			December 31, 2014
	(in thousands)

Standardized measure–beginning of year	$	4,330,377		$	4,635,332
Sales and transfers of oil, natural gas and NGL produced during the period	(207,125		)	(794,337		)
Changes in estimated future development costs	431,622			68,290
Net change in sales and transfer prices and production costs related to future production	(3,203,620		)	(1,020,605		)
Extensions, discoveries and improved recovery	20,345			674,392
Purchases of minerals in place	—			548,256
Sales of minerals in place	—			(486,903		)
Previously estimated development costs incurred during the period	67,529			269,473
Net change due to revisions in quantity estimates	(544,334		)	(66,696		)
Accretion of discount	433,038			463,533
Changes in production rates and other	(332,460		)	39,642
Net decrease	(3,335,005		)	(304,955		)
Standardized measure–end of year	$	995,372		$	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

- 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=51678428&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=51678428&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=51678428&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=50486907&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=51678428&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=51678428&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=51678428&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=51678428&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, 2015

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data



	Successor
	Quarters Ended
	March 31			June 30			September 30			December 31
(in thousands)
2015:
Oil, natural gas and natural gas liquids sales	$	156,586		$	173,381		$	140,252		$	104,812
Electricity sales	5,151			6,609			8,610			4,174
Gains (losses) on oil and natural gas derivatives	3,267			(4,474		)	27,664			2,718
Total revenues and other	169,281			177,890			179,307			115,176
Total expenses ⁽¹⁾	474,938			191,222			696,633			218,155
(Gains) losses on sale of assets and other, net	(4,473		)	(811		)	2,633			732
Net loss	(322,725		)	(28,832		)	(537,158		)	(126,462		)



	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	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		)


⁽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) $ in Thousands			1 Months Ended	3 Months Ended	12 Months Ended
	Sep. 30, 2015 USD ($)	Dec. 31, 2013 USD ($)	May 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) Cogeneration_facilities	Sep. 30, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013	Dec. 16, 2013 USD ($)	Mar. 15, 2016 USD ($)
Successor
Accounting Policies
Credit facility				$ 1,173,175	$ 873,175		$ 1,173,175
Total Debt				2,086,952	1,718,543		2,086,952
Allowance for doubtful accounts receivable				0	0		0
Capitalized interest		$ 41			2,000		6,000
Impairment of Unproved Oil and Gas Properties		0					0		$ 0
Exploration costs		0			0		0
Impairment of Leasehold									16,000
Deferred Finance Costs, Current, Net				0	8,108		0
Deferred financing fees, noncurrent, net				12,000			12,000
Amortization of deferred financing fees		83			3,000		3,000
Write off of Deferred Debt Issuance Cost					3,000		0
Restricted cash				125	$ 250,359		125
Number of cogeneration facilities (in ones) \| Cogeneration_facilities					3
Settlement of advance to affiliate		$ 0			$ 129,217		$ 0
Capital contributions from affiliate					$ 471,278
Successor \| Minimum \| Buildings and leasehold improvements
Accounting Policies
Property, plant and equipment, useful life					10 years
Successor \| Minimum \| Natural gas plant and pipeline
Accounting Policies
Property, plant and equipment, useful life					2 years
Successor \| Maximum \| Buildings and leasehold improvements
Accounting Policies
Property, plant and equipment, useful life					39 years
Successor \| Maximum \| Natural gas plant and pipeline
Accounting Policies
Property, plant and equipment, useful life					30 years
Predecessor
Accounting Policies
Capitalized interest									6,000
Exploration costs									24,048
Amortization of deferred financing fees									5,000
Settlement of advance to affiliate									$ 0
Customer Concentration Risk [Member] \| Successor \| Electricity sales
Accounting Policies
Concentration risk, percentage					100.00%		100.00%	100.00%
Customer Concentration Risk [Member] \| Successor \| Major Customer 1 \| Oil, natural gas and NGL sales
Accounting Policies
Concentration risk, percentage		50.00%			24.00%		49.00%
Customer Concentration Risk [Member] \| Successor \| Major Customer 2 \| Oil, natural gas and NGL sales
Accounting Policies
Concentration risk, percentage		10.00%			23.00%		12.00%
Customer Concentration Risk [Member] \| Successor \| Major Customer 3 \| Oil, natural gas and NGL sales
Accounting Policies
Concentration risk, percentage					20.00%
Customer Concentration Risk [Member] \| Predecessor \| Major Customer 1 \| Oil, natural gas and NGL sales
Accounting Policies
Concentration risk, percentage									45.00%
Customer Concentration Risk [Member] \| Predecessor \| Major Customer 2 \| Oil, natural gas and NGL sales
Accounting Policies
Concentration risk, percentage									10.00%
Credit Concentration Risk [Member] \| Successor \| Major Customer 1 \| Trade Accounts Receivable [Member]
Accounting Policies
Concentration risk, percentage					24.00%		36.00%
Credit Concentration Risk [Member] \| Successor \| Major Customer 2 \| Trade Accounts Receivable [Member]
Accounting Policies
Concentration risk, percentage					22.00%		10.00%
Credit Concentration Risk [Member] \| Successor \| Major Customer 3 \| Trade Accounts Receivable [Member]
Accounting Policies
Concentration risk, percentage					11.00%
Restricted Cash for Debt Agreement [Member] \| Successor
Accounting Policies
Restricted cash					$ 250,000
Linn Energy, LLC [Member]
Accounting Policies
Capital expenditures paid by affiliate				58,000		$ 223,000
Settlement of advance to affiliate	$ 129,000
Capital contributions from affiliate			$ 250,000
Linn Energy, LLC [Member] \| Successor
Accounting Policies
Capital expenditures paid by affiliate				58,000	165,000	$ 223,000
Increase (Decrease) Due from Affiliates					165,000
Settlement of advance to affiliate	$ 129,000
Capital contributions from affiliate			$ 250,000		250,000
California operating area \| Successor
Accounting Policies
Impairment of Unproved Oil and Gas Properties					71,000
Line of Credit [Member]
Accounting Policies
Remaining borrowing capacity available under the agreement					1,000
Line of Credit [Member] \| Successor
Accounting Policies
Remaining borrowing capacity available under the agreement					1,000
Credit Facility \| Credit Facility \| Successor
Accounting Policies
Credit facility				$ 1,173,175	$ 873,175		$ 1,173,175
Subsequent Event [Member] \| 6.375% senior notes due September 2022 \| Successor
Accounting Policies
Deferred interest payment										$ 18,000
Percent of aggregate outstanding debt										25.00%

