10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2015

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the transition period from _______________ to _______________

Commission File Number: 000-51719

LINN ENERGY, LLC

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	65-1177591 (IRS Employer Identification No.)
600 Travis, Suite 4900 Houston, Texas (Address of principal executive offices)	77002 (Zip Code)
(281) 840-4000 (Registrant’s telephone number, including area code)
600 Travis, Suite 5100 Houston, Texas 77002 (Former address of principal executive offices)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  x     Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company ¨

Indicate by check mark whether registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

As of March 31, 2015, there were 336,887,489 units outstanding.

TABLE OF CONTENTS

		Page
	Glossary of Terms	ii
	Part I – Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of March 31, 2015, and December 31, 2014	1
	Condensed Consolidated Statements of Operations for the three months ended March 31, 2015, and March 31, 2014	2
	Condensed Consolidated Statement of Unitholders’ Capital for the three months ended March 31, 2015	3
	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2015, and March 31, 2014	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4.	Controls and Procedures	46
	Part II – Other Information
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3.	Defaults Upon Senior Securities	47
Item 4.	Mine Safety Disclosures	47
Item 5.	Other Information	47
Item 6.	Exhibits	48
	Signature	49

i

GLOSSARY OF TERMS

As commonly used in the oil and natural gas industry and as used in this Quarterly Report on Form 10-Q, the following terms have the following meanings:

Bbl. One stock tank barrel or 42 United States gallons liquid volume.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

MBbls/d. MBbls per day.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

MMBbls. One million barrels of oil or other liquid hydrocarbons.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcf/d. MMcf per day.

MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

MMcfe/d. MMcfe per day.

MMMBtu. One billion British thermal units.

NGL. Natural gas liquids, which are the hydrocarbon liquids contained within natural gas.

ii

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

LINN ENERGY, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2015			December 31, 2014
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	48,312		$	1,809
Accounts receivable – trade, net	340,838			471,684
Derivative instruments	1,119,332			1,077,142
Other current assets	147,969			155,955
Total current assets	1,656,451			1,706,590
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	18,246,897			18,068,900
Less accumulated depletion and amortization	(5,592,674		)	(4,867,682		)
	12,654,223			13,201,218
Other property and equipment	682,772			669,149
Less accumulated depreciation	(158,409		)	(144,282		)
	524,363			524,867
Derivative instruments	949,879			848,097
Other noncurrent assets	135,259			142,737
	1,085,138			990,834
Total noncurrent assets	14,263,724			14,716,919
Total assets	$	15,920,175		$	16,423,509
LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	608,926		$	814,809
Derivative instruments	899			—
Other accrued liabilities	184,430			167,736
Total current liabilities	794,255			982,545
Noncurrent liabilities:
Credit facilities	3,148,175			2,968,175
Term loan	500,000			500,000
Senior notes, net	6,750,313			6,827,634
Derivative instruments	1,999			684
Other noncurrent liabilities	598,930			600,866
Total noncurrent liabilities	10,999,417			10,897,359
Commitments and contingencies (Note 10)
Unitholders’ capital:
336,887,489 units and 331,974,913 units issued and outstanding at March 31, 2015, and December 31, 2014, respectively	5,317,869			5,395,811
Accumulated deficit	(1,191,366		)	(852,206		)
	4,126,503			4,543,605
Total liabilities and unitholders’ capital	$	15,920,175		$	16,423,509

The accompanying notes are an integral part of these condensed consolidated financial statements.

1

LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	2015			2014
	(in thousands, except per unit amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	450,569		$	938,877
Gains (losses) on oil and natural gas derivatives	424,781			(241,493		)
Marketing revenues	33,744			30,546
Other revenues	7,453			5,657
	916,547			733,587
Expenses:
Lease operating expenses	173,021			194,033
Transportation expenses	53,540			45,630
Marketing expenses	28,841			21,072
General and administrative expenses	78,968			79,228
Exploration costs	396			1,091
Depreciation, depletion and amortization	215,014			267,801
Impairment of long-lived assets	532,617			—
Taxes, other than income taxes	54,045			65,713
(Gains) losses on sale of assets and other, net	(12,287		)	2,586
	1,124,155			677,154
Other income and (expenses):
Interest expense, net of amounts capitalized	(143,101		)	(133,813		)
Gain on extinguishment of debt	6,635			—
Other, net	(2,213		)	(2,303		)
	(138,679		)	(136,116		)
Loss before income taxes	(346,287		)	(79,683		)
Income tax expense (benefit)	(7,127		)	5,654
Net loss	$	(339,160	)	$	(85,337	)
Net loss per unit:
Basic	$	(1.03	)	$	(0.27	)
Diluted	$	(1.03	)	$	(0.27	)
Weighted average units outstanding:
Basic	330,642			328,329
Diluted	330,642			328,329
Distributions declared per unit	$	0.313		$	0.725

The accompanying notes are an integral part of these condensed consolidated financial statements.

2

LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL

(Unaudited)

	Units	Unitholders’ Capital			Accumulated Deficit			Total Unitholders’ Capital
	(in thousands)
December 31, 2014	331,975	$	5,395,811		$	(852,206	)	$	4,543,605
Sale of units, net of offering costs of $594	1,328	15,306			—			15,306
Issuance of units	3,584	—			—			—
Distributions to unitholders		(104,815		)	—			(104,815		)
Unit-based compensation expenses		20,510			—			20,510
Excess tax benefit from unit-based compensation and other		(8,943		)	—			(8,943		)
Net loss		—			(339,160		)	(339,160		)
March 31, 2015	336,887	$	5,317,869		$	(1,191,366	)	$	4,126,503

The accompanying notes are an integral part of these condensed consolidated financial statements.

3

LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Cash flow from operating activities:
Net loss	$	(339,160	)	$	(85,337	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	215,014			267,801
Impairment of long-lived assets	532,617			—
Unit-based compensation expenses	20,510			21,500
Gain on extinguishment of debt	(6,635		)	—
Amortization and write-off of deferred financing fees	6,712			2,313
(Gains) losses on sale of assets and other, net	(7,100		)	1,327
Deferred income taxes	(7,158		)	5,584
Derivatives activities:
Total (gains) losses	(423,855		)	241,493
Cash settlements	282,082			(14,511		)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	135,230			(34,337		)
Increase in other assets	(12,399		)	(4,176		)
Increase (decrease) in accounts payable and accrued expenses	(29,868		)	16,105
Increase in other liabilities	8,713			16,720
Net cash provided by operating activities	374,703			434,482
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			(25,345		)
Development of oil and natural gas properties	(264,818		)	(394,843		)
Purchases of other property and equipment	(12,401		)	(10,151		)
Proceeds from sale of properties and equipment and other	27,500			(10,686		)
Net cash used in investing activities	(249,719		)	(441,025		)
Cash flow from financing activities:
Proceeds from sale of units	15,900			—
Proceeds from borrowings	395,000			540,000
Repayments of debt	(280,287		)	(241,188		)
Distributions to unitholders	(104,815		)	(240,073		)
Financing fees and offering costs	(453		)	(2,662		)
Excess tax benefit from unit-based compensation	(8,867		)	1,457
Other	(94,959		)	(34,848		)
Net cash provided by (used in) financing activities	(78,481		)	22,686
Net increase in cash and cash equivalents	46,503			16,143
Cash and cash equivalents:
Beginning	1,809			52,171
Ending	$	48,312		$	68,314

The accompanying notes are an integral part of these condensed consolidated financial statements.

4

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation

Nature of Business

Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company. LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. The Company’s properties are located in eight operating regions in the United States (“U.S.”), in the Rockies, the Hugoton Basin, California, the Mid-Continent, the Permian Basin, TexLa, South Texas and Michigan/Illinois.

Principles of Consolidation and Reporting

The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.

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

Use of Estimates

The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“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 is currently evaluating the impact of the adoption of this ASU on its condensed consolidated financial statements and related disclosures.

5

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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, 2016, and interim periods within those years (early adoption prohibited). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its condensed consolidated financial statements and related disclosures.

Note 2 – Acquisitions and Joint-Venture Funding

The revenues and expenses related to certain oil and natural gas properties acquired in 2014 from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) are included in the condensed consolidated results of operations of the Company as of August 29, 2014. The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the three months ended March 31, 2014, assuming the Devon Assets Acquisition had been completed as of January 1, 2014, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information has been prepared for informational purposes only and does not purport to represent what the actual results of operations would have been had the transaction been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The pro forma financial information does not give effect to the costs of any integration activities or benefits that may result from the realization of future cost savings from operating efficiencies, or any other synergies that may result from the transaction.

	Three Months Ended March 31, 2014
	(in thousands, except per unit amounts)
Total revenues and other	$	879,115
Total operating expenses	$	765,491
Net loss	$	(62,305	)
Net loss per unit:
Basic	$	(0.20	)
Diluted	$	(0.20	)

The pro forma condensed combined statement of operations includes adjustments to:

• Reflect the results of the Devon Assets Acquisition.

• Reflect incremental depreciation, depletion and amortization expense, using the unit-of-production method related to oil and natural gas properties acquired and an estimated useful life of 10 years for other property and equipment.

• Reflect incremental accretion expense related to asset retirement obligations on oil and natural gas properties acquired.

• Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price.

• Reflect incremental amortization of deferred financing fees associated with debt incurred to fund the purchase price.

Joint-Venture Funding – 2014

For the three months ended March 31, 2014, the Company paid approximately $25 million, including interest, to fund the commitment related to the joint-venture agreement it entered into with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) in April 2012. As of February 2014, the Company had fully funded the total commitment of $400 million.

6

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Note 3 – Unitholders’ Capital

At-the-Market Offering Program

The Company has the authority to sell up to $500 million of units under an at-the-market offering program. Sales of units, if any, will be made under an equity distribution agreement by means of ordinary brokers’ transactions, through the facilities of the NASDAQ Global Select Market, any other national securities exchange or facility thereof, a trading facility of a national securities association or an alternate trading system, to or through a market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, at market prices, in block transactions, or as otherwise agreed with a sales agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.

During the three months ended March 31, 2015, the Company, under its equity distribution agreement, issued and sold 1,328,192 units representing limited liability company interests at an average unit price of $11.97 for net proceeds of approximately $16 million (net of approximately $159,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional service expenses of approximately $435,000. The Company used the net proceeds for general corporate purposes including the open market repurchases of a portion of its 8.625% senior notes due April 2020 (see Note 6). At March 31, 2015, units totaling approximately $484 million in aggregate offering price remained available to be issued and sold under the agreement.

Distributions

Under the Company’s limited liability company agreement, unitholders are entitled to receive a distribution of available cash, which includes cash on hand plus borrowings less any reserves established by the Company’s Board of Directors to provide for the proper conduct of the Company’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions over the next four quarters. Distributions paid by the Company are presented on the condensed consolidated statement of unitholders’ capital and the condensed consolidated statements of cash flows. On April 1, 2015, the Company’s Board of Directors declared a cash distribution of $0.3125 per unit with respect to the first quarter of 2015, to be paid in three equal installments of $0.1042 per unit. The first monthly distribution with respect to the first quarter of 2015, totaling approximately $35 million, was paid on April 16, 2015, to unitholders of record as of the close of business on April 13, 2015.

Note 4 – Oil and Natural Gas Properties

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:

	March 31, 2015			December 31, 2014
	(in thousands)
Proved properties:
Leasehold acquisition	$	13,368,818		$	13,362,642
Development	3,012,467			2,830,841
Unproved properties	1,865,612			1,875,417
	18,246,897			18,068,900
Less accumulated depletion and amortization	(5,592,674		)	(4,867,682		)
	$	12,654,223		$	13,201,218

7

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Impairment of Proved Properties

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

Based on the analysis described above, for the three months ended March 31, 2015, the Company recorded noncash impairment charges, before and after tax, of approximately $533 million associated with proved oil and natural gas properties. The impairment was due to a decline in commodity prices. 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 condensed consolidated statement of operations. Following are the impairment charges recorded:

• Shallow Texas Panhandle Brown Dolomite formation – $278 million;

• California region – $207 million;

• TexLa region – $33 million;

• South Texas region – $9 million; and

• Mid-Continent region – $6 million.

The Company recorded no impairment charges for the three months ended March 31, 2014.

Note 5 – Unit-Based Compensation

During the three months ended March 31, 2015, the Company granted 3,468,245 restricted units and 697,120 phantom units to employees, primarily as part of its annual review of its employees’ compensation, including executives, with an aggregate fair value of approximately $42 million. The restricted units and phantom units vest over three years. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:

	Three Months Ended March 31,
	2015		2014
	(in thousands)
General and administrative expenses	$	16,633	$	18,223
Lease operating expenses	3,877		3,277
Total unit-based compensation expenses	$	20,510	$	21,500
Income tax benefit	$	7,579	$	7,944

Cash-Based Performance Unit Awards

The Company also granted 567,320 performance units (the maximum number of units available to be earned) to certain executive officers. The 2015 performance unit awards vest three years from the award date. The vesting of these units is determined based on the Company’s performance compared to the performance of a predetermined group of peer companies over a specified performance period, and the value of vested units is to be paid in cash. To date, no performance units have vested and no amounts have been paid to settle any such awards. Performance unit awards that are settled in cash are recorded as a liability with the changes in fair value recognized over the vesting period. For the three months ended March 31, 2015, the Company recognized expense for cash-based performance unit awards of approximately $266,000, included in “general and

8

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

administrative expenses” on the condensed consolidated statement of operations. At March 31, 2015, the Company’s liability related to these performance unit awards was also approximately $266,000.

Note 6 – Debt

The following summarizes the Company’s outstanding debt:

	March 31, 2015			December 31, 2014
	(in thousands, except percentages)
LINN credit facility (1)	$	1,975,000		$	1,795,000
Berry credit facility (2)	1,173,175			1,173,175
Term loan (3)	500,000			500,000
6.50% senior notes due May 2019	1,200,000			1,200,000
6.25% senior notes due November 2019	1,800,000			1,800,000
8.625% senior notes due April 2020	1,220,800			1,300,000
6.75% Berry senior notes due November 2020	299,970			299,970
7.75% senior notes due February 2021	1,000,000			1,000,000
6.50% senior notes due September 2021	650,000			650,000
6.375% Berry senior notes due September 2022	599,163			599,163
Net unamortized discounts and premiums	(19,620		)	(21,499		)
Total debt, net	10,398,488			10,295,809
Less current maturities	—			—
Total long-term debt, net	$	10,398,488		$	10,295,809

⁽¹⁾  Variable interest rates of 1.93% and 1.92% at March 31, 2015, and December 31, 2014, respectively.

⁽²⁾  Variable interest rates of 2.68% and 2.67% at March 31, 2015, and December 31, 2014, respectively.

⁽³⁾  Variable interest rates of 2.68% and 2.66% at March 31, 2015, and December 31, 2014, respectively.

Fair Value

The Company’s debt is recorded at the carrying amount in the condensed consolidated balance sheets. The carrying amounts of the Company’s credit facilities and term loan approximate fair value because the interest rates are variable and reflective of market rates. The Company uses a market approach to determine the fair value of its senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.

	March 31, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Credit facilities	$	3,148,175	$	3,148,175	$	2,968,175	$	2,968,175
Term loan	500,000		500,000		500,000		500,000
Senior notes, net	6,750,313		5,454,065		6,827,634		5,703,649
Total debt, net	$	10,398,488	$	9,102,240	$	10,295,809	$	9,171,824

9

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Credit Facilities

LINN Credit Facility

The Company’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) provides for (1) a senior secured revolving credit facility and (2) a $500 million senior secured term loan, in aggregate subject to the then-effective borrowing base. Borrowing capacity under the revolving credit facility is limited to the lesser of (i) the then-effective borrowing base reduced by the $500 million term loan and (ii) the maximum commitment amount of $4.0 billion, and is currently $4.0 billion. The maturity date is April 2019. At March 31, 2015, the borrowing base under the LINN Credit Facility was $4.5 billion and availability under the revolving credit facility was approximately $2.0 billion, which includes a $6 million reduction for outstanding letters of credit.

Redetermination of the borrowing base under the LINN Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. The administrative agent, at the direction of a super-majority of certain of the lenders, has the right to request one interim borrowing base redetermination per year. The Company also has the right to request one interim borrowing base redetermination per year, as well as the right to an additional interim redetermination each year in connection with certain acquisitions. Significant declines in commodity prices may result in a decrease in the borrowing base. The spring 2015 semi-annual redetermination is scheduled for May 2015, and the Company anticipates its lenders will recommend a decrease in the borrowing base under the LINN Credit Facility.

The Company’s obligations under the LINN Credit Facility are secured by mortgages on certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in the Company’s direct and indirect material subsidiaries. The Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report, or 2) a Collateral Coverage Ratio of at least 2.5 to 1. Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. Additionally, the obligations under the LINN Credit Facility are guaranteed by all of the Company’s material subsidiaries, other than Berry Petroleum Company, LLC (“Berry”), and are required to be guaranteed by any future material subsidiaries. The Company is in compliance with all financial and other covenants of the LINN Credit Facility.

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

The $500 million term loan has a maturity date of April 2019 and incurs interest based on either the LIBOR plus a margin of 2.5% per annum or the ABR plus a margin of 1.5% per annum, at the Company’s election. Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR. The term loan may be repaid at the option of the Company without premium or penalty, subject to breakage costs. While the term loan is outstanding, the Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report, or 2) a Term Loan Collateral Coverage Ratio of at least 2.5 to 1. The Term Loan Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount and the aggregate amount of the term loan outstanding. The other terms and conditions of the LINN Credit Facility, including the financial and other restrictive covenants set forth therein, are applicable to the term loan.

10

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Berry Credit Facility

Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) currently has a borrowing base of $1.4 billion, subject to lender commitments. The maturity date is April 2019. At March 31, 2015, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit.

Redetermination of the borrowing base under the Berry Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. A super-majority of the lenders under the Berry Credit Facility and Berry also have the right to request interim borrowing base redeterminations once between scheduled redeterminations. Significant declines in commodity prices may result in a decrease in the borrowing base. The spring 2015 semi-annual redetermination is scheduled for May 2015, and the Company anticipates its lenders will recommend a decrease in the borrowing base under the Berry Credit Facility.

Berry’s obligations under the Berry Credit Facility are secured by mortgages on its oil and natural gas properties and other personal property. Berry is required to maintain mortgages on properties representing at least 80% of the present value of its oil and natural gas proved reserves. Berry is in compliance with all financial and other covenants of the Berry Credit Facility.

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

The Company refers to the LINN Credit Facility and the Berry Credit Facility, collectively, as the “Credit Facilities.”

Repurchases of Senior Notes

During the three months ended March 31, 2015, the Company repurchased on the open market approximately $79 million of its 8.625% senior notes due April 2020. In connection with the repurchases, the Company recorded a gain on extinguishment of debt of approximately $7 million for the three months ended March 31, 2015.

Senior Notes Covenants

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

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

In addition, any cash generated by Berry is currently being used by Berry to fund its activities. To the extent that Berry generates cash in excess of its needs, the indentures governing Berry’s senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and Berry may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Berry

11

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

indentures. Berry’s restricted payments basket may be increased in accordance with the terms of the Berry indentures by, among other things, 50% of Berry’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions.

Note 7 – Derivatives

Commodity Derivatives

The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company directly hedges only its oil and natural gas production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials.

The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. In connection with the 2013 acquisition of Berry, the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

The following table summarizes derivative positions for the periods indicated as of March 31, 2015:

	April 1 - December 31, 2015		2016		2017		2018
Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMMBtu)	88,935		121,841		120,122		36,500
Average price ($/MMBtu)	$	5.19	$	4.20	$	4.26	$	5.00
Put options (NYMEX Henry Hub):
Hedged volume (MMMBtu)	54,137		76,269		66,886		—
Average price ($/MMBtu)	$	5.00	$	5.00	$	4.88	$	—
Oil positions:
Fixed price swaps (NYMEX WTI): (1)
Hedged volume (MBbls)	9,426		11,465		4,755		—
Average price ($/Bbl)	$	93.33	$	90.56	$	89.02	$	—
Three-way collars (NYMEX WTI):
Hedged volume (MBbls)	825		—		—		—
Short put ($/Bbl)	$	70.00	$	—	$	—	$	—
Long put ($/Bbl)	$	90.00	$	—	$	—	$	—
Short call ($/Bbl)	$	101.62	$	—	$	—	$	—
Put options (NYMEX WTI):
Hedged volume (MBbls)	2,581		3,271		384		—
Average price ($/Bbl)	$	90.00	$	90.00	$	90.00	$	—

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

	April 1 - December 31, 2015			2016			2017			2018
Natural gas basis differential positions:(2)
Panhandle basis swaps: (3)
Hedged volume (MMMBtu)	65,670			59,954			59,138			16,425
Hedged differential ($/MMBtu)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)
NWPL Rockies basis swaps: (3)
Hedged volume (MMMBtu)	43,707			65,794			38,880			10,804
Hedged differential ($/MMBtu)	$	(0.23	)	$	(0.24	)	$	(0.19	)	$	(0.19	)
MichCon basis swaps: (3)
Hedged volume (MMMBtu)	7,040			7,768			7,437			2,044
Hedged differential ($/MMBtu)	$	0.06		$	0.05		$	0.05		$	0.05
Houston Ship Channel basis swaps: (3)
Hedged volume (MMMBtu)	19,351			34,364			36,730			986
Hedged differential ($/MMBtu)	$	(0.03	)	$	(0.02	)	$	(0.02	)	$	(0.08	)
Permian basis swaps: (3)
Hedged volume (MMMBtu)	3,823			4,219			4,819			1,314
Hedged differential ($/MMBtu)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)
SoCal basis swaps: (4)
Hedged volume (MMMBtu)	22,050			32,940			—			—
Hedged differential ($/MMBtu)	$	(0.03	)	$	(0.03	)	$	—		$	—
Oil timing differential positions:
Trade month roll swaps (NYMEX WTI): (5)
Hedged volume (MBbls)	5,463			7,446			6,486			—
Hedged differential ($/Bbl)	$	0.24		$	0.25		$	0.25		$	—

⁽¹⁾  Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, at counterparty election on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

⁽²⁾  Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.

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

⁽⁴⁾  For positions which hedge exposure to differentials in consuming areas, the Company pays the NYMEX Henry Hub natural gas price plus the respective spread and receives the specified index price. Cash settlements are made on a net basis.

⁽⁵⁾  The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

During the three months ended March 31, 2015, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for May 2015 through December 2017, to hedge exposure to differentials in certain producing areas, and oil swaps for April 2015 through December 2015. In addition, the Company entered into natural gas basis swaps for May 2015 through December 2016 to hedge exposure to the differential in California, where it consumes natural gas in its heavy oil development operations.

13

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Settled derivatives on natural gas production for the three months ended March 31, 2015, included volumes of 46,823 MMMBtu at an average contract price of $5.12 per MMBtu. Settled derivatives on oil production for the three months ended March 31, 2015, included volumes of 3,975 MBbls at an average contract price of $94.29 per Bbl. Settled derivatives on natural gas production for the three months ended March 31, 2014, included volumes of 43,651 MMMBtu at an average contract price of $5.14 per MMBtu. Settled derivatives on oil production for the three months ended March 31, 2014, included volumes of 6,161 MBbls at an average contract price of $92.39 per Bbl.

The natural gas derivatives are settled based on the closing price of NYMEX Henry Hub natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX WTI crude oil for each day of the delivery month.

Balance Sheet Presentation

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

	March 31, 2015		December 31, 2014
	(in thousands)
Assets:
Commodity derivatives	$	2,106,710	$	2,014,815
Liabilities:
Commodity derivatives	$	40,397	$	90,260

By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facilities or were participants or affiliates of participants in its Credit Facilities at the time it originally entered into the derivatives. The Credit Facilities are secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $2.1 billion at March 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

Gains and losses on derivatives used to hedge production were net gains of approximately $425 million for the three months March 31, 2015, and net losses of approximately $241 million for the three months ended March 31, 2014, and are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.” Gains and losses on derivatives used to hedge natural gas consumption, entered into in March 2015, were net losses of approximately $1 million for the three months ended March 31, 2015, and are reported on the condensed consolidated statement of operations in “lease operating expenses.” For the three months ended March 31, 2015, and March 31, 2014, the Company received net cash settlements of approximately $282 million and paid net cash settlements of approximately $15 million, respectively.

14

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Note 8 – 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).

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

	March 31, 2015
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	2,106,710	$	(37,499	)	$	2,069,211
Liabilities:
Commodity derivatives	$	40,397	$	(37,499	)	$	2,898

	December 31, 2014
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	2,014,815	$	(89,576	)	$	1,925,239
Liabilities:
Commodity derivatives	$	90,260	$	(89,576	)	$	684

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

Note 9 – 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 condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2% for the three months ended March 31, 2015); and (iv) a credit-adjusted risk-free interest rate (average of 5.6% for the three months ended March 31, 2015). 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.

15

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

The following presents a reconciliation of the Company’s asset retirement obligations (in thousands):

Asset retirement obligations at December 31, 2014	$	497,570
Liabilities added from drilling	1,390
Current year accretion expense	7,399
Settlements	(1,783		)
Revision of estimates	(1,345		)
Asset retirement obligations at March 31, 2015	$	503,231

Note 10 – Commitments and Contingencies

The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. With respect to a certain statewide class action case, the Company’s motion to dismiss was denied by the Court, and the parties have agreed on a scheduling order, which provides for briefing on the class certification issues in late 2015 and the first part of 2016. The Company has denied that it has liability on the claims asserted in the case and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. For another statewide class action royalty payment dispute, briefing on class certification issues is expected to be completed during the summer of 2015. The Company has denied that it has any liability on the claims and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. The Company is unable to estimate a possible loss, or range of possible loss, if any, in these cases. In addition, the Company is involved in various other disputes arising in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

During the three months ended March 31, 2015, and March 31, 2014, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Note 11 – Earnings Per Unit

Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect.

16

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net loss:

	Three Months Ended March 31,
	2015			2014
	(in thousands, except per unit data)
Net loss	$	(339,160	)	$	(85,337	)
Allocated to participating securities	(1,781		)	(2,199		)
	$	(340,941	)	$	(87,536	)
Basic net loss per unit	$	(1.03	)	$	(0.27	)
Diluted net loss per unit	$	(1.03	)	$	(0.27	)
Basic weighted average units outstanding	330,642			328,329
Dilutive effect of unit equivalents	—			—
Diluted weighted average units outstanding	330,642			328,329

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 5 million and 6 million unit options and warrants for the three months ended March 31, 2015, and March 31, 2014, respectively. All equivalent units were antidilutive for both the three months ended March 31, 2015, and March 31, 2014.

Note 12 – Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company. Amounts recognized for income taxes are reported in “income tax expense (benefit)” on the condensed consolidated statements of operations.

Note 13 – Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows

“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:

	March 31, 2015		December 31, 2014
	(in thousands)
Accrued interest	$	143,088	$	105,310
Accrued compensation	22,854		44,875
Asset retirement obligations	16,187		16,187
Other	2,301		1,364
	$	184,430	$	167,736

17

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

	Three Months Ended March 31,
	2015		2014
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	98,541	$	77,512
Cash payments for income taxes	$	57	$	—
Noncash investing activities:
Accrued capital expenditures	$	161,247	$	338,323

Included in “acquisition of oil and natural gas properties and joint-venture funding” on the condensed consolidated statement of cash flows for the three months ended March 31, 2014, is approximately $25 million paid by the Company to fund the commitment related to the joint-venture agreement entered into with Anadarko in April 2012 (see Note 2).

For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $6 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at both March 31, 2015, and December 31, 2014, and primarily represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facilities. At December 31, 2014, net outstanding checks of approximately $95 million were reclassified and included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet. At March 31, 2015, no net outstanding checks were reclassified. Net outstanding checks are presented as cash flows from financing activities and included in “other” on the condensed consolidated statements of cash flows.

Note 14 – Related Party Transactions

LinnCo

LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, was formed on April 30, 2012. LinnCo’s initial sole purpose was to own units in LINN Energy. In connection with the 2013 acquisition of Berry, LinnCo amended its limited liability company agreement to permit, among other things, the acquisition and subsequent contribution of assets to LINN Energy. All of LinnCo’s common shares are held by the public. As of March 31, 2015, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy and owned approximately 39% of LINN Energy’s outstanding units.

LINN Energy has agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any financial, legal, accounting, tax advisory, financial advisory and engineering fees, and other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity. These expenses include costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees. In addition, the Company has agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities. All expenses and costs paid by LINN Energy on LinnCo’s behalf are expensed by LINN Energy.

For the three months ended March 31, 2015, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $1.4 million, of which approximately $1.1 million had been paid by LINN Energy on LinnCo’s behalf as of March 31, 2015. The expenses for the three months ended March 31, 2015, include approximately $491,000 related to

18

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses.

For the three months ended March 31, 2014, LinnCo incurred total general and administrative expenses of approximately $734,000, of which approximately $83,000 had been paid by LINN Energy on LinnCo’s behalf as of March 31, 2014. The expenses for the three months ended March 31, 2014, include approximately $470,000 related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses. In addition, during the three months ended March 31, 2014, LINN Energy paid approximately $11 million on LinnCo’s behalf for general and administrative expenses incurred by LinnCo in 2013.

During the three months ended March 31, 2015, and March 31, 2014, the Company paid approximately $40 million and $93 million, respectively, in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy.

Other

One of the Company’s directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the three months ended March 31, 2015, and March 31, 2014, the Company incurred expenditures of approximately $3 million and $4 million, respectively, related to services rendered by Superior and its subsidiaries.

Note 15 – Subsidiary Guarantors

LINN Energy, LLC’s May 2019 senior notes, November 2019 senior notes, April 2020 senior notes, February 2021 senior notes and September 2021 senior notes are guaranteed by all of the Company’s material subsidiaries, other than Berry Petroleum Company, LLC, which is an indirect 100% wholly owned subsidiary of the Company.

The following condensed consolidating financial information presents the financial information of LINN Energy, LLC, the guarantor subsidiaries and the non-guarantor subsidiary in accordance with SEC Regulation S-X Rule 3‑10. The condensed consolidating financial information for the co-issuer, Linn Energy Finance Corp., is not presented as it has no assets, operations or cash flows. The financial information may not necessarily be indicative of the financial position or results of operations had the guarantor subsidiaries or non-guarantor subsidiary operated as independent entities. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.

19

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS

March 31, 2015

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	3,864		$	43,024		$	1,424		$	—		$	48,312
Accounts receivable – trade, net	—			251,957			88,881			—			340,838
Accounts receivable – affiliates	4,011,808			33,061			—			(4,044,869		)	—
Derivative instruments	—			1,099,777			19,555			—			1,119,332
Other current assets	18			94,722			53,229			—			147,969
Total current assets	4,015,690			1,522,541			163,089			(4,044,869		)	1,656,451
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	—			13,318,736			4,928,161			—			18,246,897
Less accumulated depletion and amortization	—			(4,790,872		)	(865,266		)	63,464			(5,592,674		)
	—			8,527,864			4,062,895			63,464			12,654,223
Other property and equipment	—			564,928			117,844			—			682,772
Less accumulated depreciation	—			(147,307		)	(11,102		)	—			(158,409		)
	—			417,621			106,742			—			524,363
Derivative instruments	—			949,798			81			—			949,879
Notes receivable – affiliates	146,900			—			—			(146,900		)	—
Advance to affiliate	—			—			220,571			(220,571		)	—
Investments in consolidated subsidiaries	8,296,020			—			—			(8,296,020		)	—
Other noncurrent assets, net	110,256			11,660			13,343			—			135,259
	8,553,176			961,458			233,995			(8,663,491		)	1,085,138
Total noncurrent assets	8,553,176			9,906,943			4,403,632			(8,600,027		)	14,263,724
Total assets	$	12,568,866		$	11,429,484		$	4,566,721		$	(12,644,896	)	$	15,920,175
LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	5,150		$	422,042		$	181,734		$	—		$	608,926
Accounts payable – affiliates	—			4,011,808			33,061			(4,044,869		)	—
Advance from affiliate	—			220,571			—			(220,571		)	—
Derivative instruments	—			—			899			—			899
Other accrued liabilities	132,202			37,872			14,356			—			184,430
Total current liabilities	137,352			4,692,293			230,050			(4,265,440		)	794,255
Noncurrent liabilities:
Credit facilities	1,975,000			—			1,173,175			—			3,148,175
Term loan	500,000			—			—			—			500,000
Senior notes, net	5,836,998			—			913,315			—			6,750,313
Notes payable – affiliates	—			146,900			—			(146,900		)	—
Derivative instruments	—			1,770			229			—			1,999
Other noncurrent liabilities	—			401,479			197,451			—			598,930
Total noncurrent liabilities	8,311,998			550,149			2,284,170			(146,900		)	10,999,417
Unitholders’ capital:
Units issued and outstanding	5,310,882			4,831,265			2,372,603			(7,196,881		)	5,317,869
Accumulated income (deficit)	(1,191,366		)	1,355,777			(320,102		)	(1,035,675		)	(1,191,366		)
	4,119,516			6,187,042			2,052,501			(8,232,556		)	4,126,503
Total liabilities and unitholders’ capital	$	12,568,866		$	11,429,484		$	4,566,721		$	(12,644,896	)	$	15,920,175

20

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2014

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	38		$	185		$	1,586		$	—		$	1,809
Accounts receivable – trade, net	—			371,325			100,359			—			471,684
Accounts receivable – affiliates	4,028,890			13,205			—			(4,042,095		)	—
Derivative instruments	—			1,033,448			43,694			—			1,077,142
Other current assets	18			96,678			59,259			—			155,955
Total current assets	4,028,946			1,514,841			204,898			(4,042,095		)	1,706,590
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	—			13,196,841			4,872,059			—			18,068,900
Less accumulated depletion and amortization	—			(4,342,675		)	(525,007		)	—			(4,867,682		)
	—			8,854,166			4,347,052			—			13,201,218
Other property and equipment	—			553,150			115,999			—			669,149
Less accumulated depreciation	—			(135,830		)	(8,452		)	—			(144,282		)
	—			417,320			107,547			—			524,867
Derivative instruments	—			848,097			—			—			848,097
Notes receivable – affiliates	130,500			—			—			(130,500		)	—
Advance to affiliate	—			—			293,627			(293,627		)	—
Investments in consolidated subsidiaries	8,562,608			—			—			(8,562,608		)	—
Other noncurrent assets, net	116,637			11,816			14,284			—			142,737
	8,809,745			859,913			307,911			(8,986,735		)	990,834
Total noncurrent assets	8,809,745			10,131,399			4,762,510			(8,986,735		)	14,716,919
Total assets	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509
LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	3,784		$	581,880		$	229,145		$	—		$	814,809
Accounts payable – affiliates	—			4,028,890			13,205			(4,042,095		)	—
Advance from affiliate	—			293,627			—			(293,627		)	—
Derivative instruments	—			—			—			—			—
Other accrued liabilities	89,507			59,142			19,087			—			167,736
Total current liabilities	93,291			4,963,539			261,437			(4,335,722		)	982,545
Noncurrent liabilities:
Credit facilities	1,795,000			—			1,173,175			—			2,968,175
Term loan	500,000			—			—			—			500,000
Senior notes, net	5,913,857			—			913,777			—			6,827,634
Notes payable – affiliates	—			130,500			—			(130,500		)	—
Derivative instruments	—			684			—			—			684
Other noncurrent liabilities	—			400,851			200,015			—			600,866
Total noncurrent liabilities	8,208,857			532,035			2,286,967			(130,500		)	10,897,359
Unitholders’ capital:
Units issued and outstanding	5,388,749			4,831,339			2,416,381			(7,240,658		)	5,395,811
Accumulated income (deficit)	(852,206		)	1,319,327			2,623			(1,321,950		)	(852,206		)
	4,536,543			6,150,666			2,419,004			(8,562,608		)	4,543,605
Total liabilities and unitholders’ capital	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509