Basis of Presentation and Significant Accounting Policies Impairment (Details) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 16, 2013
Successor
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	$ 0	$ 782,631	$ 253,362
Successor \| California operating area [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets		537,511	22
Successor \| Uinta Basin operating area [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets		111,339	253,340
Successor \| East Texas operating area [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets		78,437	0
Successor \| Piceance Basin operating area [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets		$ 55,344	$ 0
Predecessor
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets				$ 0

Basis of Presentation and Significant Accounting Policies (Other Current Assets) (Details) - Successor - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Other Current Assets [Line Items]
Prepaid expenses	$ 1,903	$ 1,210
California carbon allowance inventories	7,073	38,409
Oil inventories	3,446	4,034
Materials inventories	0	1,747
Deferred financing fees	8,108	0
Receivables from exchanges of properties and divestitures, and other	367	13,859
Other current assets	$ 20,897	$ 59,259

Basis of Presentation and Significant Accounting Policies (Other Accrued Liabilities) (Details) - Successor - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accrued interest	$ 14,096	$ 15,803
Asset retirement obligations	2,548	3,101
Other	92	183
Other accrued liabilities	$ 16,736	$ 19,087

Basis of Presentation and Significant Accounting Policies (Supplemental Cash Flow Data) (Details) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 16, 2013
Successor
Supplemental disclosures to the statements of cash flows [Line Items]
Cash payments for interest, net of amounts capitalized	$ 0	$ 86	$ 95,915
Cash payments for income taxes	0	0	0
Accrued capital expenditures	$ 77,001	$ 11	$ 59,884
Predecessor
Supplemental disclosures to the statements of cash flows [Line Items]
Cash payments for interest, net of amounts capitalized				$ 87,495
Cash payments for income taxes				622
Accrued capital expenditures				$ 70,866

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 Transaction
Business Combination, Acquisition Related Costs	$ 16		$ 45
Linn Merger
LINN Energy Transaction
Preliminary value of acquisition		$ 4,600
Long-term debt assumed		2,300	2,300
Cash acquired		$ 451	$ 451
Berry and LinnCo
LINN Energy Transaction
Exchange ratio		168.00%
Number of shares issued in merger		93,756,674
Linn Energy LLC and LinnCo
LINN Energy Transaction
Exchange ratio		100.13%
Number of shares issued in merger		93,756,674

Acquisitions and Divestitures (Details ) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2015	Dec. 31, 2014
Exxon Exchange II [Member]
Exchanges of Properties and Divestiture
Gain (loss) on sale of oil and natural gas property				$ 30
Exxon Exchange I [Member]
Exchanges of Properties and Divestiture
Gain (loss) on sale of oil and natural gas property				34
Permian basin assets [Member]
Exchanges of Properties and Divestiture
Proceeds from sale of assets				352
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
Linn Energy, LLC [Member]
Exchanges of Properties and Divestiture
Capital expenditures paid by affiliate		$ 58	$ 223
Settlement of advance to affiliate	$ 129

Debt (Details) - USD ($)	1 Months Ended		12 Months Ended
Debt (Details) - USD ($)	Oct. 31, 2015	May 31, 2015	Dec. 31, 2015	Sep. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
Debt Instrument
Percent of future net income allowable to increase Berry's restricted payments basket			50.00%
6.75% senior notes due November 2020
Debt Instrument
Interest rate on debt instrument (as a percent)			6.75%
6.375% senior notes due September 2022
Debt Instrument
Interest rate on debt instrument (as a percent)			6.375%
Line of Credit [Member]
Debt Instrument
Credit facility, maximum borrowing capacity	$ 900,000,000		$ 900,000,000	$ 1,200,000,000.0	$ 1,400,000,000.0
Line of Credit Facility, Current Borrowing Capacity			900,000,000
Remaining borrowing capacity available under the agreement			$ 1,000,000
Credit facility, portion of properties required to maintain mortgages	90.00%		90.00%	80.00%
Debt Instrument, Change in basis spread on variable rate			0.25%
Credit facility, unused capacity, commitment fee percentage			0.50%
Maximum Junior Lien Debt			$ 500,000,000
Line of Credit Facility Collateral Coverage Ratio			2.5
Repayments of Long-term Debt	$ 300,000,000
Line of Credit [Member] \| Minimum
Debt Instrument
Credit facility, unused capacity, commitment fee percentage			0.50%
Successor
Debt Instrument
Capital contributions from affiliate			$ 471,278,000
Successor \| Credit Facility \| Credit Facility
Debt Instrument
Credit facility, variable interest rate			3.17%			2.67%
Successor \| Line of Credit [Member]
Debt Instrument
Remaining borrowing capacity available under the agreement			$ 1,000,000
London Interbank Offered Rate (LIBOR) [Member] \| Line of Credit [Member] \| Minimum
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)			1.75%
London Interbank Offered Rate (LIBOR) [Member] \| Line of Credit [Member] \| Maximum
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)			2.75%
Prime Rate [Member] \| Line of Credit [Member] \| Minimum
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)			0.75%
Prime Rate [Member] \| Line of Credit [Member] \| Maximum
Debt Instrument
Credit facility, margin rate over LIBOR (as a percent)			1.75%
December 31, 2015 and December 31, 2016 [Member] \| Line of Credit [Member]
Debt Instrument
Line of Credit Facility Collateral Coverage Ratio			2
March 31, 2017 and June 30, 2017 [Member] \| Line of Credit [Member]
Debt Instrument
Line of Credit Facility Collateral Coverage Ratio			2.25
Subsequent to June 30, 2017 [Member] \| Line of Credit [Member]
Debt Instrument
Line of Credit Facility Collateral Coverage Ratio			2.5
Linn Energy, LLC [Member]
Debt Instrument
Capital contributions from affiliate		$ 250,000,000
Linn Energy, LLC [Member] \| Successor
Debt Instrument
Capital contributions from affiliate		$ 250,000,000	$ 250,000,000