21

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2015

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	293,983		$	156,586		$	—		$	450,569
Gains on oil and natural gas derivatives	—			421,514			3,267			—			424,781
Marketing revenues	—			26,212			7,532			—			33,744
Other revenues	—			5,557			1,896			—			7,453
	—			747,266			169,281			—			916,547
Expenses:
Lease operating expenses	—			105,832			67,189			—			173,021
Transportation expenses	—			40,934			12,606			—			53,540
Marketing expenses	—			23,196			5,645			—			28,841
General and administrative expenses	—			57,781			21,187			—			78,968
Exploration costs	—			396			—			—			396
Depreciation, depletion and amortization	—			140,699			72,979			1,336			215,014
Impairment of long-lived assets	—			325,417			272,000			(64,800		)	532,617
Taxes, other than income taxes	2			30,711			23,332			—			54,045
Gains on sale of assets and other, net	—			(7,814		)	(4,473		)	—			(12,287		)
	2			717,152			470,465			(63,464		)	1,124,155
Other income and (expenses):
Interest expense, net of amounts capitalized	(123,386		)	1,706			(21,421		)	—			(143,101		)
Interest expense – affiliates	—			(2,382		)	—			2,382			—
Interest income – affiliates	2,382			—			—			(2,382		)	—
Gain on extinguishment of debt	6,635			—			—			—			6,635
Equity in losses from consolidated subsidiaries	(222,811		)	—			—			222,811			—
Other, net	(1,978		)	(65		)	(170		)	—			(2,213		)
	(339,158		)	(741		)	(21,591		)	222,811			(138,679		)
Income (loss) before income taxes	(339,160		)	29,373			(322,775		)	286,275			(346,287		)
Income tax benefit	—			(7,077		)	(50		)	—			(7,127		)
Net income (loss)	$	(339,160	)	$	36,450		$	(322,725	)	$	286,275		$	(339,160	)

22

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2014

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	605,761		$	333,116		$	—		$	938,877
Gains (losses) on oil and natural gas derivatives	—			(244,958		)	3,465			—			(241,493		)
Marketing revenues	—			15,731			14,815			—			30,546
Other revenues	—			5,673			(16		)	—			5,657
	—			382,207			351,380			—			733,587
Expenses:
Lease operating expenses	—			104,002			90,031			—			194,033
Transportation expenses	—			37,637			7,993			—			45,630
Marketing expenses	—			10,091			10,981			—			21,072
General and administrative expenses	—			35,737			43,491			—			79,228
Exploration costs	—			1,091			—			—			1,091
Depreciation, depletion and amortization	—			199,170			68,631			—			267,801
Taxes, other than income taxes	—			42,684			23,029			—			65,713
(Gains) losses on sale of assets and other, net	—			(781		)	3,367			—			2,586
	—			429,631			247,523			—			677,154
Other income and (expenses):
Interest expense, net of amounts capitalized	(109,650		)	(162		)	(24,001		)	—			(133,813		)
Interest expense – affiliates	—			(1,550		)	—			1,550			—
Interest income – affiliates	1,550			—			—			(1,550		)	—
Equity in earnings from consolidated subsidiaries	24,893			—			—			(24,893		)	—
Other, net	(2,130		)	16			(189		)	—			(2,303		)
	(85,337		)	(1,696		)	(24,190		)	(24,893		)	(136,116		)
Income (loss) before income taxes	(85,337		)	(49,120		)	79,667			(24,893		)	(79,683		)
Income tax expense (benefit)	—			5,685			(31		)	—			5,654
Net income (loss)	$	(85,337	)	$	(54,805	)	$	79,698		$	(24,893	)	$	(85,337	)

23

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2015

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(339,160	)	$	36,450		$	(322,725	)	$	286,275		$	(339,160	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			140,699			72,979			1,336			215,014
Impairment of long-lived assets	—			325,417			272,000			(64,800		)	532,617
Unit-based compensation expenses	—			20,510			—			—			20,510
Gain on extinguishment of debt	(6,635		)	—			—			—			(6,635		)
Amortization and write-off of deferred financing fees	6,453			—			259			—			6,712
Gains on sale of assets and other, net	—			(5,243		)	(1,857		)	—			(7,100		)
Equity in losses from consolidated subsidiaries	222,811			—			—			(222,811		)	—
Deferred income taxes	—			(7,108		)	(50		)	—			(7,158		)
Derivatives activities:
Total gains	—			(421,514		)	(2,341		)	—			(423,855		)
Cash settlements	—			254,569			27,513			—			282,082
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net	21,921			96,917			16,392			—			135,230
(Increase) decrease in accounts receivable – affiliates	17,082			(19,856		)	—			2,774			—
Increase in other assets	—			(8,521		)	(3,878		)	—			(12,399		)
Decrease in accounts payable and accrued expenses	(290		)	(3,844		)	(25,734		)	—			(29,868		)
Increase (decrease) in accounts payable and accrued expenses – affiliates	—			(17,082		)	19,856			(2,774		)	—
Increase (decrease) in other liabilities	42,695			(24,057		)	(9,925		)	—			8,713
Net cash provided by (used in) operating activities	(35,123		)	367,337			42,489			—			374,703
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			—			—			—			—
Development of oil and natural gas properties	—			(263,209		)	(1,609		)	—			(264,818		)
Purchases of other property and equipment	—			(11,309		)	(1,092		)	—			(12,401		)
Investment in affiliates	43,778			—			—			(43,778		)	—
Change in notes receivable with affiliate	(16,400		)	—			—			16,400			—
Proceeds from sale of properties and equipment and other	(1,121		)	24,808			3,813			—			27,500
Net cash provided by (used in) investing activities	26,257			(249,710		)	1,112			(27,378		)	(249,719		)

24

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from financing activities:
Proceeds from sale of units	15,900			—			—			—			15,900
Proceeds from borrowings	395,000			—			—			—			395,000
Repayments of debt	(280,287		)	—			—			—			(280,287		)
Distributions to unitholders	(104,815		)	—			—			—			(104,815		)
Financing fees and offering costs	(453		)	—			—			—			(453		)
Change in notes payable with affiliate	—			16,400			—			(16,400		)	—
Distribution to affiliate	—			—			(43,778		)	43,778			—
Excess tax benefit from unit-based compensation	(8,867		)	—			—			—			(8,867		)
Other	(3,786		)	(91,188		)	15			—			(94,959		)
Net cash provided by (used in) financing activities	12,692			(74,788		)	(43,763		)	27,378			(78,481		)
Net increase (decrease) in cash and cash equivalents	3,826			42,839			(162		)	—			46,503
Cash and cash equivalents:
Beginning	38			185			1,586			—			1,809
Ending	$	3,864		$	43,024		$	1,424		$	—		$	48,312

25

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2014

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(85,337	)	$	(54,805	)	$	79,698		$	(24,893	)	$	(85,337	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			199,170			68,631			—			267,801
Unit-based compensation expenses	—			21,500			—			—			21,500
Amortization and write-off of deferred financing fees	5,791			—			(3,478		)	—			2,313
Losses on sale of assets and other, net	—			1,327			—			—			1,327
Equity in earnings from consolidated subsidiaries	(24,893		)	—			—			24,893			—
Deferred income taxes	—			5,615			(31		)	—			5,584
Derivatives activities:
Total (gains) losses	—			244,958			(3,465		)	—			241,493
Cash settlements	—			(11,856		)	(2,655		)	—			(14,511		)
Changes in assets and liabilities:
Increase in accounts receivable – trade, net	—			(18,964		)	(15,373		)	—			(34,337		)
Decrease in accounts receivable – affiliates	10,513			16,950			—			(27,463		)	—
Increase in other assets	—			(3,136		)	(1,040		)	—			(4,176		)
Increase (decrease) in accounts payable and accrued expenses	30			20,252			(4,177		)	—			16,105
Decrease in accounts payable and accrued expenses – affiliates	—			(10,513		)	(16,950		)	27,463			—
Increase (decrease) in other liabilities	53,698			(30,648		)	(6,330		)	—			16,720
Net cash provided by (used in) operating activities	(40,198		)	379,850			94,830			—			434,482
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			(25,345		)	—			—			(25,345		)
Development of oil and natural gas properties	—			(260,093		)	(134,750		)	—			(394,843		)
Purchases of other property and equipment	—			(8,318		)	(1,833		)	—			(10,151		)
Change in notes receivable with affiliate	(9,200		)	—			—			9,200			—
Proceeds from sale of properties and equipment and other	(11,230		)	544			—			—			(10,686		)
Net cash used in investing activities	(20,430		)	(293,212		)	(136,583		)	9,200			(441,025		)

26

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from financing activities:
Proceeds from borrowings	540,000			—			—			—			540,000
Repayments of debt	(240,000		)	—			(1,188		)	—			(241,188		)
Distributions to unitholders	(240,073		)	—			—			—			(240,073		)
Financing fees and offering costs	(81		)	—			(2,581		)	—			(2,662		)
Change in notes payable with affiliate	—			9,200			—			(9,200		)	—
Excess tax benefit from unit-based compensation	—			1,457			—			—			1,457
Other	763			(35,611		)	—			—			(34,848		)
Net cash provided by (used in) financing activities	60,609			(24,954		)	(3,769		)	(9,200		)	22,686
Net increase (decrease) in cash and cash equivalents	(19		)	61,684			(45,522		)	—			16,143
Cash and cash equivalents:
Beginning	52			1,078			51,041			—			52,171
Ending	$	33		$	62,762		$	5,519		$	—		$	68,314

27

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. The Company’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement Regarding Forward-Looking Statements” below and in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2014, and elsewhere in the Annual Report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

The following discussion and analysis should be read in conjunction with the financial statements and related notes included in this Quarterly Report on Form 10-Q and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”

Executive Overview

LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering in January 2006. The Company’s properties are located in eight operating regions in the United States (“U.S.”):

• Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin), North Dakota (Williston Basin) and Colorado (Piceance Basin);

• Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle;

• California, which includes properties located in the San Joaquin Valley and Los Angeles basins;

• Mid-Continent, which includes Oklahoma properties located in the Anadarko and Arkoma basins, as well as waterfloods in the Central Oklahoma Platform;

• Permian Basin, which includes properties located in west Texas and southeast New Mexico;

• TexLa, which includes properties located in east Texas and north Louisiana;

• South Texas; and

• Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois.

Results for the three months ended March 31, 2015, included the following:

• oil, natural gas and NGL sales of approximately $451 million compared to $939 million for the first quarter of 2014;

• average daily production of approximately 1,201 MMcfe/d compared to 1,104 MMcfe/d for the first quarter of 2014;

• net loss of approximately $339 million compared to $85 million for the first quarter of 2014;

• net cash provided by operating activities of approximately $375 million compared to $434 million for the first quarter of 2014;

• capital expenditures, excluding acquisitions, of approximately $197 million compared to $409 million for the first quarter of 2014; and

• 196 wells drilled (all successful) compared to 200 wells drilled (199 successful) for the first quarter of 2014.

Reduction of 2015 Oil and Natural Gas Capital Budget and Distribution

In February 2015, the Company’s Board of Directors approved a revised 2015 budget which includes a 61% reduction in total capital expenditures to approximately $600 million, from approximately $1.6 billion spent in 2014, and includes approximately $520 million related to its oil and natural gas capital program. The 2015 budget contemplates significantly lower commodity prices as compared to 2014. In January 2015, the Company reduced its distribution to $1.25 per unit, from the previous level of $2.90 per unit, on an annualized basis. The reduction of the 2015 budget and the distribution was intended to solidify the Company’s financial position and allow it to regain a useful cost of capital.

28

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Alliance with GSO Capital Partners

In January 2015, the Company announced that it signed a non-binding letter of intent with private capital investor GSO Capital Partners LP (“GSO”) to fund oil and natural gas development (“DrillCo”). Subject to final documentation, funds managed by GSO and its affiliates have agreed to commit up to $500 million with 5-year availability to fund drilling programs on locations provided by LINN Energy. Subject to certain conditions, GSO will fund 100% of the costs associated with new wells drilled under the DrillCo agreement and is expected to receive an 85% working interest in these wells until it achieves a 15% internal rate of return on annual groupings of wells, while LINN Energy is expected to receive a 15% carried working interest during this period. Upon reaching the internal rate of return target, GSO’s interest will be reduced to 5%, while LINN Energy’s interest will increase to 95%.

The DrillCo agreement is subject to final negotiations and approval by the Company and GSO, and as such there can be no assurance that an agreement will be reached on the terms set forth in the letter of intent or at all.

Alliance with Quantum Energy Partners

In March 2015, the Company announced that it signed a non-binding letter of intent with private capital investor Quantum Energy Partners (“Quantum”) to fund selected future oil and natural gas acquisitions and development of those acquired assets (“AcqCo”). Subject to final documentation, Quantum has agreed to initially commit up to $1 billion of equity capital to fund acquisitions and development of oil and natural gas assets. LINN Energy will have the ability to participate in all acquisition opportunities with a direct working interest ranging from 15% to 50%. AcqCo assets will be managed by LINN Energy in exchange for a reimbursement of general and administrative expenses. Additionally, after certain investor return hurdles are met, LINN Energy will have the ability to earn a promoted interest in AcqCo. Upon the sale of any assets within AcqCo, LINN Energy will be given right of first offer to acquire those assets.

The AcqCo agreement is subject to final negotiations and approval by the Company and Quantum, and as such there can be no assurance that an agreement will be reached on the terms set forth in the letter of intent or at all.

Financing Activities

The spring 2015 semi-annual borrowing base redetermination of the Company’s Credit Facilities, as defined in Note 6, is scheduled for May 2015. Pending final approval from its bank group, the Company expects the borrowing base under the LINN Credit Facility to decrease from $4.5 billion to approximately $4.05 billion and the borrowing base under the Berry Credit Facility to decrease from $1.4 billion to approximately $1.2 billion at the upcoming redetermination as a result of lower commodity prices. In connection with the reduction in Berry’s borrowing base, LINN Energy intends to make a contribution to Berry of approximately $250 million, which will be posted as restricted cash with Berry’s lenders and may be returned to LINN Energy in the future if commodity prices improve.

During the three months ended March 31, 2015, the Company, under its equity distribution agreement, issued and sold 1,328,192 units representing limited liability company interests at an average unit price of $11.97 for net proceeds of approximately $16 million (net of approximately $159,000 in commissions). The Company used the net proceeds for general corporate purposes including the open market repurchases of a portion of its 8.625% senior notes due April 2020 (see Note 6). At March 31, 2015, units totaling approximately $484 million in aggregate offering price remained available to be issued and sold under the agreement.

In addition, during the three months ended March 31, 2015, the Company repurchased on the open market approximately $79 million of its 8.625% senior notes due April 2020.

Commodity Derivatives

During the three months ended March 31, 2015, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for May 2015 through December 2017, to hedge exposure to differentials in certain producing areas, and oil swaps for April 2015 through December 2015. In addition, the Company entered into natural gas basis swaps for May 2015 through December 2016 to hedge exposure to the differential in California, where it consumes natural gas in its heavy oil development operations.

In April 2015, the Company entered into oil swaps for May 2015 through December 2015. Including these new hedges, as of April 1, 2015, the Company had oil swaps of approximately 10,039 MBbls at an average price of approximately $91.29 for the remainder of 2015.

29

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Results of Operations

Three Months Ended March 31, 2015, Compared to Three Months Ended March 31, 2014

	Three Months Ended March 31,
	2015			2014			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	172,096		$	226,689		$	(54,593	)
Oil sales	235,237			595,645			(360,408		)
NGL sales	43,236			116,543			(73,307		)
Total oil, natural gas and NGL sales	450,569			938,877			(488,308		)
Gains (losses) on oil and natural gas derivatives	424,781			(241,493		)	666,274
Marketing and other revenues	41,197			36,203			4,994
	916,547			733,587			182,960
Expenses:
Lease operating expenses	173,021			194,033			(21,012		)
Transportation expenses	53,540			45,630			7,910
Marketing expenses	28,841			21,072			7,769
General and administrative expenses (1)	78,968			79,228			(260		)
Exploration costs	396			1,091			(695		)
Depreciation, depletion and amortization	215,014			267,801			(52,787		)
Impairment of long-lived assets	532,617			—			532,617
Taxes, other than income taxes	54,045			65,713			(11,668		)
(Gains) losses on sale of assets and other, net	(12,287		)	2,586			(14,873		)
	1,124,155			677,154			447,001
Other income and (expenses)	(138,679		)	(136,116		)	(2,563		)
Loss before income taxes	(346,287		)	(79,683		)	(266,604		)
Income tax expense (benefit)	(7,127		)	5,654			(12,781		)
Net loss	$	(339,160	)	$	(85,337	)	$	(253,823	)

⁽¹⁾  General and administrative expenses for the three months ended March 31, 2015, and March 31, 2014, include approximately $17 million and $18 million, respectively, of noncash unit-based compensation expenses.