Debt Debt schedule of long term debt (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	May 30, 2014	Dec. 16, 2013
6.75% senior notes due November 2020
Debt Instrument
Net unamortized premiums				$ 10,000
6.375% senior notes due September 2022
Debt Instrument
Net unamortized premiums				$ 7,000
Successor
Debt Instrument
Credit facility	$ 873,175	$ 1,173,175
Senior notes, net	845,368	913,777
Total debt, net	1,718,543	2,086,952
Less current portion (2)	(873,175)	0
Total long-term debt, net	845,368	2,086,952
Credit Facility \| Successor \| Credit Facility
Debt Instrument
Credit facility	$ 873,175	$ 1,173,175
Credit facility, variable interest rate	3.17%	2.67%
Senior Notes [Member] \| 10.25% Senior notes due 2014
Debt Instrument
Senior notes, net			$ 205,000
Senior Notes [Member] \| Successor
Debt Instrument
Net unamortized premiums	$ 11,568	$ 14,644
Senior Notes [Member] \| Successor \| 6.75% senior notes due November 2020
Debt Instrument
Senior notes, net	261,100	299,970
Senior Notes [Member] \| Successor \| 6.375% senior notes due September 2022
Debt Instrument
Senior notes, net	$ 572,700	$ 599,163

Debt Debt fair value disclosure (Details) - Successor - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Carrying Value
Credit facility	$ 873,175	$ 1,173,175
Senior notes, net	845,368	913,777
Total debt, net	1,718,543	2,086,952
Fair Value
Credit facility	873,175	1,173,175
Senior notes, net	200,249	699,462
Total debt, net	$ 1,073,424	$ 1,872,637

- 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

Debt 6.75% Senior Notes Due 2020 (Details) - 6.75% Senior notes due 2020 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 16, 2013
Debt Instrument
Interest rate on debt instrument (as a percent)	6.75%
Senior notes	$ 261
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) - 6.375% senior notes due September 2022 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 16, 2013
Debt Instrument
Interest rate on debt instrument (as a percent)	6.375%
Senior notes	$ 573
Long-term debt, fair value		$ 607
Net unamortized premiums		$ 7
March 15, 2017 through March 14, 2018
Debt Instrument
Debt Instrument, Redemption Price, Percentage	103.188%
March 15, 2018 through March 14, 2019
Debt Instrument
Debt Instrument, Redemption Price, Percentage	102.125%
March 15, 2019 through March 14, 2020
Debt Instrument
Debt Instrument, Redemption Price, Percentage	101.063%
March 15, 2020 and thereafter
Debt Instrument
Debt Instrument, Redemption Price, Percentage	100.00%
March 9, 2012 through March 14, 2017
Debt Instrument
Debt Instrument, Redemption Price, Percentage	100.00%
Minimum
Debt Instrument
Senior Notes Redemption Price, Notice Period Range in Days	30 days
Maximum
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	12 Months Ended
	Feb. 28, 2014	Dec. 31, 2015	Dec. 31, 2014	May 30, 2014
6.75% senior notes due November 2020
Debt Instrument
Interest rate on debt instrument (as a percent)		6.75%
6.375% senior notes due September 2022
Debt Instrument
Interest rate on debt instrument (as a percent)		6.375%
Senior Notes [Member]
Debt Instrument
Debt repurchase amount		$ 65,000
Repayments of Long-term Debt		55,000
Gain on extinguishment of debt		11,000
Senior Notes [Member] \| 10.25% Senior notes due 2014
Debt Instrument
Debt repurchase amount	$ 321,000
Interest rate on debt instrument (as a percent)			10.25%	10.25%
Senior notes, net				$ 205,000
Senior Notes [Member] \| 6.75% senior notes due November 2020
Debt Instrument
Debt repurchase amount	30,000	$ 39,000
Interest rate on debt instrument (as a percent)		6.75%
Senior Notes [Member] \| 6.375% senior notes due September 2022
Debt Instrument
Debt repurchase amount	$ 837,000	$ 26,000
Interest rate on debt instrument (as a percent)		6.375%

Income Taxes (Schedule of Components of Income Tax Expense (Benefit)) (Details) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 16, 2013
Successor
Current taxes:
Federal	$ 0	$ 0	$ 0
State	0	0	0
Deferred taxes:
Federal	0	0	0
State	0	(68)	69
Income tax expense (benefit)	$ 0	$ (68)	$ 69
Predecessor
Current taxes:
Federal				$ (225)
State				(11,043)
Deferred taxes:
Federal				56,620
State				19,928
Income tax expense (benefit)				$ 65,280

Income Taxes (Schedule of Effective Income Tax Rate Reconciliation) (Details)		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 16, 2013
Successor
Reconciliation of the federal statutory tax rate to the effective tax rate
Federal statutory rate	35.00%	35.00%	35.00%
State, net of federal tax benefit	0.00%	0.00%	0.00%
Income excluded from nontaxable entities	(35.00%)	(35.00%)	(35.00%)
Net impact to uncertain income tax positions	0.00%	0.00%	0.00%
Transaction costs	0.00%	0.00%	0.00%
Other	0.00%	0.00%	0.00%
Effective rate	0.00%	0.00%	0.00%
Predecessor
Reconciliation of the federal statutory tax rate to the effective tax rate
Federal statutory rate				35.00%
State, net of federal tax benefit				3.00%
Income excluded from nontaxable entities				(0.00%)
Net impact to uncertain income tax positions				(2.00%)
Transaction costs				4.00%
Other				1.00%
Effective rate				41.00%

Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - Successor - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
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	1	69
Deferred tax liabilities, gross	1	69
Net deferred tax liabilities	$ 1	$ 69

Income Taxes (Summary of Income Tax Contingencies) (Details) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 16, 2013
Successor
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits at beginning of period	$ 0	$ 0	$ 0
Increases for positions taken in current year	0	0	0
Decreases for positions taken in a prior year	0	0	0
Decreases for settlements with taxing authorities	0	0	0
Decreases for lapses in the applicable statute of limitations	0	0	0
Unrecognized tax benefits at end of period	$ 0	$ 0	$ 0
Predecessor
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits at beginning of period				$ 22,553
Increases for positions taken in current year				50
Decreases for positions taken in a prior year				(635)
Decreases for settlements with taxing authorities				0
Decreases for lapses in the applicable statute of limitations				(1,862)
Unrecognized tax benefits at end of period				20,106
Unrecognized tax benefits, period decrease				$ 2,000

Member's and Shareholders' Equity (Details) - Predecessor	12 Months Ended
	Dec. 16, 2013 USD ($) $ / shares shares
Class of Stock [Line Items]
Dividends per share \| $ / shares	$ 0.32
Class A
Class of Stock [Line Items]
Common stock, voting rights	1
Class B
Class of Stock [Line Items]
Common stock, voting rights	.95
Common stock liquidation preference value \| $ / shares	$ 0.50
Conversion of stock, shares \| shares	1
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 \| $ / shares	$ 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	May 31, 2010	May 31, 2005
Share-based Compensation Arrangement by Share-based Payment Award
Employee participation in 401(k) Plan (as a percent)		93.00%
Company's contributions to 401(k) Plan, net of forfeitures		$ 2
Term of options granted under plan		10 years
Total compensation cost		$ 12
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
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 \| 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 \| 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) $ / shares in Units, $ in Thousands		12 Months Ended
	Dec. 16, 2013 USD ($) $ / shares shares	Dec. 16, 2013 USD ($) $ / shares shares
Number of Shares
Outstanding shares at the beginning of the period \| shares		1,387,592
Shares exercised \| shares		(57,350)
Outstanding shares at the end of the period \| shares	1,330,242.000	1,330,242.000
Vested and expected to vest at December 16, 2013 \| shares	1,328,771	1,328,771
Exercisable at December 16, 2013 \| shares	1,224,022	1,224,022
Weighted Average Exercise Price
Outstanding at the beginning of the period (in dollars per share) \| $ / shares		$ 33.71
Exercised (in dollars per share) \| $ / shares		12.74
Outstanding at the end of the period (in dollars per share) \| $ / shares	$ 34.61	34.61
Vested and expected to vest at December 16, 2013 \| $ / shares	34.60	34.60
Exercisable at December 16, 2013 \| $ / shares	$ 33.18	$ 33.18
Aggregate Intrinsic Value (in thousands) (1)
Outstanding at the beginning of the period \| $		$ 4,681
Exercised \| $		2,066
Outstanding at the end of the period \| $	$ 19,243	19,243
Vested and expected to vest at December 16, 2014 \| $	19	19
Exercisable at December 16, 2013 \| $	$ 19,229	$ 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

Equity Incentive Compensation Plans (Range of Exercise Prices) (Details) - $ / shares		12 Months Ended
	Dec. 16, 2013	Dec. 16, 2013	Dec. 31, 2012
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
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
Restricted Stock Units (RSUs) [Member]
Performance Share Awards
Outstanding shares at the beginning of the period \| shares	981,877
Granted \| shares	286,344
Issued \| shares	(853,169)
Canceled/expired \| shares	(22,511)
Outstanding shares at the end of the period \| shares	392,541
Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per share) \| $ / shares	$ 26.72
Granted (in dollars per share) \| $ / shares	45.51
Issued (in dollars per share) \| $ / shares	23.94
Canceled/expired (in dollars per share) \| $ / shares	44.69
Outstanding at the end of the period (in dollars per share) \| $ / shares	$ 46.86
Vest Date Fair Value
Issued \| $	$ 39,513
Performance Shares [Member]
Performance Share Awards
Outstanding shares at the beginning of the period \| shares	222,587
Issued \| shares	(135,167)
Canceled/expired \| shares	(87,420)
Outstanding shares at the end of the period \| shares	0
Weighted Average Grant Date Fair Value
Outstanding at the beginning of the period (in dollars per share) \| $ / shares	$ 45.79
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
Vest Date Fair Value
Issued \| $	$ 6,308