30

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

	Three Months Ended March 31,
	2015		2014		Variance
Average daily production:
Natural gas (MMcf/d)	651		481		35	%
Oil (MBbls/d)	62.8		71.2		(12	)%
NGL (MBbls/d)	28.8		32.5		(11	)%
Total (MMcfe/d)	1,201		1,104		9	%
Weighted average prices: (1)
Natural gas (Mcf)	$	2.94	$	5.23	(44	)%
Oil (Bbl)	$	41.65	$	92.95	(55	)%
NGL (Bbl)	$	16.69	$	39.85	(58	)%
Average NYMEX prices:
Natural gas (MMBtu)	$	2.98	$	4.94	(40	)%
Oil (Bbl)	$	48.64	$	98.68	(51	)%
Costs per Mcfe of production:
Lease operating expenses	$	1.60	$	1.95	(18	)%
Transportation expenses	$	0.50	$	0.46	9	%
General and administrative expenses (2)	$	0.73	$	0.80	(9	)%
Depreciation, depletion and amortization	$	1.99	$	2.70	(26	)%
Taxes, other than income taxes	$	0.50	$	0.66	(24	)%

⁽¹⁾  Does not include the effect of gains (losses) on derivatives.

⁽²⁾  General and administrative expenses for the three months ended March 31, 2015, and March 31, 2014, include approximately $17 million and $18 million, respectively, of noncash unit-based compensation expenses.

31

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales decreased by approximately $488 million or 52% to approximately $451 million for the three months ended March 31, 2015, from approximately $939 million for the three months ended March 31, 2014, due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $289 million, $135 million and $60 million, respectively.

Average daily production volumes increased to approximately 1,201 MMcfe/d for the three months ended March 31, 2015, from 1,104 MMcfe/d for the three months ended March 31, 2014. Higher natural gas production volumes resulted in an increase in revenues of approximately $80 million. Lower oil and NGL production volumes resulted in a decrease in revenues of approximately $71 million and $13 million, respectively.

The following table sets forth average daily production by region:

	Three Months Ended March 31,
	2015	2014	Variance
Average daily production (MMcfe/d):
Rockies	424	273	151		55	%
Hugoton Basin	247	144	103		72	%
California	191	157	34		22	%
Mid-Continent	102	300	(198	)	(66	)%
Permian Basin	94	166	(72	)	(43	)%
TexLa	78	31	47		149	%
South Texas	34	—	34		—
Michigan/Illinois	31	33	(2	)	(6	)%
	1,201	1,104	97		9	%

The increase in average daily production volumes in the Rockies region primarily reflects the impact of the acquisition of properties from subsidiaries of Devon Energy Corporation (the “Devon Assets Acquisition”) on August 29, 2014, and development capital spending. The increase in average daily production volumes in the Hugoton Basin region primarily reflects the impact of the properties received in the exchange with Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., on August 15, 2014, the acquisition of properties from Pioneer Natural Resources Company (the “Pioneer Assets Acquisition”) on September 11, 2014, and development capital spending. The increase in average daily production volumes in the California region primarily reflects the impact of the properties received in the exchange with Exxon Mobil Corporation on November 21, 2014, and development capital spending. The decrease in average daily production volumes in the Mid-Continent region primarily reflects lower production volumes as a result of the properties sold to privately held institutional affiliates of EnerVest, Ltd. and its joint venture partner FourPoint Energy, LLC (the “Granite Wash Assets Sale”) on December 15, 2014, partially offset by the impact of the Devon Assets Acquisition. The decrease in average daily production volumes in the Permian Basin region primarily reflects lower production volumes as a result of the properties relinquished in the two exchanges with ExxonMobil and the properties sold to Fleur de Lis Energy, LLC (the “Permian Basin Assets Sale”) on November 14, 2014. The increase in average daily production volumes in the TexLa region primarily reflects the impact of the Devon Assets Acquisition. Average daily production volumes in the South Texas region reflect the impact of the Devon Assets Acquisition. The decrease in average daily production volumes in the Michigan/Illinois region primarily reflects a low-decline asset base and minimal development capital spending.

32

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

See below for details regarding capital expenditures for the periods presented:

	Three Months Ended March 31,
	2015		2014
	(in thousands)
Oil and natural gas	$	182,973	$	397,200
Plant and pipeline	2,253		5,395
Other	11,561		6,845
Capital expenditures, excluding acquisitions	$	196,787	$	409,440

Gains (Losses) on Oil and Natural Gas Derivatives

Gains on oil and natural gas derivatives were approximately $425 million for the three months ended March 31, 2015, compared to losses of approximately $241 million for the three months ended March 31, 2014, representing a variance of approximately $666 million. Gains on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts. The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.

During the three months ended March 31, 2015, the Company had commodity derivative contracts for approximately 80% of its natural gas production and 70% of its oil production. During the three months ended March 31, 2014, the Company had commodity derivative contracts for approximately 101% of its natural gas production and 96% of its oil production. The Company does not hedge the portion of natural gas production used to economically offset natural gas consumption related to its heavy oil development operations in California.

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. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Note 7 and Note 8 for additional information about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.

Marketing and Other Revenues

Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing and other revenues increased by approximately $5 million or 14% to approximately $41 million for the three months ended March 31, 2015, from approximately $36 million for the three months ended March 31, 2014. The increase was primarily due to higher revenues generated by the Jayhawk natural gas processing plant in Kansas and higher helium sales revenues, partially offset by lower electricity sales revenues generated by the Company’s California cogeneration facilities.

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $21 million or 11% to approximately $173 million for the three months ended March 31, 2015, from approximately $194 million for the three months ended March 31, 2014. The decrease was primarily due to lower costs as a result of the properties sold during the fourth quarter of 2014, a decrease in steam costs caused by a lower price of natural gas used in steam generation and cost savings initiatives, partially offset by costs associated with properties acquired during the third quarter of 2014. Lease operating expenses per Mcfe also decreased to $1.60 per Mcfe for the three months ended March 31, 2015, from $1.95 per Mcfe for the three months ended March 31, 2014.

Transportation Expenses

Transportation expenses increased by approximately $8 million or 17% to approximately $54 million for the three months ended March 31, 2015, from approximately $46 million for the three months ended March 31, 2014. The increase was primarily due to costs associated with properties acquired during the third quarter of 2014 partially offset by lower costs as a

33

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

result of the properties sold during the fourth quarter of 2014. Transportation expenses per Mcfe also increased to $0.50 per Mcfe for the three months ended March 31, 2015, from $0.46 per Mcfe for the three months ended March 31, 2014.

Marketing Expenses

Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $8 million or 37% to approximately $29 million for the three months ended March 31, 2015, from approximately $21 million for the three months ended March 31, 2014. The increase was primarily due to higher expenses associated with the Jayhawk natural gas processing plant in Kansas partially offset by lower electricity generation expenses incurred by the Company’s California cogeneration facilities.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. General and administrative expenses remained consistent at approximately $79 million for both the three months ended March 31, 2015, and March 31, 2014. For the three months ended March 31, 2015, higher acquisition expenses and higher professional services expenses were offset by lower salaries and benefits related expenses, primarily driven by reduced unit-based compensation, and lower various other administrative expenses. General and administrative expenses per Mcfe decreased to $0.73 per Mcfe for the three months ended March 31, 2015, from $0.80 per Mcfe for the three months ended March 31, 2014.

Exploration Costs

Exploration costs decreased by approximately $695,000 or 64% to approximately $396,000 for the three months ended March 31, 2015, from approximately $1 million for the three months ended March 31, 2014. The decrease was primarily due to lower leasehold impairment expenses on unproved properties.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization decreased by approximately $53 million or 20% to approximately $215 million for the three months ended March 31, 2015, from approximately $268 million for the three months ended March 31, 2014. The decrease was primarily due to the 2014 divestitures of properties with higher rates compared to the rates of properties acquired in 2014, as well as lower rates as a result of the impairments recorded in the prior year, partially offset by higher total production volumes. Depreciation, depletion and amortization per Mcfe decreased to $1.99 per Mcfe for the three months ended March 31, 2015, from $2.70 per Mcfe for the three months ended March 31, 2014.

Impairment of Long-Lived Assets

During the three months ended March 31, 2015, the Company recorded noncash impairment charges, before and after tax, of approximately $533 million associated with proved oil and natural gas properties. The impairment was due to a decline in commodity prices. Following are the impairment charges recorded:

• Shallow Texas Panhandle Brown Dolomite formation – $278 million;

• California region – $207 million;

• TexLa region – $33 million;

• South Texas region – $9 million; and

• Mid-Continent region – $6 million.

The Company recorded no impairment charges for the three months ended March 31, 2014.

Taxes, Other Than Income Taxes

	Three Months Ended March 31,
	2015			2014		Variance
	(in thousands)
Severance taxes	$	13,890		$	32,116	$	(18,226	)
Ad valorem taxes	34,116			29,076		5,040
California carbon allowances	6,151			4,519		1,632
Other	(112		)	2		(114		)
	$	54,045		$	65,713	$	(11,668	)

34

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Taxes, other than income taxes decreased by approximately $12 million or 18% for the three months ended March 31, 2015, compared to the three months ended March 31, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to acquisitions completed during the third quarter of 2014. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed, caused by production increases.

Other Income and (Expenses)

	Three Months Ended March 31,
	2015			2014			Variance
	(in thousands)
Interest expense, net of amounts capitalized	$	(143,101	)	$	(133,813	)	$	(9,288	)
Gain on extinguishment of debt	6,635			—			6,635
Other, net	(2,213		)	(2,303		)	90
	$	(138,679	)	$	(136,116	)	$	(2,563	)

Other income and (expenses) increased by approximately $3 million for the three months ended March 31, 2015, compared to the three months ended March 31, 2014. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with the senior notes issued in September 2014 and amendments made to the Company’s Credit Facilities during 2014. In addition, for the three months ended March 31, 2015, the Company recorded a gain on extinguishment of debt of approximately $7 million as a result of the repurchases of a portion of the 8.625% senior notes due April 2020. See “Debt” under “Liquidity and Capital Resources” below for additional details.

Income Tax Expense (Benefit)

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized an income tax benefit of approximately $7 million for the three months ended March 31, 2015, compared to income tax expense of approximately $6 million for the three months ended March 31, 2014. The income tax benefit was primarily due to lower income from the Company’s taxable subsidiaries during the three months ended March 31, 2015, compared to the same period in 2014.

Net Income (Loss)

Net loss increased by approximately $254 million or 297% to approximately $339 million for the three months ended March 31, 2015, from approximately $85 million for the three months ended March 31, 2014. The increase was primarily due to higher impairment charges and lower production revenues, partially offset by higher gains on oil and natural gas derivatives. See discussions above for explanations of variances.

Liquidity and Capital Resources

The Company utilizes funds from debt and equity offerings, borrowings under its Credit Facilities and net cash provided by operating activities for capital resources and liquidity. To date, the primary use of capital has been for acquisitions and the development of oil and natural gas properties. For the three months ended March 31, 2015, the Company’s total capital expenditures, excluding acquisitions, were approximately $197 million. For 2015, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $600 million, including approximately $520 million related to its oil and natural gas capital program and approximately $40 million related to its plant and pipeline capital. This estimate reflects amounts for the development of properties associated with acquisitions (see Note 2), is under continuous review and subject to ongoing adjustments. The Company expects to fund the capital expenditures primarily with net cash provided by

35

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

operating activities. At March 31, 2015, there was approximately $2.0 billion of available borrowing capacity under the LINN Credit Facility but less than $1 million available under the Berry Credit Facility, each as defined in Note 6.

The spring 2015 semi-annual borrowing base redetermination of the Company’s Credit Facilities is scheduled for May 2015. Pending final approval from its bank group, the Company expects the borrowing base under the LINN Credit Facility to decrease from $4.5 billion to approximately $4.05 billion and the borrowing base under the Berry Credit Facility to decrease from $1.4 billion to approximately $1.2 billion at the upcoming redetermination as a result of lower commodity prices. In connection with the reduction in Berry’s borrowing base, LINN Energy intends to make a contribution to Berry of approximately $250 million, which will be posted as restricted cash with Berry’s lenders and may be returned to LINN Energy in the future if commodity prices improve.

As the Company pursues growth, it continually monitors the capital resources available to meet future financial obligations and planned capital expenditures. The Company’s future success in growing reserves and production volumes will be highly dependent on the capital resources available and its success in drilling for or acquiring additional reserves. The Company actively reviews acquisition opportunities on an ongoing basis. If the Company were to make significant additional acquisitions for cash, it would need to borrow additional amounts under its Credit Facilities, if available, or obtain additional debt or equity financing. The Company’s Credit Facilities and indentures governing its senior notes impose certain restrictions on the Company’s ability to obtain additional debt financing. Based upon current expectations, the Company believes its liquidity and capital resources will be sufficient to conduct its business and operations.

Statements of Cash Flows

The following is a comparative cash flow summary:

	Three Months Ended March 31,
	2015			2014			Variance
	(in thousands)
Net cash:
Provided by operating activities	$	374,703		$	434,482		$	(59,779	)
Used in investing activities	(249,719		)	(441,025		)	191,306
Provided by (used in) financing activities	(78,481		)	22,686			(101,167		)
Net increase in cash and cash equivalents	$	46,503		$	16,143		$	30,360

Operating Activities

Cash provided by operating activities for the three months ended March 31, 2015, was approximately $375 million, compared to approximately $434 million for the three months ended March 31, 2014. The decrease was primarily due to lower production related revenues principally due to lower commodity prices partially offset by higher cash settlements on derivatives.

Investing Activities

The following provides a comparative summary of cash flow from investing activities:

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	$	—		$	(25,345	)
Capital expenditures	(277,219		)	(404,994		)
Proceeds from sale of properties and equipment and other	27,500			(10,686		)
	$	(249,719	)	$	(441,025	)

36

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The primary use of cash in investing activities is for capital spending, including acquisitions and the development of the Company’s oil and natural gas properties. Capital expenditures decreased primarily due to lower spending on development activities throughout the Company’s various operating regions as a result of the Company’s reduced 2015 capital budget.

Financing Activities

Cash used in financing activities for the three months ended March 31, 2015, was approximately $78 million, compared to cash provided by financing activities of approximately $23 million for the three months ended March 31, 2014. The decrease in financing cash flow needs was primarily attributable to decreased capital expenditures during the three months ended March 31, 2015, as compared to the three months ended March 31, 2014. The following provides a comparative summary of proceeds from borrowings and repayments of debt:

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Proceeds from borrowings:
LINN Credit Facility	$	395,000		$	540,000
Repayments of debt:
LINN Credit Facility	$	(215,000	)	$	(240,000	)
Senior notes	(65,287		)	(1,188		)
	$	(280,287	)	$	(241,188	)

Debt

The following summarizes the Company’s outstanding debt:

	March 31, 2015			December 31, 2014
	(in thousands, except percentages)
LINN credit facility	$	1,975,000		$	1,795,000
Berry credit facility	1,173,175			1,173,175
Term loan	500,000			500,000
6.50% senior notes due May 2019	1,200,000			1,200,000
6.25% senior notes due November 2019	1,800,000			1,800,000
8.625% senior notes due April 2020	1,220,800			1,300,000
6.75% Berry senior notes due November 2020	299,970			299,970
7.75% senior notes due February 2021	1,000,000			1,000,000
6.50% senior notes due September 2021	650,000			650,000
6.375% Berry senior notes due September 2022	599,163			599,163
Net unamortized discounts and premiums	(19,620		)	(21,499		)
Total debt, net	$	10,398,488		$	10,295,809

At March 31, 2015, there was approximately $2.0 billion of available borrowing capacity under the LINN Credit Facility but less than $1 million available under the Berry Credit Facility. During the three months ended March 31, 2015, the Company repurchased on the open market approximately $79 million of its 8.625% senior notes due April 2020.

For additional information related to the Company’s outstanding debt, see Note 6. The Company plans to file Berry’s stand-alone financial statements with the Securities and Exchange Commission at a later date.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Financial Covenants

The Credit Facilities contain requirements and financial covenants, among others, to maintain: 1) a ratio of EBITDA to Interest Expense (as each term is defined in the LINN Credit Facility) and Adjusted EBITDAX to Interest Expense (as each term is defined in the Berry Credit Facility) (“Interest Coverage Ratio”) for the preceding four quarters of greater than 2.5 to 1.0, and 2) a ratio of adjusted current assets to adjusted current liabilities (as described in the LINN Credit Facility) and Current Assets to Current Liabilities (as each term is defined in the Berry Credit Facility) (“Current Ratio”) as of the last day of any fiscal quarter of greater than 1.0 to 1.0. The Interest Coverage Ratio is intended as a measure of the Company’s ability to make interest payments on its outstanding indebtedness and the Current Ratio is intended as a measure of the Company’s solvency. The Company is required to demonstrate compliance with each of these ratios on a quarterly basis. The following represents the calculations of the Interest Coverage Ratio and the Current Ratio as presented to the lenders under the Credit Facilities:

	At or for the Quarter Ended
	June 30, 2014	September 30, 2014	December 31, 2014	March 31, 2015	Twelve Months Ended March 31, 2015
LINN Credit Facility:
Interest Coverage Ratio	3.7	3.4	2.7	2.9	3.2
Current Ratio	3.4	3.7	2.6	3.0	3.0
Berry Credit Facility:
Interest Coverage Ratio	8.1	9.4	6.7	1.9	6.6
Current Ratio (1)	0.6	2.0	0.6	0.6	0.6
Current Ratio (consolidated) (1)	2.5	3.3	2.9	3.2	3.2

⁽¹⁾  The Berry Credit Facility allows Berry to demonstrate its compliance with the Current Ratio financial covenant on a consolidated basis with LINN Energy for up to three quarters of each calendar year.

The Company has included disclosure of the Interest Coverage Ratio for the twelve months ended March 31, 2015, and the Current Ratio as of March 31, 2015, to demonstrate its compliance for the three months ended March 31, 2015, as well as the Interest Coverage Ratio for each of the preceding four quarters on an individual basis (rather than on a last twelve months basis) and the Current Ratio as of the end of each of the preceding four quarters to provide investors with trend information about the Company’s ongoing compliance with these financial covenants. If the Company fails to demonstrate compliance with either or both of the Interest Coverage Ratio or the Current Ratio as of the end of the quarter and such failure continues beyond applicable cure periods, an event of default would occur and the Company would be unable to make additional borrowings and outstanding indebtedness may be accelerated. The Company depends, in part, on its Credit Facilities for future capital needs. In addition, the Company has drawn on the LINN Credit Facility to fund or partially fund cash distribution payments. Absent such borrowings, the Company would have at times experienced a shortfall in cash available to pay the declared cash distribution amount. For additional information, see “Distribution Practices” below.

The Company is in compliance with all financial and other covenants of its Credit Facilities and senior notes.

Counterparty Credit Risk

The Company accounts for its commodity derivatives at fair value. The Company’s counterparties are current participants or affiliates of participants in its Credit Facilities or were participants or affiliates of participants in its Credit Facilities at the time it originally entered into the derivatives. The LINN Credit Facility is secured by LINN Energy’s oil, natural gas and NGL reserves and the Berry Credit Facility is secured by Berry’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 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.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

At-the-Market Offering Program

The Company has the authority to sell up to $500 million of units under an at-the-market offering program. Sales of units, if any, will be made under an equity distribution agreement by means of ordinary brokers’ transactions, through the facilities of the NASDAQ Global Select Market, any other national securities exchange or facility thereof, a trading facility of a national securities association or an alternate trading system, to or through a market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, at market prices, in block transactions, or as otherwise agreed with a sales agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.

During the three months ended March 31, 2015, the Company, under its equity distribution agreement, issued and sold 1,328,192 units representing limited liability company interests at an average unit price of $11.97 for net proceeds of approximately $16 million (net of approximately $159,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional service expenses of approximately $435,000. The Company used the net proceeds for general corporate purposes including the open market repurchases of a portion of its 8.625% senior notes due April 2020 (see Note 6). At March 31, 2015, units totaling approximately $484 million in aggregate offering price remained available to be issued and sold under the agreement.

Distributions

Under the Company’s limited liability company agreement, unitholders are entitled to receive a distribution of available cash, which includes cash on hand plus borrowings less any reserves established by the Company’s Board of Directors to provide for the proper conduct of the Company’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions over the next four quarters. The following provides a summary of distributions paid by the Company during the three months ended March 31, 2015:

Date Paid	Distributions Per Unit		Total Distributions
			(in millions)
March 2015	$	0.1042	$	35
February 2015	$	0.1042	$	35
January 2015	$	0.1042	$	35

On April 1, 2015, the Company’s Board of Directors declared a cash distribution of $0.3125 per unit with respect to the first quarter of 2015, to be paid in three equal monthly installments of $0.1042 per unit. The first monthly distribution with respect to the first quarter of 2015, totaling approximately $35 million, was paid on April 16, 2015, to unitholders of record as of the close of business on April 13, 2015.

Off-Balance Sheet Arrangements

The Company does not currently have any off-balance sheet arrangements.

Contingencies

See Part II. Item 1. “Legal Proceedings” for information regarding legal proceedings that the Company is party to and any contingencies related to these legal proceedings.

Commitments and Contractual Obligations

The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in the table of contractual obligations in the 2014 Annual Report on Form 10-K. There have been no significant changes to the Company’s contractual obligations since December 31, 2014. See Note 6 for additional information about the Company’s debt instruments.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Distribution Practices

The Company’s Board of Directors determines the appropriate level of distributions on a periodic basis in accordance with the provisions of the Company’s limited liability company agreement. Management considers the timing and size of planned capital expenditures and long-term views about expected results in determining the amount of its distributions. Capital spending and resulting production and net cash provided by operating activities do not typically occur evenly throughout the year due to a variety of factors which are difficult to predict, including rig availability, weather, well performance, the timing of completions and the commodity price environment. Consistent with practices common to publicly traded partnerships, the Company’s Board of Directors historically has not varied the distribution it declares from period to period based on uneven net cash provided by operating activities. The Company’s Board of Directors reviews historical financial results and forecasts for future periods, including development activities, as well as considers the impact of significant acquisitions in making a determination to increase, decrease or maintain the current level of distribution. If shortfalls are sustained over time and forecasts demonstrate expectations for continued future shortfalls, the Company’s Board of Directors may determine to reduce, suspend or discontinue paying distributions.

In January 2015, the Company’s Board of Directors approved a reduction of the Company’s distribution to $1.25 per unit, from the previous level of $2.90 per unit, on an annualized basis. The reduction of the distribution was intended to solidify the Company’s financial position and allow it to regain a useful cost of capital, and was primarily driven by the contemplation of significantly lower commodity prices and a reduced capital budget in 2015 as compared to 2014.

For 2015, the Company’s Board of Directors approved an oil and natural gas capital budget of approximately $520 million. At this level of capital investment, the Company forecasts a modest decline in production during 2015 while it focuses only on projects that generate an acceptable rate of return in the current low commodity price environment, and plans to balance cash flow and spending. As a result, for 2015, the Company intends to fund interest expense, its total oil and natural gas development costs and distributions to unitholders from net cash provided by operating activities, and will present “excess (shortfall) of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors” after deducting total oil and natural gas development costs. Previously, the Company intended to fund interest expense, a portion of its oil and natural gas development costs and distributions to unitholders from net cash provided by operating activities and presented “excess (shortfall) of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors” after deducting only a portion of oil and natural gas development costs.

The Company funds acquisitions and premiums paid for derivatives, if any, primarily with proceeds from debt or equity offerings, borrowings under the LINN Credit Facility or other external sources of funding. Although it is the Company’s practice to acquire or modify derivative instruments with external sources of funding, any cash settlements on derivatives are reported as net cash provided by operating activities and may be used to fund distributions.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

See below for details regarding the discretionary adjustments considered by the Company’s Board of Directors in assessing the appropriate distribution amount for each period, as well as the extent to which sources of funding have been sufficient for the periods presented:

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Net cash provided by operating activities	$	374,703		$	434,482
Distributions to unitholders	(104,815		)	(240,073		)
Excess of net cash provided by operating activities after distributions to unitholders	269,888			194,409
Discretionary adjustments considered by the Board of Directors:
Discretionary reductions for a portion of oil and natural gas development costs (1)	NM*			(193,420		)
Development of oil and natural gas properties (2)	(182,973		)	NM*
Cash received (paid) for acquisitions or divestitures – revenues less operating expenses (3)	(2,712		)	—
Provision for legal matters (4)	(1,000		)	—
Changes in operating assets and liabilities and other, net (5)	(120,337		)	(3,982		)
Shortfall of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors, including a portion of oil and natural gas development costs (6)	NM*			$	(2,993	)
Shortfall of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors, including total development of oil and natural gas properties (6)	$	(37,134	)	NM*

^*  Not meaningful due to the 2015 change in presentation.

⁽¹⁾  Represent discretionary reductions for a portion of oil and natural gas development costs, an estimated component of total development costs. The Board of Directors establishes the discretionary reductions with the objective of replacing proved developed producing reserves, current production and cash flow, taking into consideration the Company’s overall commodity mix. Management evaluates all of these objectives as part of the decision-making process to determine the discretionary reductions for a portion of oil and natural gas development costs for the year, although every objective may not be met in each year. Furthermore, there may be certain years in which commodity prices and other economic conditions do not merit capital spending at a level sufficient to accomplish any of these objectives. The 2014 amounts were established by the Board of Directors at the end of the previous year, allocated across four quarters, and were intended to fully offset declines in production and proved developed producing reserves during the year as compared to the prior year.

The portion of oil and natural gas development costs includes estimated drilling and development costs associated with projects to convert a portion of non-producing reserves to producing status. However, the amounts do not include the historical cost of acquired properties as those amounts have already been spent in prior periods, were financed primarily with external sources of funding and do not affect the Company’s ability to pay distributions in the current period. The Company’s existing reserves, inventory of drilling locations and production levels will decline over time as a result of development and production activities. Consequently, if the Company were to limit its total capital expenditures to this portion of oil and natural gas development costs and not acquire new reserves, total reserves would decrease over time, resulting in an inability to maintain production at current levels, which could adversely affect the Company’s ability to pay a distribution at the current level or at all. However, the Company’s current total reserves do not include reserve additions that may result from converting existing probable and possible resources to additional proved reserves, potential additional discoveries or technological advancements on the Company’s existing acreage position.

⁽²⁾  Represents total capital expenditures for the development of oil and natural gas properties as presented on an accrual basis. For 2015, the Company intends to fund its total oil and natural gas capital program, in addition to interest expense and distributions to unitholders, from net cash provided by operating activities. Previously, the Company intended to fund only a portion of its oil and natural gas capital program, in addition to interest expense and distributions to unitholders, from net cash provided by operating activities.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

⁽³⁾  Represents adjustments to the purchase price of acquisitions and divestitures, based on the Company’s contractual right to revenues less operating expenses for periods from the effective date of a transaction to the closing date of a transaction. When the Company is the buyer, it is legally entitled to revenues less operating expenses generated during this period, and the Company’s Board of Directors has historically made a discretionary adjustment to include this cash in the amount available for distribution. Conversely, when the Company is the seller, the Company’s Board of Directors has historically made a discretionary adjustment to reduce this cash from the amount available for distribution during the period.

⁽⁴⁾  Represents reserves and settlements related to legal matters.

⁽⁵⁾  Represents primarily working capital adjustments. These adjustments may or may not impact cash provided by (used in) operating activities during the respective period, but are included as discretionary adjustments considered by the Company’s Board of Directors as the Board historically has not varied the distribution it declares period to period based on uneven cash flows. The Company’s Board of Directors, when determining the appropriate level of cash distributions, excluded the impact of the timing of cash receipts and payments; as such, this adjustment is necessary to show the historical amounts considered by the Company’s Board of Directors in assessing the appropriate distribution amount for each period.

⁽⁶⁾  Represents the excess (shortfall) of net operating cash flow after distributions to unitholders and discretionary adjustments. Any excess was retained by the Company for future operations, future capital expenditures, future debt service or other future obligations. Any shortfall was funded with cash on hand and/or borrowings under the LINN Credit Facility.

Any cash generated by Berry is currently being used by Berry to fund its activities. To the extent that Berry generates cash in excess of its needs, the indentures governing Berry’s senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and Berry may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Berry indentures. Berry’s restricted payments basket was approximately $206 million at March 31, 2015, and may be increased in accordance with the terms of the Berry indentures by, among other things, 50% of Berry’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions.

A summary of the significant sources and uses of funding for the respective periods is presented below:

	Three Months Ended March 31,
	2015			2014
	(in thousands)
Net cash provided by operating activities	$	374,703		$	434,482
Distributions to unitholders	(104,815		)	(240,073		)
Excess of net cash provided by operating activities after distributions to unitholders	269,888			194,409
Plus (less):
Net cash provided by financing activities (excluding distributions to unitholders)	26,334			262,759
Acquisition of oil and natural gas properties and joint-venture funding	—			(25,345		)
Development of oil and natural gas properties	(264,818		)	(394,843		)
Purchases of other property and equipment	(12,401		)	(10,151		)
Proceeds from sale of properties and equipment and other	27,500			(10,686		)
Net increase in cash and cash equivalents	$	46,503		$	16,143

Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations is based on the condensed consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires management of the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. 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 that are believed to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. Actual results may differ from these estimates and assumptions used in the preparation of the financial statements.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Recently Issued Accounting Standards

For a discussion of recently issued accounting standards, see Note 1 of Notes to Condensed Consolidated Financial Statements.

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond the Company’s control. These statements may include discussions about the Company’s:

• business strategy;

• acquisition strategy;

• financial strategy;

• effects of legal proceedings;

• ability to maintain or grow distributions;

• drilling locations;

• oil, natural gas and NGL reserves;

• realized oil, natural gas and NGL prices;

• production volumes;

• capital expenditures;

• economic and competitive advantages;

• credit and capital market conditions;

• regulatory changes;

• lease operating expenses, general and administrative expenses and development costs;

• future operating results, including results of acquired properties;

• plans, objectives, expectations and intentions; and

• integration of acquired businesses and operations, which may take longer than anticipated, may be more costly than anticipated as a result of unexpected factors or events and may have an unanticipated adverse effect on the Company’s business.

All of these types of statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, are forward-looking statements. These forward-looking statements may be found in Item 2. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on Company expectations, which reflect estimates and assumptions made by Company management. These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors. Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control. In addition, management’s assumptions may prove to be inaccurate. The Company cautions that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors set forth in Item 1A. “Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2014, and elsewhere in the Annual Report. The forward-looking statements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures. All of the Company’s market risk sensitive instruments were entered into for purposes other than trading.

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Item 3.    Quantitative and Qualitative Disclosures About Market Risk - Continued

The following should be read in conjunction with the financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q and in the Company’s 2014 Annual Report on Form 10-K. The reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”

Commodity Price Risk

An important part of the Company’s business strategy includes hedging a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company directly hedges only its oil and natural gas production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials. By removing a significant 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.

Commodity hedging transactions are entered into with respect to a portion of the Company’s 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 enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date.

In addition, as part of the 2013 acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. 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 maintains a substantial portion of its hedges in the form of swap contracts. From time to time, the Company has chosen to purchase put option contracts primarily in connection with acquisition activity to hedge volumes in excess of those already hedged with swap contracts. The appropriate level of production to be hedged is an ongoing consideration and is based on a variety of factors, including current and future expected commodity market prices, cost and availability of put option contracts, the level of acquisition activity and the Company’s overall risk profile, including leverage and size and scale considerations. As a result, the appropriate percentage of production volumes to be hedged may change over time. There have been no significant changes to the Company’s objectives, general strategies or instruments used to manage the Company’s commodity price risk exposures from the year ended December 31, 2014.

In certain historical periods, the Company paid an incremental premium to increase the fixed price floors on existing put options because the Company typically hedges multiple years in advance and in some cases commodity prices had increased significantly beyond the initial hedge prices. As a result, the Company determined that the existing put option strike prices did not provide reasonable downside protection in the context of the current market.

At March 31, 2015, the fair value of fixed price swaps, put option contracts and three-way collars was a net asset of approximately $1.9 billion. A 10% increase in the index oil and natural gas prices above the March 31, 2015, prices would result in a net asset of approximately $1.6 billion, which represents a decrease in the fair value of approximately $347 million; conversely, a 10% decrease in the index oil and natural gas prices below the March 31, 2015, prices would result in a net asset of approximately $2.3 billion, which represents an increase in the fair value of approximately $347 million.

44

Item 3.    Quantitative and Qualitative Disclosures About Market Risk - Continued

At December 31, 2014, the fair value of fixed price swaps, put option contracts and three-way collars was a net asset of approximately $1.8 billion. A 10% increase in the index oil and natural gas prices above the December 31, 2014, prices would result in a net asset of approximately $1.4 billion, which represents a decrease in the fair value of approximately $423 million; conversely, a 10% decrease in the index oil and natural gas prices below the December 31, 2014, prices would result in a net asset of approximately $2.2 billion, which represents an increase in the fair value of approximately $421 million.

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.

The prices of oil, natural gas and NGL have been extremely volatile, and the Company expects this volatility to continue. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for such commodities, market uncertainty and a variety of additional factors that are beyond its control. Actual gains or losses recognized related to the Company’s derivative contracts will likely differ from those estimated at March 31, 2015, and December 31, 2014, and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

The Company cannot be assured that its counterparties will be able to perform under its derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, the Company’s cash flows and ability to pay distributions could be impacted.

Interest Rate Risk

At March 31, 2015, the Company had long-term debt outstanding under its credit facilities and term loan of approximately $3.6 billion which incurred interest at floating rates (see Note 6). A 1% increase in the LIBOR would result in an estimated $36 million increase in annual interest expense.

At December 31, 2014, the Company had long-term debt outstanding under its credit facilities and term loan of approximately $3.5 billion which incurred interest at floating rates. A 1% increase in the LIBOR would result in an estimated $35 million increase in annual interest expense.

Counterparty Credit Risk

The Company accounts for its commodity derivatives at fair value on a recurring basis (see Note 8). The fair value of these derivative financial instruments includes the impact of assumed credit risk adjustments, which are based on the Company’s and counterparties’ published credit ratings, public bond yield spreads and credit default swap spreads, as applicable.

At March 31, 2015, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 2.15%. A 1% increase in the average public bond yield spread would result in an estimated $45,000 increase in net income for the three months ended March 31, 2015. At March 31, 2015, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 2.01%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $22 million decrease in net income for the three months ended March 31, 2015.

At December 31, 2014, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 1.85%. A 1% increase in the average public bond yield spread would result in an estimated $18,000 increase in net income for the year ended December 31, 2014. At December 31, 2014, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 2.15%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $20 million decrease in net income for the year ended December 31, 2014.

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Item 4.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, and the Company’s Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2015.

Changes in the Company’s Internal Control Over Financial Reporting

The Company’s management is also responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The Company’s internal controls were designed to provide reasonable assurance as to the reliability of its financial reporting and the preparation and presentation of the condensed consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.

Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

There were no changes in the Company’s internal control over financial reporting during the first quarter of 2015 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Part II - Other Information

Item 1. Legal Proceedings

The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. With respect to a certain statewide class action case, the Company’s motion to dismiss was denied by the Court, and the parties have agreed on a scheduling order, which provides for briefing on the class certification issues in late 2015 and the first part of 2016. The Company has denied that it has liability on the claims asserted in the case and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. For another statewide class action royalty payment dispute, briefing on class certification issues is expected to be completed during the summer of 2015. The Company has denied that it has any liability on the claims and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. The Company is unable to estimate a possible loss, or range of possible loss, if any, in these cases. In addition, the Company is involved in various other disputes arising in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

Item 1A. Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our units are described in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014. As of the date of this report, these risk factors have not changed materially. This information should be considered carefully, together with other information in this report and other reports and materials we file with the United States Securities and Exchange Commission.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

The Company has the authority to repurchase up to $250 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. The timing and amounts of any such repurchases are at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. The Company did not repurchase any units during the quarter ended March 31, 2015, and as of March 31, 2015, the entire amount remained available for unit repurchase under the program.

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

Not applicable

Item 5. Other Information

None

47

Item 6. Exhibits

Exhibit Number		Description
3.1	—	Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-125501) filed on June 3, 2005)
3.2	—	Certificate of Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S‑1 (File No. 333-125501) filed on June 3, 2005)
3.3	—	Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC dated September 3, 2010 (incorporated herein by reference to Exhibit 3.1 to Current Report on Form 8-K filed on September 7, 2010)
3.4	—	Amendment No. 1, dated April 23, 2013, to Third Amended and Restated LLC Agreement of Linn Energy, LLC, dated September 3, 2010 (incorporated herein by reference to Exhibit 3.1 to Quarterly Report on Form 10-Q filed on April 25, 2013)
31.1*	—	Section 302 Certification of Mark E. Ellis, Chairman, President and Chief Executive Officer of Linn Energy, LLC
31.2*	—	Section 302 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
32.1*	—	Section 906 Certification of Mark E. Ellis, Chairman, President and Chief Executive Officer of Linn Energy, LLC
32.2*	—	Section 906 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
101.INS**	—	XBRL Instance Document
101.SCH**	—	XBRL Taxonomy Extension Schema Document
101.CAL**	—	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	—	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	—	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	—	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith.

** Furnished herewith.

48

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	LINN ENERGY, LLC
	(Registrant)
Date: April 29, 2015	/s/ David B. Rottino
	David B. Rottino
	Executive Vice President, Business Development and Chief Accounting Officer
	(As Duly Authorized Officer and Chief Accounting Officer)

49

EX-31.1

Exhibit 31.1

I, Mark E. Ellis, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Linn Energy, LLC (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

(a)    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 29, 2015

/s/ Mark E. Ellis

Mark E. Ellis

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

I, Kolja Rockov, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Linn Energy, LLC (the “registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

(a)    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 29, 2015

/s/ Kolja Rockov

Kolja Rockov

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Linn Energy, LLC (the “Company”) on Form 10-Q for the quarter ended March 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Mark E. Ellis, Chairman, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: April 29, 2015	/s/ Mark E. Ellis
	Mark E. Ellis
	Chairman, President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Linn Energy, LLC (the “Company”) on Form 10-Q for the quarter ended March 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kolja Rockov, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: April 29, 2015	/s/ Kolja Rockov
	Kolja Rockov
	Executive Vice President and Chief Financial Officer

XML

Unit-Based Compensation (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred Compensation Share-based Arrangements, Liability, Classified, Noncurrent	$ 266,000
Unit-based compensation expense	20,510,000	21,500,000
Aggregate fair value of grants issued to employees	42,000,000
Vesting period of grants issued to employees	3 years
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted to employees	3,468,245
Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted to employees	697,120
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted to employees	567,320
General and administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation expense	16,633,000	18,223,000
General and administrative expenses | Liability Classified Performance Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unit-based compensation expense	$ 266,000

XML

Subsidiary Guarantors Condensed Consolidating Balance Sheets (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 48,312	$ 1,809	$ 68,314	$ 52,171
Accounts receivable – trade, net	340,838	471,684
Accounts receivable – affiliates	0	0
Derivative instruments	1,119,332	1,077,142
Other current assets	147,969	155,955
Total current assets	1,656,451	1,706,590
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	18,246,897	18,068,900
Less accumulated depletion and amortization	(5,592,674)	(4,867,682)
Oil and natural gas properties, successful efforts method, net	12,654,223	13,201,218
Other property and equipment	682,772	669,149
Less accumulated depreciation	(158,409)	(144,282)
Other property and equipment, net	524,363	524,867
Derivative instruments	949,879	848,097
Notes receivable – affiliates	0	0
Advance to affiliate	0	0
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	135,259	142,737
Noncurrent assets, excluding property, total	1,085,138	990,834
Total noncurrent assets	14,263,724	14,716,919
Total assets	15,920,175	16,423,509
Current liabilities:
Accounts payable and accrued expenses	608,926	814,809
Accounts payable – affiliates	0	0
Advance from affiliate	0	0
Derivative instruments	899	0
Other accrued liabilities	184,430	167,736
Total current liabilities	794,255	982,545
Noncurrent liabilities:
Credit facilities	3,148,175	2,968,175
Term loan	500,000	500,000
Senior notes, net	6,750,313	6,827,634
Notes payable – affiliates	0	0
Derivative instruments	1,999	684
Other noncurrent liabilities	598,930	600,866
Total noncurrent liabilities	10,999,417	10,897,359
336,887,489 units and 331,974,913 units issued and outstanding at March 31, 2015, and December 31, 2014, respectively	5,317,869	5,395,811
Unitholders’ capital:
Accumulated deficit	(1,191,366)	(852,206)
Total unitholders' capital	4,126,503	4,543,605
Total liabilities and unitholders’ capital	15,920,175	16,423,509
Reportable Legal Entities [Member] | LINN Energy, LLC
Current assets:
Cash and cash equivalents	3,864	38	33	52
Accounts receivable – trade, net	0	0
Accounts receivable – affiliates	4,011,808	4,028,890
Derivative instruments	0	0
Other current assets	18	18
Total current assets	4,015,690	4,028,946
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	0	0
Less accumulated depletion and amortization	0	0
Oil and natural gas properties, successful efforts method, net	0	0
Other property and equipment	0	0
Less accumulated depreciation	0	0
Other property and equipment, net	0	0
Derivative instruments	0	0
Notes receivable – affiliates	146,900	130,500
Advance to affiliate	0	0
Investments in consolidated subsidiaries	8,296,020	8,562,608
Other noncurrent assets	110,256	116,637
Noncurrent assets, excluding property, total	8,553,176	8,809,745
Total noncurrent assets	8,553,176	8,809,745
Total assets	12,568,866	12,838,691
Current liabilities:
Accounts payable and accrued expenses	5,150	3,784
Accounts payable – affiliates	0	0
Advance from affiliate	0	0
Derivative instruments	0	0
Other accrued liabilities	132,202	89,507
Total current liabilities	137,352	93,291
Noncurrent liabilities:
Credit facilities	1,975,000	1,795,000
Term loan	500,000	500,000
Senior notes, net	5,836,998	5,913,857
Notes payable – affiliates	0	0
Derivative instruments	0	0
Other noncurrent liabilities	0	0
Total noncurrent liabilities	8,311,998	8,208,857
336,887,489 units and 331,974,913 units issued and outstanding at March 31, 2015, and December 31, 2014, respectively	5,310,882	5,388,749
Unitholders’ capital:
Accumulated deficit	(1,191,366)	(852,206)
Total unitholders' capital	4,119,516	4,536,543
Total liabilities and unitholders’ capital	12,568,866	12,838,691
Reportable Legal Entities [Member] | Guarantor Subsidiaries
Current assets:
Cash and cash equivalents	43,024	185	62,762	1,078
Accounts receivable – trade, net	251,957	371,325
Accounts receivable – affiliates	33,061	13,205
Derivative instruments	1,099,777	1,033,448
Other current assets	94,722	96,678
Total current assets	1,522,541	1,514,841
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	13,318,736	13,196,841
Less accumulated depletion and amortization	(4,790,872)	(4,342,675)
Oil and natural gas properties, successful efforts method, net	8,527,864	8,854,166
Other property and equipment	564,928	553,150
Less accumulated depreciation	(147,307)	(135,830)
Other property and equipment, net	417,621	417,320
Derivative instruments	949,798	848,097
Notes receivable – affiliates	0	0
Advance to affiliate	0	0
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	11,660	11,816
Noncurrent assets, excluding property, total	961,458	859,913
Total noncurrent assets	9,906,943	10,131,399
Total assets	11,429,484	11,646,240
Current liabilities:
Accounts payable and accrued expenses	422,042	581,880
Accounts payable – affiliates	4,011,808	4,028,890
Advance from affiliate	220,571	293,627
Derivative instruments	0	0
Other accrued liabilities	37,872	59,142
Total current liabilities	4,692,293	4,963,539
Noncurrent liabilities:
Credit facilities	0	0
Term loan	0	0
Senior notes, net	0	0
Notes payable – affiliates	146,900	130,500
Derivative instruments	1,770	684
Other noncurrent liabilities	401,479	400,851
Total noncurrent liabilities	550,149	532,035
336,887,489 units and 331,974,913 units issued and outstanding at March 31, 2015, and December 31, 2014, respectively	4,831,265	4,831,339
Unitholders’ capital:
Accumulated deficit	1,355,777	1,319,327
Total unitholders' capital	6,187,042	6,150,666
Total liabilities and unitholders’ capital	11,429,484	11,646,240
Reportable Legal Entities [Member] | Non- Guarantor Subsidiary
Current assets:
Cash and cash equivalents	1,424	1,586	5,519	51,041
Accounts receivable – trade, net	88,881	100,359
Accounts receivable – affiliates	0	0
Derivative instruments	19,555	43,694
Other current assets	53,229	59,259
Total current assets	163,089	204,898
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	4,928,161	4,872,059
Less accumulated depletion and amortization	(865,266)	(525,007)
Oil and natural gas properties, successful efforts method, net	4,062,895	4,347,052
Other property and equipment	117,844	115,999
Less accumulated depreciation	(11,102)	(8,452)
Other property and equipment, net	106,742	107,547
Derivative instruments	81	0
Notes receivable – affiliates	0	0
Advance to affiliate	220,571	293,627
Investments in consolidated subsidiaries	0	0
Other noncurrent assets	13,343	14,284
Noncurrent assets, excluding property, total	233,995	307,911
Total noncurrent assets	4,403,632	4,762,510
Total assets	4,566,721	4,967,408
Current liabilities:
Accounts payable and accrued expenses	181,734	229,145
Accounts payable – affiliates	33,061	13,205
Advance from affiliate	0	0
Derivative instruments	899	0
Other accrued liabilities	14,356	19,087
Total current liabilities	230,050	261,437
Noncurrent liabilities:
Credit facilities	1,173,175	1,173,175
Term loan	0	0
Senior notes, net	913,315	913,777
Notes payable – affiliates	0	0
Derivative instruments	229	0
Other noncurrent liabilities	197,451	200,015
Total noncurrent liabilities	2,284,170	2,286,967
336,887,489 units and 331,974,913 units issued and outstanding at March 31, 2015, and December 31, 2014, respectively	2,372,603	2,416,381
Unitholders’ capital:
Accumulated deficit	(320,102)	2,623
Total unitholders' capital	2,052,501	2,419,004
Total liabilities and unitholders’ capital	4,566,721	4,967,408
Eliminations
Current assets:
Cash and cash equivalents	0	0	0	0
Accounts receivable – trade, net	0	0
Accounts receivable – affiliates	(4,044,869)	(4,042,095)
Derivative instruments	0	0
Other current assets	0	0
Total current assets	(4,044,869)	(4,042,095)
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	0	0
Less accumulated depletion and amortization	63,464	0
Oil and natural gas properties, successful efforts method, net	63,464	0
Other property and equipment	0	0
Less accumulated depreciation	0	0
Other property and equipment, net	0	0
Derivative instruments	0	0
Notes receivable – affiliates	(146,900)	(130,500)
Advance to affiliate	(220,571)	(293,627)
Investments in consolidated subsidiaries	(8,296,020)	(8,562,608)
Other noncurrent assets	0	0
Noncurrent assets, excluding property, total	(8,663,491)	(8,986,735)
Total noncurrent assets	(8,600,027)	(8,986,735)
Total assets	(12,644,896)	(13,028,830)
Current liabilities:
Accounts payable and accrued expenses	0	0
Accounts payable – affiliates	(4,044,869)	(4,042,095)
Advance from affiliate	(220,571)	(293,627)
Derivative instruments	0	0
Other accrued liabilities	0	0
Total current liabilities	(4,265,440)	(4,335,722)
Noncurrent liabilities:
Credit facilities	0	0
Term loan	0	0
Senior notes, net	0	0
Notes payable – affiliates	(146,900)	(130,500)
Derivative instruments	0	0
Other noncurrent liabilities	0	0
Total noncurrent liabilities	(146,900)	(130,500)
336,887,489 units and 331,974,913 units issued and outstanding at March 31, 2015, and December 31, 2014, respectively	(7,196,881)	(7,240,658)
Unitholders’ capital:
Accumulated deficit	(1,035,675)	(1,321,950)
Total unitholders' capital	(8,232,556)	(8,562,608)
Total liabilities and unitholders’ capital	$ (12,644,896)	$ (13,028,830)

XML

Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Future inflation factor used in the calculation of the asset retirement obligations	2.00%
Credit adjusted risk-free interest rate for the calculation of the asset retirement obligations	5.60%
Asset retirement obligations rollforward
Asset retirement obligations at December 31, 2014	$ 497,570
Liabilities added from drilling	1,390
Current year accretion expense	7,399
Settlements	(1,783)
Revision of estimates	(1,345)
Asset retirement obligations at March 31, 2015	$ 503,231

XML

Subsidiary Guarantors Condensed Consolidating Statements of Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Revenues and other:
Oil, natural gas and natural gas liquids sales	$ 450,569	$ 938,877
Gains (losses) on oil and natural gas derivatives	424,781	(241,493)
Marketing revenues	33,744	30,546
Other revenues	7,453	5,657
Total revenues	916,547	733,587
Expenses:
Lease operating expenses	173,021	194,033
Transportation expenses	53,540	45,630
Marketing expenses	28,841	21,072
General and administrative expenses	78,968	79,228
Exploration costs	396	1,091
Depreciation, depletion and amortization	215,014	267,801
Impairment of long-lived assets	532,617	0
Taxes, other than income taxes	54,045	65,713
(Gains) losses on sale of assets and other, net	(12,287)	2,586
Total expenses	1,124,155	677,154
Other income and (expenses):
Interest expense, net of amounts capitalized	(143,101)	(133,813)
Interest expense – affiliates	0	0
Interest income – affiliates	0	0
Gain on extinguishment of debt	6,635	0
Equity in earnings from consolidated subsidiaries	0	0
Other, net	(2,213)	(2,303)
Total other income and (expenses)	(138,679)	(136,116)
Loss before income taxes	(346,287)	(79,683)
Income tax expense (benefit)	(7,127)	5,654
Net loss	(339,160)	(85,337)
Reportable Legal Entities [Member] | LINN Energy, LLC
Revenues and other:
Oil, natural gas and natural gas liquids sales	0	0
Gains (losses) on oil and natural gas derivatives	0	0
Marketing revenues	0	0
Other revenues	0	0
Total revenues	0	0
Expenses:
Lease operating expenses	0	0
Transportation expenses	0	0
Marketing expenses	0	0
General and administrative expenses	0	0
Exploration costs	0	0
Depreciation, depletion and amortization	0	0
Impairment of long-lived assets	0
Taxes, other than income taxes	2	0
(Gains) losses on sale of assets and other, net	0	0
Total expenses	2	0
Other income and (expenses):
Interest expense, net of amounts capitalized	(123,386)	(109,650)
Interest expense – affiliates	0	0
Interest income – affiliates	2,382	1,550
Gain on extinguishment of debt	6,635
Equity in earnings from consolidated subsidiaries	(222,811)	24,893
Other, net	(1,978)	(2,130)
Total other income and (expenses)	(339,158)	(85,337)
Loss before income taxes	(339,160)	(85,337)
Income tax expense (benefit)	0	0
Net loss	(339,160)	(85,337)
Reportable Legal Entities [Member] | Guarantor Subsidiaries
Revenues and other:
Oil, natural gas and natural gas liquids sales	293,983	605,761
Gains (losses) on oil and natural gas derivatives	421,514	(244,958)
Marketing revenues	26,212	15,731
Other revenues	5,557	5,673
Total revenues	747,266	382,207
Expenses:
Lease operating expenses	105,832	104,002
Transportation expenses	40,934	37,637
Marketing expenses	23,196	10,091
General and administrative expenses	57,781	35,737
Exploration costs	396	1,091
Depreciation, depletion and amortization	140,699	199,170
Impairment of long-lived assets	325,417
Taxes, other than income taxes	30,711	42,684
(Gains) losses on sale of assets and other, net	(7,814)	(781)
Total expenses	717,152	429,631
Other income and (expenses):
Interest expense, net of amounts capitalized	1,706	(162)
Interest expense – affiliates	(2,382)	(1,550)
Interest income – affiliates	0	0
Gain on extinguishment of debt	0
Equity in earnings from consolidated subsidiaries	0	0
Other, net	(65)	16
Total other income and (expenses)	(741)	(1,696)
Loss before income taxes	29,373	(49,120)
Income tax expense (benefit)	(7,077)	5,685
Net loss	36,450	(54,805)
Reportable Legal Entities [Member] | Non- Guarantor Subsidiary
Revenues and other:
Oil, natural gas and natural gas liquids sales	156,586	333,116
Gains (losses) on oil and natural gas derivatives	3,267	3,465
Marketing revenues	7,532	14,815
Other revenues	1,896	(16)
Total revenues	169,281	351,380
Expenses:
Lease operating expenses	67,189	90,031
Transportation expenses	12,606	7,993
Marketing expenses	5,645	10,981
General and administrative expenses	21,187	43,491
Exploration costs	0	0
Depreciation, depletion and amortization	72,979	68,631
Impairment of long-lived assets	272,000
Taxes, other than income taxes	23,332	23,029
(Gains) losses on sale of assets and other, net	(4,473)	3,367
Total expenses	470,465	247,523
Other income and (expenses):
Interest expense, net of amounts capitalized	(21,421)	(24,001)
Interest expense – affiliates	0	0
Interest income – affiliates	0	0
Gain on extinguishment of debt	0
Equity in earnings from consolidated subsidiaries	0	0
Other, net	(170)	(189)
Total other income and (expenses)	(21,591)	(24,190)
Loss before income taxes	(322,775)	79,667
Income tax expense (benefit)	(50)	(31)
Net loss	(322,725)	79,698
Eliminations
Revenues and other:
Oil, natural gas and natural gas liquids sales	0	0
Gains (losses) on oil and natural gas derivatives	0	0
Marketing revenues	0	0
Other revenues	0	0
Total revenues	0	0
Expenses:
Lease operating expenses	0	0
Transportation expenses	0	0
Marketing expenses	0	0
General and administrative expenses	0	0
Exploration costs	0	0
Depreciation, depletion and amortization	1,336	0
Impairment of long-lived assets	(64,800)
Taxes, other than income taxes	0	0
(Gains) losses on sale of assets and other, net	0	0
Total expenses	(63,464)	0
Other income and (expenses):
Interest expense, net of amounts capitalized	0	0
Interest expense – affiliates	2,382	1,550
Interest income – affiliates	(2,382)	(1,550)
Gain on extinguishment of debt	0
Equity in earnings from consolidated subsidiaries	222,811	(24,893)
Other, net	0	0
Total other income and (expenses)	222,811	(24,893)
Loss before income taxes	286,275	(24,893)
Income tax expense (benefit)	0	0
Net loss	$ 286,275	$ (24,893)