Equity Incentive Compensation Plans and Other Benefit Plans (Director Fees and Other Employee Benefits-401(k) Plan) (Details) $ in Millions	12 Months Ended
	Dec. 16, 2013 USD ($) shares
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
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) \| shares	10,758

Derivative Instruments (Details) $ in Thousands		3 Months Ended	12 Months Ended
Derivative Instruments (Details) $ in Thousands	Dec. 31, 2013 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) MBbl $ / bbl	Dec. 31, 2014 USD ($) MBbl $ / bbl	Dec. 16, 2013 USD ($)
Successor
Notional amount of derivative instruments
Cash settlements on canceled derivatives	$ 0	$ 12,000	$ 0	$ 12,281
Derivative, Nonmonetary Notional Amount, Volume \| MBbl			3,859	9,125
Average contract price on oil settled derivatives per unit \| $ / bbl			67.66	92.16
Predecessor
Notional amount of derivative instruments
Cash settlements on canceled derivatives					$ 0

Derivative Instruments Derivative Instruments (Commodity Derivatives) (Details) - 2016 [Member] - Natural gas basis differential commodity contract [Member]

Dec. 31, 2015

mmbls

$ / mmbls

^[2]

NWPL Rockies basis swaps: (2)

Derivative [Line Items]

Hedged volume (MMMBtu) | mmbls

11,712

^[1]

Hedged differential ($/MMBtu) | $ / mmbls

(0.34)

^[1]

SoCal basis swaps: (3)

Derivative [Line Items]

Hedged volume (MMMBtu) | mmbls

32,940

^[3]

Hedged differential ($/MMBtu) | $ / mmbls

(0.03)

^[3]

[1]	For positions which hedge exposure to differentials in producing areas, the Company receives the NYMEX Henry Hub natural gas price plus the respective spread and pays the specified index price. Cash settlements are made on a net basis.
[2]	Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.
[3]	For positions which hedge exposure to differentials in consuming areas, the Company pays the NYMEX Henry Hub natural gas price plus the respective spread and receives the specified index price. Cash settlements are made on a net basis.

Derivative Instruments Derivative Instruments Balance Sheet Presentation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
ASSETS
Commodity derivatives	$ 13,807	$ 60,843
Liabilities:
Commodity derivatives	2,830	17,149
Successor
ASSETS
Commodity derivatives	13,807	60,843
Liabilities:
Commodity derivatives	2,830	$ 17,149
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 14,000

Derivative Instruments Derivative Instruments Income Statement Location (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 16, 2013

Successor

Derivative [Line Items]

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

$ (5,049)

$ 2,718

$ 27,664

$ (4,474)

$ 3,267

$ 55,891

$ 44,990

$ (25,562)

$ 3,465

$ 36,068

$ 78,784

Predecessor

Derivative [Line Items]

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

$ (34,711)

Gains (losses) on oil and natural gas derivatives | Successor

Derivative [Line Items]

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

(5,049)

29,175

78,784

Gains (losses) on oil and natural gas derivatives | Predecessor

Derivative [Line Items]

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

(34,711)

Lease operating expenses (1) | Successor

Derivative [Line Items]

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

^[1]

$ 0

$ 6,893

$ 0

Lease operating expenses (1) | Predecessor

Derivative [Line Items]

Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net

^[1]

$ 0

[1]	Consists of gains and (losses) on derivatives used to hedge exposure to differentials in consuming areas, which were entered into in March 2015.

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

Dec. 31, 2015

Dec. 31, 2014

Assets:

Commodity derivatives

$ 13,807

$ 60,843

Commodity derivatives

^[1]

(589)

(17,149)

Commodity derivatives

13,218

43,694

Liabilities:

Commodity derivatives

2,830

17,149

Commodity derivatives

^[1]

(589)

(17,149)

Commodity derivatives

$ 2,241

$ 0

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

Other Property and Equipment (Details) - Successor - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 111,495	$ 115,999
Less accumulated depreciation	(12,522)	(8,452)
Other property and equipment, net	98,973	107,547
Natural gas plant and pipeline
Property, Plant and Equipment [Line Items]
Other property and equipment	96,771	101,626
Buildings and leasehold improvements
Property, Plant and Equipment [Line Items]
Other property and equipment	5,884	6,559
Vehicles
Property, Plant and Equipment [Line Items]
Other property and equipment	4,647	3,759
Drilling and other equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	113	28
Furniture and office equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	3,879	3,826
Land
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 201	$ 201

Asset Retirement Obligations (Details) - Successor - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations [Line Items]
Asset retirement obligations at beginning of year	$ 121,760	$ 94,830
Liabilities added from drilling	1,270	5,124
Settlements	(683)	(5,260)
Liabilities added from acquisitions	0	25,223
Liabilities associated with assets divested	0	(5,460)
Current year accretion expense	6,897	5,670
Revision of estimates	8,319	1,633
Asset retirement obligations at end of year	$ 137,563	$ 121,760

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2015

Dec. 31, 2014

Dec. 16, 2013

Operating leases

Operating Leases, Rent Expense, Net

$ 302

$ 6,000

$ 5,000

Operating Leases, Future Minimum Payments Due

Operating leases, future minimum payments due

^[1]

9,377

Operating leases, future minimum payments due, current

^[1]

3,710

Operating leases, future minimum payments, due in two years

^[1]

2,234

Operating leases, future minimum payments, due in three years

^[1]

1,279

Operating leases, future minimum payments, due in four years

^[1]

1,175

Operating leases, future minimum payments, due in five years

^[1]

979

Operating leases, future minimum payments, due after fifth year

^[1]

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

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

158,800

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

39,598

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

35,651

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

25,251

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

23,703

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

20,102

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

14,495

Other commitments

Unrecorded Unconditional Purchase Obligation Payment Schedule

Unrecorded unconditional purchase obligation due

^[2]

2,442

Unrecorded unconditional purchase obligation due, current

^[2]

2,442

Unrecorded unconditional purchase obligation due in second year

^[2]

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]

146,981

Unrecorded unconditional purchase obligation due, current

^[3]

33,446

Unrecorded unconditional purchase obligation due in second year

^[3]

33,417

Unrecorded unconditional purchase obligation due in third year

^[3]

23,972

Unrecorded unconditional purchase obligation due in fourth year

^[3]

22,528

Unrecorded unconditional purchase obligation due in fifth year

^[3]

19,123

Unrecorded unconditional purchase obligation due after fifth year

^[3]

$ 14,495

[1]	Operating leases relate primarily to obligations associated with the Company’s office facilities, rail cars and vehicles.
[2]	Other commitments relate primarily to cogeneration facility management services and equipment rental 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 two to eight 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 ($)	Dec. 31, 2015 USD ($) a	Dec. 31, 2014 USD ($)	Dec. 16, 2013 USD ($)
Loss Contingencies [Line Items]
Gathering System, Book Value		$ 5,000,000
Accrual for Environmental Loss Contingencies		0
Payments for Legal Settlements	$ 0	0	$ 0	$ 0
Operating Leases, Rent Expense, Net	$ 302,000	6,000,000	$ 6,000,000	$ 5,000,000
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

Related Party Transactions (Details) - USD ($)						1 Months Ended	3 Months Ended		12 Months Ended
Related Party Transactions (Details) - USD ($)	Sep. 30, 2015	Dec. 31, 2013	Dec. 31, 2013	Dec. 19, 2013	Dec. 16, 2013	May 31, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	May 30, 2014
Linn Energy, LLC [Member]
Related Party Transaction
Capital contributions from affiliate						$ 250,000,000
Capital expenditures paid by affiliate							$ 58,000,000			$ 223,000,000
Settlement of advance to affiliate	$ 129,000,000
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
Capital contributions from affiliate									$ 471,278,000
Proceeds from Contributions from Parent								$ 220,000,000
Distribution to affiliate		$ 435,000,000	$ 435,000,000	$ 435,000,000					88,946,000		$ 119,079,000
Proceeds from sale of properties and equipment and other		0							22,525,000		7,667,000
Settlement of advance to affiliate		0							129,217,000		0
Transfer of derivative liability from affiliate		31,000,000	$ 31,428,000
Successor \| Linn Operating, Inc. [Member]
Related Party Transaction
Management Fee Expense		$ 20,000,000							78,000,000		86,000,000
Due to Affiliate							13,000,000		9,000,000		13,000,000
Successor \| Linn Energy, LLC [Member]
Related Party Transaction
Capital contributions from affiliate						$ 250,000,000			250,000,000
Capital expenditures paid by affiliate							$ 58,000,000		165,000,000	$ 223,000,000
Settlement of advance to affiliate	$ 129,000,000
Successor \| Superior Energy Services, Inc. [Member]
Related Party Transaction
Payments to related party									$ 562,000		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											352,000,000
Permian basin assets [Member] \| Successor
Related Party Transaction
Proceeds from sale of properties and equipment and other											$ 352,000,000
Senior Notes [Member] \| 10.25% Senior notes due 2014
Related Party Transaction
Interest rate on debt instrument (as a percent)							10.25%				10.25%	10.25%

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

12 Months Ended

Dec. 31, 2013

Dec. 31, 2015

Dec. 31, 2014

Dec. 16, 2013

Successor

Property acquisition costs:

Proved

$ 0

$ 478,311

Unproved

Exploration costs

148

Development costs

22,266

130,276

555,629

Asset retirement costs

2,151

6,064

Total costs incurred (1)

^[1]

22,266

132,427

1,040,152

Capitalized interest

$ 41

2,000

6,000

Oil and natural gas:

Proved properties

4,231,836

4,025,595

Unproved properties

779,225

846,464

Total Oil and natural gas properties

5,011,061

4,872,059

Less accumulated depletion and amortization

(1,596,165)

(525,007)

Total oil and natural gas properties, net

$ 3,414,896

$ 4,347,052

Predecessor

Property acquisition costs:

$ 3,457

463

868

577,568

Asset retirement costs

15,998

Total costs incurred (1)

^[1]

598,354

Capitalized interest

$ 6,000

[1]

The total above does not reflect approximately $2 million, $6 million, $41,000 and $6 million of capitalized interest incurred for the years ended December 31, 2015, and December 31, 2014, and for the periods from December 17, 2013 through December 31, 2013, and January 1, 2013 through December 16, 2013, respectively.