XML

Derivatives (Gains (Losses) On Derivatives) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015 MBbls MMMBTU	Mar. 31, 2014 MBbls MMMBTU
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) on oil and natural gas derivatives	$ 423,855	$ (241,493)
Volume Of Natural Gas Production On Settled Derivatives	46,823	43,651
Cash settlements	282,082	(14,511)
Average Contract Price On Natural Gas Settled Derivatives Per Unit	5.12	5.14
Volume Of Oil On Settled Derivatives	3,975	6,161
Average Contract Price On Oil Settled Derivatives Per Unit	94.29	92.39
Gains (losses) on oil and natural gas derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) on oil and natural gas derivatives	424,781	(241,493)
Lease operating expenses
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) on oil and natural gas derivatives	$ (1,000)

XML

Subsidiary Guarantors (Tables)

3 Months Ended

Mar. 31, 2015

Condensed Consolidating Financial Information [Abstract]

Condensed Consolidating Balance Sheets

CONDENSED CONSOLIDATING BALANCE SHEETS

March 31, 2015

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	3,864		$	43,024		$	1,424		$	—		$	48,312
Accounts receivable – trade, net	—			251,957			88,881			—			340,838
Accounts receivable – affiliates	4,011,808			33,061			—			(4,044,869		)	—
Derivative instruments	—			1,099,777			19,555			—			1,119,332
Other current assets	18			94,722			53,229			—			147,969
Total current assets	4,015,690			1,522,541			163,089			(4,044,869		)	1,656,451
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	—			13,318,736			4,928,161			—			18,246,897
Less accumulated depletion and amortization	—			(4,790,872		)	(865,266		)	63,464			(5,592,674		)
	—			8,527,864			4,062,895			63,464			12,654,223
Other property and equipment	—			564,928			117,844			—			682,772
Less accumulated depreciation	—			(147,307		)	(11,102		)	—			(158,409		)
	—			417,621			106,742			—			524,363
Derivative instruments	—			949,798			81			—			949,879
Notes receivable – affiliates	146,900			—			—			(146,900		)	—
Advance to affiliate	—			—			220,571			(220,571		)	—
Investments in consolidated subsidiaries	8,296,020			—			—			(8,296,020		)	—
Other noncurrent assets, net	110,256			11,660			13,343			—			135,259
	8,553,176			961,458			233,995			(8,663,491		)	1,085,138
Total noncurrent assets	8,553,176			9,906,943			4,403,632			(8,600,027		)	14,263,724
Total assets	$	12,568,866		$	11,429,484		$	4,566,721		$	(12,644,896	)	$	15,920,175
LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	5,150		$	422,042		$	181,734		$	—		$	608,926
Accounts payable – affiliates	—			4,011,808			33,061			(4,044,869		)	—
Advance from affiliate	—			220,571			—			(220,571		)	—
Derivative instruments	—			—			899			—			899
Other accrued liabilities	132,202			37,872			14,356			—			184,430
Total current liabilities	137,352			4,692,293			230,050			(4,265,440		)	794,255
Noncurrent liabilities:
Credit facilities	1,975,000			—			1,173,175			—			3,148,175
Term loan	500,000			—			—			—			500,000
Senior notes, net	5,836,998			—			913,315			—			6,750,313
Notes payable – affiliates	—			146,900			—			(146,900		)	—
Derivative instruments	—			1,770			229			—			1,999
Other noncurrent liabilities	—			401,479			197,451			—			598,930
Total noncurrent liabilities	8,311,998			550,149			2,284,170			(146,900		)	10,999,417
Unitholders’ capital:
Units issued and outstanding	5,310,882			4,831,265			2,372,603			(7,196,881		)	5,317,869
Accumulated income (deficit)	(1,191,366		)	1,355,777			(320,102		)	(1,035,675		)	(1,191,366		)
	4,119,516			6,187,042			2,052,501			(8,232,556		)	4,126,503
Total liabilities and unitholders’ capital	$	12,568,866		$	11,429,484		$	4,566,721		$	(12,644,896	)	$	15,920,175

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2014

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	38		$	185		$	1,586		$	—		$	1,809
Accounts receivable – trade, net	—			371,325			100,359			—			471,684
Accounts receivable – affiliates	4,028,890			13,205			—			(4,042,095		)	—
Derivative instruments	—			1,033,448			43,694			—			1,077,142
Other current assets	18			96,678			59,259			—			155,955
Total current assets	4,028,946			1,514,841			204,898			(4,042,095		)	1,706,590
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	—			13,196,841			4,872,059			—			18,068,900
Less accumulated depletion and amortization	—			(4,342,675		)	(525,007		)	—			(4,867,682		)
	—			8,854,166			4,347,052			—			13,201,218
Other property and equipment	—			553,150			115,999			—			669,149
Less accumulated depreciation	—			(135,830		)	(8,452		)	—			(144,282		)
	—			417,320			107,547			—			524,867
Derivative instruments	—			848,097			—			—			848,097
Notes receivable – affiliates	130,500			—			—			(130,500		)	—
Advance to affiliate	—			—			293,627			(293,627		)	—
Investments in consolidated subsidiaries	8,562,608			—			—			(8,562,608		)	—
Other noncurrent assets, net	116,637			11,816			14,284			—			142,737
	8,809,745			859,913			307,911			(8,986,735		)	990,834
Total noncurrent assets	8,809,745			10,131,399			4,762,510			(8,986,735		)	14,716,919
Total assets	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509
LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	3,784		$	581,880		$	229,145		$	—		$	814,809
Accounts payable – affiliates	—			4,028,890			13,205			(4,042,095		)	—
Advance from affiliate	—			293,627			—			(293,627		)	—
Derivative instruments	—			—			—			—			—
Other accrued liabilities	89,507			59,142			19,087			—			167,736
Total current liabilities	93,291			4,963,539			261,437			(4,335,722		)	982,545
Noncurrent liabilities:
Credit facilities	1,795,000			—			1,173,175			—			2,968,175
Term loan	500,000			—			—			—			500,000
Senior notes, net	5,913,857			—			913,777			—			6,827,634
Notes payable – affiliates	—			130,500			—			(130,500		)	—
Derivative instruments	—			684			—			—			684
Other noncurrent liabilities	—			400,851			200,015			—			600,866
Total noncurrent liabilities	8,208,857			532,035			2,286,967			(130,500		)	10,897,359
Unitholders’ capital:
Units issued and outstanding	5,388,749			4,831,339			2,416,381			(7,240,658		)	5,395,811
Accumulated income (deficit)	(852,206		)	1,319,327			2,623			(1,321,950		)	(852,206		)
	4,536,543			6,150,666			2,419,004			(8,562,608		)	4,543,605
Total liabilities and unitholders’ capital	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509

Condensed Consolidating Statements of Operations

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2015

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	293,983		$	156,586		$	—		$	450,569
Gains on oil and natural gas derivatives	—			421,514			3,267			—			424,781
Marketing revenues	—			26,212			7,532			—			33,744
Other revenues	—			5,557			1,896			—			7,453
	—			747,266			169,281			—			916,547
Expenses:
Lease operating expenses	—			105,832			67,189			—			173,021
Transportation expenses	—			40,934			12,606			—			53,540
Marketing expenses	—			23,196			5,645			—			28,841
General and administrative expenses	—			57,781			21,187			—			78,968
Exploration costs	—			396			—			—			396
Depreciation, depletion and amortization	—			140,699			72,979			1,336			215,014
Impairment of long-lived assets	—			325,417			272,000			(64,800		)	532,617
Taxes, other than income taxes	2			30,711			23,332			—			54,045
Gains on sale of assets and other, net	—			(7,814		)	(4,473		)	—			(12,287		)
	2			717,152			470,465			(63,464		)	1,124,155
Other income and (expenses):
Interest expense, net of amounts capitalized	(123,386		)	1,706			(21,421		)	—			(143,101		)
Interest expense – affiliates	—			(2,382		)	—			2,382			—
Interest income – affiliates	2,382			—			—			(2,382		)	—
Gain on extinguishment of debt	6,635			—			—			—			6,635
Equity in losses from consolidated subsidiaries	(222,811		)	—			—			222,811			—
Other, net	(1,978		)	(65		)	(170		)	—			(2,213		)
	(339,158		)	(741		)	(21,591		)	222,811			(138,679		)
Income (loss) before income taxes	(339,160		)	29,373			(322,775		)	286,275			(346,287		)
Income tax benefit	—			(7,077		)	(50		)	—			(7,127		)
Net income (loss)	$	(339,160	)	$	36,450		$	(322,725	)	$	286,275		$	(339,160	)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2014

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	605,761		$	333,116		$	—		$	938,877
Gains (losses) on oil and natural gas derivatives	—			(244,958		)	3,465			—			(241,493		)
Marketing revenues	—			15,731			14,815			—			30,546
Other revenues	—			5,673			(16		)	—			5,657
	—			382,207			351,380			—			733,587
Expenses:
Lease operating expenses	—			104,002			90,031			—			194,033
Transportation expenses	—			37,637			7,993			—			45,630
Marketing expenses	—			10,091			10,981			—			21,072
General and administrative expenses	—			35,737			43,491			—			79,228
Exploration costs	—			1,091			—			—			1,091
Depreciation, depletion and amortization	—			199,170			68,631			—			267,801
Taxes, other than income taxes	—			42,684			23,029			—			65,713
(Gains) losses on sale of assets and other, net	—			(781		)	3,367			—			2,586
	—			429,631			247,523			—			677,154
Other income and (expenses):
Interest expense, net of amounts capitalized	(109,650		)	(162		)	(24,001		)	—			(133,813		)
Interest expense – affiliates	—			(1,550		)	—			1,550			—
Interest income – affiliates	1,550			—			—			(1,550		)	—
Equity in earnings from consolidated subsidiaries	24,893			—			—			(24,893		)	—
Other, net	(2,130		)	16			(189		)	—			(2,303		)
	(85,337		)	(1,696		)	(24,190		)	(24,893		)	(136,116		)
Income (loss) before income taxes	(85,337		)	(49,120		)	79,667			(24,893		)	(79,683		)
Income tax expense (benefit)	—			5,685			(31		)	—			5,654
Net income (loss)	$	(85,337	)	$	(54,805	)	$	79,698		$	(24,893	)	$	(85,337	)

Condensed Consolidating Statements of Cash Flows

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2015

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(339,160	)	$	36,450		$	(322,725	)	$	286,275		$	(339,160	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			140,699			72,979			1,336			215,014
Impairment of long-lived assets	—			325,417			272,000			(64,800		)	532,617
Unit-based compensation expenses	—			20,510			—			—			20,510
Gain on extinguishment of debt	(6,635		)	—			—			—			(6,635		)
Amortization and write-off of deferred financing fees	6,453			—			259			—			6,712
Gains on sale of assets and other, net	—			(5,243		)	(1,857		)	—			(7,100		)
Equity in losses from consolidated subsidiaries	222,811			—			—			(222,811		)	—
Deferred income taxes	—			(7,108		)	(50		)	—			(7,158		)
Derivatives activities:
Total gains	—			(421,514		)	(2,341		)	—			(423,855		)
Cash settlements	—			254,569			27,513			—			282,082
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net	21,921			96,917			16,392			—			135,230
(Increase) decrease in accounts receivable – affiliates	17,082			(19,856		)	—			2,774			—
Increase in other assets	—			(8,521		)	(3,878		)	—			(12,399		)
Decrease in accounts payable and accrued expenses	(290		)	(3,844		)	(25,734		)	—			(29,868		)
Increase (decrease) in accounts payable and accrued expenses – affiliates	—			(17,082		)	19,856			(2,774		)	—
Increase (decrease) in other liabilities	42,695			(24,057		)	(9,925		)	—			8,713
Net cash provided by (used in) operating activities	(35,123		)	367,337			42,489			—			374,703
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			—			—			—			—
Development of oil and natural gas properties	—			(263,209		)	(1,609		)	—			(264,818		)
Purchases of other property and equipment	—			(11,309		)	(1,092		)	—			(12,401		)
Investment in affiliates	43,778			—			—			(43,778		)	—
Change in notes receivable with affiliate	(16,400		)	—			—			16,400			—
Proceeds from sale of properties and equipment and other	(1,121		)	24,808			3,813			—			27,500
Net cash provided by (used in) investing activities	26,257			(249,710		)	1,112			(27,378		)	(249,719		)

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from financing activities:
Proceeds from sale of units	15,900			—			—			—			15,900
Proceeds from borrowings	395,000			—			—			—			395,000
Repayments of debt	(280,287		)	—			—			—			(280,287		)
Distributions to unitholders	(104,815		)	—			—			—			(104,815		)
Financing fees and offering costs	(453		)	—			—			—			(453		)
Change in notes payable with affiliate	—			16,400			—			(16,400		)	—
Distribution to affiliate	—			—			(43,778		)	43,778			—
Excess tax benefit from unit-based compensation	(8,867		)	—			—			—			(8,867		)
Other	(3,786		)	(91,188		)	15			—			(94,959		)
Net cash provided by (used in) financing activities	12,692			(74,788		)	(43,763		)	27,378			(78,481		)
Net increase (decrease) in cash and cash equivalents	3,826			42,839			(162		)	—			46,503
Cash and cash equivalents:
Beginning	38			185			1,586			—			1,809
Ending	$	3,864		$	43,024		$	1,424		$	—		$	48,312

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2014

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(85,337	)	$	(54,805	)	$	79,698		$	(24,893	)	$	(85,337	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			199,170			68,631			—			267,801
Unit-based compensation expenses	—			21,500			—			—			21,500
Amortization and write-off of deferred financing fees	5,791			—			(3,478		)	—			2,313
Losses on sale of assets and other, net	—			1,327			—			—			1,327
Equity in earnings from consolidated subsidiaries	(24,893		)	—			—			24,893			—
Deferred income taxes	—			5,615			(31		)	—			5,584
Derivatives activities:
Total (gains) losses	—			244,958			(3,465		)	—			241,493
Cash settlements	—			(11,856		)	(2,655		)	—			(14,511		)
Changes in assets and liabilities:
Increase in accounts receivable – trade, net	—			(18,964		)	(15,373		)	—			(34,337		)
Decrease in accounts receivable – affiliates	10,513			16,950			—			(27,463		)	—
Increase in other assets	—			(3,136		)	(1,040		)	—			(4,176		)
Increase (decrease) in accounts payable and accrued expenses	30			20,252			(4,177		)	—			16,105
Decrease in accounts payable and accrued expenses – affiliates	—			(10,513		)	(16,950		)	27,463			—
Increase (decrease) in other liabilities	53,698			(30,648		)	(6,330		)	—			16,720
Net cash provided by (used in) operating activities	(40,198		)	379,850			94,830			—			434,482
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			(25,345		)	—			—			(25,345		)
Development of oil and natural gas properties	—			(260,093		)	(134,750		)	—			(394,843		)
Purchases of other property and equipment	—			(8,318		)	(1,833		)	—			(10,151		)
Change in notes receivable with affiliate	(9,200		)	—			—			9,200			—
Proceeds from sale of properties and equipment and other	(11,230		)	544			—			—			(10,686		)
Net cash used in investing activities	(20,430		)	(293,212		)	(136,583		)	9,200			(441,025		)

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from financing activities:
Proceeds from borrowings	540,000			—			—			—			540,000
Repayments of debt	(240,000		)	—			(1,188		)	—			(241,188		)
Distributions to unitholders	(240,073		)	—			—			—			(240,073		)
Financing fees and offering costs	(81		)	—			(2,581		)	—			(2,662		)
Change in notes payable with affiliate	—			9,200			—			(9,200		)	—
Excess tax benefit from unit-based compensation	—			1,457			—			—			1,457
Other	763			(35,611		)	—			—			(34,848		)
Net cash provided by (used in) financing activities	60,609			(24,954		)	(3,769		)	(9,200		)	22,686
Net increase (decrease) in cash and cash equivalents	(19		)	61,684			(45,522		)	—			16,143
Cash and cash equivalents:
Beginning	52			1,078			51,041			—			52,171
Ending	$	33		$	62,762		$	5,519		$	—		$	68,314