Supplemental Oil & Natural Gas Data (Unaudited) Results of Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands		12 Months Ended
	Dec. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 16, 2013
Successor
Revenues and other:
Oil, natural gas and natural gas liquids sales	$ 50,324	$ 575,031	$ 1,298,402
Gains (losses) on oil and natural gas derivatives	(5,049)	29,175	78,784
Total revenue from oil and gas producing activities	45,275	604,206	1,377,186
Production costs:
Lease operating expenses	15,410	245,155	364,540
Transportation expenses	2,576	52,160	41,842
Severance taxes, ad valorem taxes and California carbon allowances	2,130	70,591	97,683
Results of Operations, Expense from Oil and Gas Producing Activities	20,116	367,906	504,065
Other costs:
Exploration costs	0	0	0
Depletion and amortization	10,612	241,019	294,107
Impairment of long-lived assets	0	853,810	253,362
(Gains) losses on sale of assets and other, net	10,208	372	112,303
Total other costs	20,820	1,095,201	659,772
Income tax expense (benefit)	0	(68)	69
Results of operations	4,339	(858,833)	213,280
Predecessor
Revenues and other:
Oil, natural gas and natural gas liquids sales				$ 1,103,245
Gains (losses) on oil and natural gas derivatives				(34,711)
Total revenue from oil and gas producing activities				1,068,534
Production costs:
Lease operating expenses				295,811
Transportation expenses				46,774
Severance taxes, ad valorem taxes and California carbon allowances				57,063
Results of Operations, Expense from Oil and Gas Producing Activities				399,648
Other costs:
Exploration costs				24,048
Depletion and amortization				275,927
Impairment of long-lived assets				0
(Gains) losses on sale of assets and other, net				(23)
Total other costs				299,952
Income tax expense (benefit)				65,280
Results of operations				$ 303,654
Federal Tax \| Successor
Other costs:
Income tax expense (benefit)	$ 0	$ 0	$ 0

Supplemental Oil & Natural Gas Data (Unaudited) Reserve Quantities (Details) bbl in Thousands, Mcf in Thousands		12 Months Ended
	Dec. 31, 2013 MBoe bbl Mcf	Dec. 31, 2015 MBoe Wells bbl Mcf	Dec. 31, 2014 MBoe Wells bbl Mcf	Dec. 16, 2013 MBoe Wells bbl Mcf	Dec. 31, 2015 MBoe bbl Mcf	Dec. 31, 2014 MBoe bbl Mcf	Dec. 31, 2013 MBoe bbl Mcf	Dec. 16, 2013 MBoe bbl Mcf
Successor
Total proved reserves:
Beginning of year \| MBoe	234,715	278,908	234,048
Revisions of previous estimates \| MBoe	0	(87,365)	(3,561)
Extensions, discoveries and other additions \| MBoe	0	1,610	26,360
Purchases of minerals in place \| MBoe		0	90,676
Sales of minerals in place \| MBoe	0	0	(49,727)
Production \| MBoe	(667)	(17,666)	(18,888)
End of year \| MBoe	234,048	175,487	278,908	234,715
Proved developed reserves \| MBoe					175,487	211,069	155,494
Proved undeveloped reserves \| MBoe					0	67,839	78,554
Total proved reserves \| MBoe	234,048	278,908	234,048	234,715	175,487	278,908	234,048	234,715
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) \| MBoe	(667)	(103,421)	44,860
Change in proved reserves due to commodity prices \| MBoe		(71,389)	2,896
Change in proved reserves due to the uncertainty of future capital commitments \| MBoe		(15,067)
Change in proved reserves due to the SEC five-year development limitation on puds \| MBoe		(10,733)	(2,910)
Change in proved reserves due to asset performance \| MBoe		9,824	(3,547)
Wells Drilled Gross Productive \| Wells		196	411
Successor \| Oil
Total proved reserves:
Beginning of year	171,399	144,410	170,903
Revisions of previous estimates	0	(40,348)	(9,256)
Extensions, discoveries and other additions	0	793	20,056
Purchases of minerals in place		0	4,991
Sales of minerals in place	0	0	(28,890)
Production	(496)	(10,963)	(13,394)
End of year	170,903	93,892	144,410	171,399
Proved developed reserves					93,892	104,337	113,717
Proved undeveloped reserves					0	40,073	57,186
Total proved reserves	170,903	144,410	170,903	171,399	93,892	144,410	170,903	171,399
Successor \| Natural Gas Liquids [Member]
Total proved reserves:
Beginning of year	16,493	19,992	16,459
Revisions of previous estimates	0	(2,012)	(1,391)
Extensions, discoveries and other additions	0	34	379
Purchases of minerals in place		0	17,542
Sales of minerals in place	0	0	(12,326)
Production	(34)	(1,061)	(671)
End of year	16,459	16,953	19,992	16,493
Proved developed reserves					16,953	14,702	7,977
Proved undeveloped reserves					0	5,290	8,482
Total proved reserves	16,459	19,992	16,459	16,493	16,953	19,992	16,459	16,493
Successor \| Natural gas
Total proved reserves:
Beginning of year \| Mcf	280,943	687,037	280,117
Revisions of previous estimates \| Mcf	0	(270,030)	42,514
Extensions, discoveries and other additions \| Mcf	0	4,693	35,552
Purchases of minerals in place \| Mcf		0	408,857
Sales of minerals in place \| Mcf	0	0	(51,065)
Production \| Mcf	(826)	(33,852)	(28,938)
End of year \| Mcf	280,117	387,848	687,037	280,943
Proved developed reserves \| Mcf					387,848	552,184	202,798
Proved undeveloped reserves \| Mcf					0	134,853	77,319
Total proved reserves \| Mcf	280,117	687,037	280,117	280,943	387,848	687,037	280,117	280,943
Predecessor
Total proved reserves:
Beginning of year \| MBoe	234,715			275,129
Revisions of previous estimates \| MBoe				(39,092)
Extensions, discoveries and other additions \| MBoe				15,913
Sales of minerals in place \| MBoe				(2,775)
Production \| MBoe				(14,460)
End of year \| MBoe				234,715
Proved developed reserves \| MBoe								156,161
Proved undeveloped reserves \| MBoe								78,554
Total proved reserves \| MBoe	234,715			275,129				234,715
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) \| MBoe				(40,414)
Wells Drilled Gross Productive \| Wells				340
Predecessor \| Oil
Total proved reserves:
Beginning of year	171,399			184,468
Revisions of previous estimates				(10,301)
Extensions, discoveries and other additions				9,360
Sales of minerals in place				(1,416)
Production				(10,712)
End of year				171,399
Proved developed reserves								114,213
Proved undeveloped reserves								57,186
Total proved reserves	171,399			184,468				171,399
Predecessor \| Natural Gas Liquids [Member]
Total proved reserves:
Beginning of year	16,493			19,740
Revisions of previous estimates				(3,235)
Extensions, discoveries and other additions				1,595
Sales of minerals in place				(847)
Production				(760)
End of year				16,493
Proved developed reserves								8,011
Proved undeveloped reserves								8,482
Total proved reserves	16,493			19,740				16,493
Predecessor \| Natural gas
Total proved reserves:
Beginning of year \| Mcf	280,943			425,519
Revisions of previous estimates \| Mcf				(153,330)
Extensions, discoveries and other additions \| Mcf				29,756
Sales of minerals in place \| Mcf				(3,071)
Production \| Mcf				(17,931)
End of year \| Mcf				280,943
Proved developed reserves \| Mcf								203,624
Proved undeveloped reserves \| Mcf								77,319
Total proved reserves \| Mcf	280,943			425,519				280,943

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

Dec. 31, 2015

USD ($)

$ / boe

$ / MMBtu

Dec. 31, 2014

USD ($)

$ / boe

$ / MMBtu

Dec. 31, 2013

USD ($)

$ / boe

$ / MMBtu

Dec. 17, 2013

USD ($)

Dec. 16, 2013

USD ($)

Dec. 31, 2012

USD ($)

Successor

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

Future estimated revenues

$ 5,483,899

$ 16,844,678

$ 17,863,984

Future estimated production costs

(3,458,415)

(7,742,035)

(6,654,536)

Future estimated development costs

(332,311)

(1,132,807)

(1,854,849)

Future net cash flows

1,693,173

7,969,836

9,354,599

10% annual discount for estimated timing of cash flows

(697,801)

(3,639,459)

(4,719,267)

Standardized measure of discounted future net cash flows

$ 995,372

$ 4,330,377

$ 4,635,332

$ 3,558,595

Successor | Crude Oil [Member]

Representative NYMEX prices: (1)

Oil (Bbl) | $ / boe

^[1]

50.16

95.27

96.89

Successor | Natural gas ($/Mcf)

Representative NYMEX prices: (1)

Natural gas (MMBtu) | $ / MMBtu

^[1]

2.59

4.35

3.67

Predecessor

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

Standardized measure of discounted future net cash flows

$ 3,558,595

$ 3,833,415

[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, 2015	Dec. 31, 2014	Dec. 16, 2013
Predecessor
Change in Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Standardized measure—beginning of year				$ 3,833,415
Sales and transfers of oil, natural gas and NGL produced during the period				(703,597)
Changes in estimated future development costs				20,932
Net change in sales and transfer prices and production costs related to future production				(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				496,718
Income taxes				237,117
Changes in production rates and other				166,480
Net increase (decrease)				(274,820)
Standardized measure—end of year				$ 3,558,595
Successor
Change in Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
Standardized measure—beginning of year	$ 3,558,595	$ 4,330,377	$ 4,635,332
Sales and transfers of oil, natural gas and NGL produced during the period	(30,208)	(207,125)	(794,337)
Changes in estimated future development costs	0	431,622	68,290
Net change in sales and transfer prices and production costs related to future production	(1,272)	(3,203,620)	(1,020,605)
Extensions, discoveries and improved recovery	0	20,345	674,392
Purchases of minerals in place		0	548,256
Sales of minerals in place	0	0	(486,903)
Previously estimated development costs incurred during the period	0	67,529	269,473
Net change due to revisions in quantity estimates	0	(544,334)	(66,696)
Accretion of discount	19,184	433,038	463,533
Income taxes	1,109,522
Changes in production rates and other	(20,489)	(332,460)	39,642
Net increase (decrease)	1,076,737	(3,335,005)	(304,955)
Standardized measure—end of year	$ 4,635,332	$ 995,372	$ 4,330,377

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

3 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Selected Quarterly Financial Data

Oil, natural gas and natural gas liquids sales

$ 50,324

$ 104,812

$ 140,252

$ 173,381

$ 156,586

$ 254,043

$ 350,863

$ 360,380

$ 333,116

$ 575,031

$ 1,298,402

Electricity sales

1,444

4,174

8,610

6,609

5,151

8,561

11,300

10,192

9,969

24,544

40,022

Gains (losses) on oil and natural gas derivatives

(5,049)

2,718

27,664

(4,474)

3,267

55,891

44,990

(25,562)

3,465

36,068

78,784

Total revenues and other

47,118

115,176

179,307

177,890

169,281

323,232

409,416

347,261

351,380

641,654

1,431,289

Total expenses

^[1]

218,155

696,633

191,222

474,938

488,741

225,834

240,116

244,156

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

10,208

732

2,633

(811)

(4,473)

64,151

49,011

4,257

3,367

(1,919)

120,786

Net income (loss)

$ (19,973)

$ (126,462)

$ (537,158)

$ (28,832)

$ (322,725)

$ (251,275)

$ 115,165

$ 79,008

$ 79,698

$ (1,015,177)

$ 22,596

[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.

- Definition

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

+ References + Details