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Subsidiary Guarantors Details (Details)	3 Months Ended
	Mar. 31, 2015
Condensed Consolidating Financial Information [Abstract]
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions	100.00%

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Oil and Natural Gas Properties (Tables)

3 Months Ended

Mar. 31, 2015

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Capitalized Costs Related to Oil, Natural Gas and NGL Production Activities

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

	March 31, 2015			December 31, 2014
	(in thousands)
Proved properties:
Leasehold acquisition	$	13,368,818		$	13,362,642
Development	3,012,467			2,830,841
Unproved properties	1,865,612			1,875,417
	18,246,897			18,068,900
Less accumulated depletion and amortization	(5,592,674		)	(4,867,682		)
	$	12,654,223		$	13,201,218

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Earnings Per Unit (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Earnings Per Share [Abstract]
Net loss	$ (339,160)	$ (85,337)
Allocated to participating securities	(1,781)	(2,199)
Net income (loss) available to common unitholders, basic	$ (340,941)	$ (87,536)
Earnings per share reconciliation
Basic loss per unit (in usd per unit)	$ (1.03)	$ (0.27)
Diluted loss per unit (in usd per unit)	$ (1.03)	$ (0.27)
Weighted average units outstanding
Basic weighted average units outstanding	330,642,000	328,329,000
Dilutive effect of unit equivalents	0	0
Diluted weighted average units outstanding	330,642,000	328,329,000
Unit options and warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average anti-dilutive unit equivalents excluded from computation of earnings per unit (in units)	5,000,000	6,000,000

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Debt Schedule of Long Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Debt Instrument [Line Items]
Credit facilities	$ 3,148,175		$ 2,968,175
Term loan	500,000		500,000
Senior notes, net	6,750,313		6,827,634
Total debt, net	10,398,488		10,295,809
Less current maturities	0		0
Total long-term debt, net	10,398,488		10,295,809
Senior Notes [Member]
Debt Instrument [Line Items]
Net unamortized discounts and premiums	(19,620)		(21,499)
Linn Energy, LLC [Member] | Line of Credit
Debt Instrument [Line Items]
Credit facilities	1,975,000	[1]	1,795,000	[1]
Linn Energy, LLC [Member] | Line of Credit | Credit Facility
Debt Instrument [Line Items]
Debt Instrument Interest Rate Period End	1.93%		1.92%
Linn Energy, LLC [Member] | Loans Payable [Member]
Debt Instrument [Line Items]
Term loan	500,000	[2]	500,000	[2]
Debt Instrument Interest Rate Period End	2.68%		2.66%
Linn Energy, LLC [Member] | Senior Notes [Member] | Senior Notes Due May 2019
Debt Instrument [Line Items]
Senior notes, net	1,200,000		1,200,000
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Linn Energy, LLC [Member] | Senior Notes [Member] | Senior Notes Due November 2019
Debt Instrument [Line Items]
Senior notes, net	1,800,000		1,800,000
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Linn Energy, LLC [Member] | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Senior notes, net	1,220,800		1,300,000
Debt Instrument, Interest Rate, Stated Percentage	8.625%
Linn Energy, LLC [Member] | Senior Notes [Member] | Senior Notes Due September 2021 [Member]
Debt Instrument [Line Items]
Senior notes, net	650,000		650,000
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Linn Energy, LLC [Member] | Senior Notes [Member] | Senior Notes Due February 2021 [Member]
Debt Instrument [Line Items]
Senior notes, net	1,000,000		1,000,000
Debt Instrument, Interest Rate, Stated Percentage	7.75%
Berry [Member] | Line of Credit
Debt Instrument [Line Items]
Credit facilities	1,173,175	[3]	1,173,175	[3]
Berry [Member] | Line of Credit | Credit Facility
Debt Instrument [Line Items]
Debt Instrument Interest Rate Period End	2.68%		2.67%
Berry [Member] | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Senior notes, net	299,970		299,970
Debt Instrument, Interest Rate, Stated Percentage	6.75%
Berry [Member] | Senior Notes [Member] | Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Senior notes, net	$ 599,163		$ 599,163
Debt Instrument, Interest Rate, Stated Percentage	6.375%

[1] Variable interest rates of 1.93% and 1.92% at March 31, 2015, and December 31, 2014, respectively.

[2] Variable interest rates of 2.68% and 2.66% at March 31, 2015, and December 31, 2014, respectively.

[3] Variable interest rates of 2.68% and 2.67% at March 31, 2015, and December 31, 2014, respectively.

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Unitholders' Capital At-The-Market Offering (Details) (USD $)	3 Months Ended
	Mar. 31, 2015
Debt Instrument [Line Items]
Equity Offering Program Maximum Value	$ 500,000,000
Sale of units (in units)	1,328,192
EquityOfferingProgramPricePerUnit	$ 11.97
EquityOfferingProgramNetProceeds	16,000,000
Equity Distribution Agreement Commissions And Professional Service Expenses	159,000
Equity distribution agreement professional service expenses	435,000
EquityOfferingProgramRemainingBalance	$ 484,000,000
Linn Energy, LLC [Member] | Senior Notes Due 2020 | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.625%

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Cash Flows) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Cash payments for interest, net of amounts capitalized	$ 98,541,000	$ 77,512,000
Cash payments for income taxes	57,000	0
Noncash investing activities:
Accrued capital expenditures	161,247,000	338,323,000
Joint-venture funding		25,000,000
Net Outstanding Checks	$ 0		$ 95,000,000

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Fair Value Measurements on a Recurring Basis (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Assets:
Commodity derivatives	$ 2,106,710		$ 2,014,815
Commodity derivatives	(37,499)	[1]	(89,576)	[1]
Commodity derivatives	2,069,211		1,925,239
Liabilities:
Commodity derivatives	40,397		90,260
Commodity derivatives	(37,499)	[1]	(89,576)	[1]
Commodity derivatives	$ 2,898		$ 684

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

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Acquisitions and Joint-Venture Funding

3 Months Ended

Mar. 31, 2015

Business Combinations [Abstract]

Acquisitions and Joint-Venture Funding

Acquisitions and Joint-Venture Funding

The revenues and expenses related to certain oil and natural gas properties acquired in 2014 from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) are included in the condensed consolidated results of operations of the Company as of August 29, 2014. The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the three months ended March 31, 2014, assuming the Devon Assets Acquisition had been completed as of January 1, 2014, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information has been prepared for informational purposes only and does not purport to represent what the actual results of operations would have been had the transaction been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The pro forma financial information does not give effect to the costs of any integration activities or benefits that may result from the realization of future cost savings from operating efficiencies, or any other synergies that may result from the transaction.

	Three Months Ended March 31, 2014
	(in thousands, except per unit amounts)
Total revenues and other	$	879,115
Total operating expenses	$	765,491
Net loss	$	(62,305	)
Net loss per unit:
Basic	$	(0.20	)
Diluted	$	(0.20	)

The pro forma condensed combined statement of operations includes adjustments to:

• Reflect the results of the Devon Assets Acquisition.

• Reflect incremental depreciation, depletion and amortization expense, using the unit-of-production method related to oil and natural gas properties acquired and an estimated useful life of 10 years for other property and equipment.

• Reflect incremental accretion expense related to asset retirement obligations on oil and natural gas properties acquired.

• Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price.

• Reflect incremental amortization of deferred financing fees associated with debt incurred to fund the purchase price.

Joint-Venture Funding – 2014

For the three months ended March 31, 2014, the Company paid approximately $25 million, including interest, to fund the commitment related to the joint-venture agreement it entered into with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) in April 2012. As of February 2014, the Company had fully funded the total commitment of $400 million.

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Debt Debt Fair Value Disclosure (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Carrying Value
Credit facilities	$ 3,148,175	$ 2,968,175
Term loan	500,000	500,000
Senior notes, net	6,750,313	6,827,634
Total debt, net	10,398,488	10,295,809
Fair Value
Credit facilities	3,148,175	2,968,175
Term loan	500,000	500,000
Senior notes, net	5,454,065	5,703,649
Total debt, net	$ 9,102,240	$ 9,171,824

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Fair Value Measurements on a Recurring Basis (Tables)

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements, Recurring Basis

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

	March 31, 2015
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	2,106,710	$	(37,499	)	$	2,069,211
Liabilities:
Commodity derivatives	$	40,397	$	(37,499	)	$	2,898

	December 31, 2014
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	2,014,815	$	(89,576	)	$	1,925,239
Liabilities:
Commodity derivatives	$	90,260	$	(89,576	)	$	684

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

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Derivatives (Tables)

3 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

The following table summarizes derivative positions for the periods indicated as of March 31, 2015:

	April 1 - December 31, 2015		2016		2017		2018
Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMMBtu)	88,935		121,841		120,122		36,500
Average price ($/MMBtu)	$	5.19	$	4.20	$	4.26	$	5.00
Put options (NYMEX Henry Hub):
Hedged volume (MMMBtu)	54,137		76,269		66,886		—
Average price ($/MMBtu)	$	5.00	$	5.00	$	4.88	$	—
Oil positions:
Fixed price swaps (NYMEX WTI): (1)
Hedged volume (MBbls)	9,426		11,465		4,755		—
Average price ($/Bbl)	$	93.33	$	90.56	$	89.02	$	—
Three-way collars (NYMEX WTI):
Hedged volume (MBbls)	825		—		—		—
Short put ($/Bbl)	$	70.00	$	—	$	—	$	—
Long put ($/Bbl)	$	90.00	$	—	$	—	$	—
Short call ($/Bbl)	$	101.62	$	—	$	—	$	—
Put options (NYMEX WTI):
Hedged volume (MBbls)	2,581		3,271		384		—
Average price ($/Bbl)	$	90.00	$	90.00	$	90.00	$	—

	April 1 - December 31, 2015			2016			2017			2018
Natural gas basis differential positions:(2)
Panhandle basis swaps: (3)
Hedged volume (MMMBtu)	65,670			59,954			59,138			16,425
Hedged differential ($/MMBtu)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)
NWPL Rockies basis swaps: (3)
Hedged volume (MMMBtu)	43,707			65,794			38,880			10,804
Hedged differential ($/MMBtu)	$	(0.23	)	$	(0.24	)	$	(0.19	)	$	(0.19	)
MichCon basis swaps: (3)
Hedged volume (MMMBtu)	7,040			7,768			7,437			2,044
Hedged differential ($/MMBtu)	$	0.06		$	0.05		$	0.05		$	0.05
Houston Ship Channel basis swaps: (3)
Hedged volume (MMMBtu)	19,351			34,364			36,730			986
Hedged differential ($/MMBtu)	$	(0.03	)	$	(0.02	)	$	(0.02	)	$	(0.08	)
Permian basis swaps: (3)
Hedged volume (MMMBtu)	3,823			4,219			4,819			1,314
Hedged differential ($/MMBtu)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)
SoCal basis swaps: (4)
Hedged volume (MMMBtu)	22,050			32,940			—			—
Hedged differential ($/MMBtu)	$	(0.03	)	$	(0.03	)	$	—		$	—
Oil timing differential positions:
Trade month roll swaps (NYMEX WTI): (5)
Hedged volume (MBbls)	5,463			7,446			6,486			—
Hedged differential ($/Bbl)	$	0.24		$	0.25		$	0.25		$	—

⁽¹⁾  Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, at counterparty election on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

⁽²⁾  Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.

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

⁽⁴⁾  For positions which hedge exposure to differentials in consuming areas, the Company pays the NYMEX Henry Hub natural gas price plus the respective spread and receives the specified index price. Cash settlements are made on a net basis.

⁽⁵⁾  The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

Fair Value of Derivatives Outstanding on a Gross Basis by Location on the Balance Sheet

The following summarizes the fair value of derivatives outstanding on a gross basis:

	March 31, 2015		December 31, 2014
	(in thousands)
Assets:
Commodity derivatives	$	2,106,710	$	2,014,815
Liabilities:
Commodity derivatives	$	40,397	$	90,260

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Subsidiary Guarantors Condensed Consolidating Statements of Cash Flow (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Cash flow from operating activities:
Net loss	$ (339,160)	$ (85,337)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	215,014	267,801
Impairment of long-lived assets	532,617	0
Unit-based compensation expenses	20,510	21,500
Gain on extinguishment of debt	(6,635)	0
Amortization and write-off of deferred financing fees	6,712	2,313
(Gains) losses on sale of assets and other, net	(7,100)	1,327
Equity in losses from consolidated subsidiaries	0	0
Deferred income taxes	(7,158)	5,584
Total (gains) losses	423,855	(241,493)
Derivatives activities:
Cash settlements	282,082	(14,511)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	135,230	(34,337)
(Increase) decrease in accounts receivable – affiliates	0	0
Increase in other assets	(12,399)	(4,176)
Increase (decrease) in accounts payable and accrued expenses	(29,868)	16,105
Increase (decrease) in accounts payable and accrued expenses – affiliates	0	0
Increase in other liabilities	8,713	16,720
Net cash provided by operating activities	374,703	434,482
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	0	(25,345)
Development of oil and natural gas properties	(264,818)	(394,843)
Purchases of other property and equipment	(12,401)	(10,151)
Investment in affiliates	0
Change in notes receivable with affiliate	0	0
Proceeds from sale of properties and equipment and other	27,500	(10,686)
Net cash used in investing activities	(249,719)	(441,025)
Cash flow from financing activities:
Proceeds from sale of units	15,900	0
Proceeds from borrowings	395,000	540,000
Repayments of debt	(280,287)	(241,188)
Distributions to unitholders	(104,815)	(240,073)
Financing fees and offering costs	(453)	(2,662)
Change in notes payable with affiliate	0	0
Distribution to affiliate	0
Excess tax benefit from unit-based compensation	(8,867)	1,457
Other	(94,959)	(34,848)
Net cash provided by (used in) financing activities	(78,481)	22,686
Net increase in cash and cash equivalents	46,503	16,143
Cash and cash equivalents:
Beginning	1,809	52,171
Ending	48,312	68,314
Reportable Legal Entities [Member] | LINN Energy, LLC
Cash flow from operating activities:
Net loss	(339,160)	(85,337)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	0	0
Impairment of long-lived assets	0
Unit-based compensation expenses	0	0
Gain on extinguishment of debt	(6,635)
Amortization and write-off of deferred financing fees	6,453	5,791
(Gains) losses on sale of assets and other, net	0	0
Equity in losses from consolidated subsidiaries	222,811	(24,893)
Deferred income taxes	0	0
Total (gains) losses	0	0
Derivatives activities:
Cash settlements	0	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	21,921	0
(Increase) decrease in accounts receivable – affiliates	17,082	10,513
Increase in other assets	0	0
Increase (decrease) in accounts payable and accrued expenses	(290)	30
Increase (decrease) in accounts payable and accrued expenses – affiliates	0	0
Increase in other liabilities	42,695	53,698
Net cash provided by operating activities	(35,123)	(40,198)
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	0	0
Development of oil and natural gas properties	0	0
Purchases of other property and equipment	0	0
Investment in affiliates	43,778
Change in notes receivable with affiliate	(16,400)	(9,200)
Proceeds from sale of properties and equipment and other	(1,121)	(11,230)
Net cash used in investing activities	26,257	(20,430)
Cash flow from financing activities:
Proceeds from sale of units	15,900
Proceeds from borrowings	395,000	540,000
Repayments of debt	(280,287)	(240,000)
Distributions to unitholders	(104,815)	(240,073)
Financing fees and offering costs	(453)	(81)
Change in notes payable with affiliate	0	0
Distribution to affiliate	0
Excess tax benefit from unit-based compensation	(8,867)	0
Other	(3,786)	763
Net cash provided by (used in) financing activities	12,692	60,609
Net increase in cash and cash equivalents	3,826	(19)
Cash and cash equivalents:
Beginning	38	52
Ending	3,864	33
Reportable Legal Entities [Member] | Guarantor Subsidiaries
Cash flow from operating activities:
Net loss	36,450	(54,805)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	140,699	199,170
Impairment of long-lived assets	325,417
Unit-based compensation expenses	20,510	21,500
Gain on extinguishment of debt	0
Amortization and write-off of deferred financing fees	0	0
(Gains) losses on sale of assets and other, net	(5,243)	1,327
Equity in losses from consolidated subsidiaries	0	0
Deferred income taxes	(7,108)	5,615
Total (gains) losses	421,514	(244,958)
Derivatives activities:
Cash settlements	254,569	(11,856)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	96,917	(18,964)
(Increase) decrease in accounts receivable – affiliates	(19,856)	16,950
Increase in other assets	(8,521)	(3,136)
Increase (decrease) in accounts payable and accrued expenses	(3,844)	20,252
Increase (decrease) in accounts payable and accrued expenses – affiliates	(17,082)	(10,513)
Increase in other liabilities	(24,057)	(30,648)
Net cash provided by operating activities	367,337	379,850
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	0	(25,345)
Development of oil and natural gas properties	(263,209)	(260,093)
Purchases of other property and equipment	(11,309)	(8,318)
Investment in affiliates	0
Change in notes receivable with affiliate	0	0
Proceeds from sale of properties and equipment and other	24,808	544
Net cash used in investing activities	(249,710)	(293,212)
Cash flow from financing activities:
Proceeds from sale of units	0
Proceeds from borrowings	0	0
Repayments of debt	0	0
Distributions to unitholders	0	0
Financing fees and offering costs	0	0
Change in notes payable with affiliate	16,400	9,200
Distribution to affiliate	0
Excess tax benefit from unit-based compensation	0	1,457
Other	(91,188)	(35,611)
Net cash provided by (used in) financing activities	(74,788)	(24,954)
Net increase in cash and cash equivalents	42,839	61,684
Cash and cash equivalents:
Beginning	185	1,078
Ending	43,024	62,762
Reportable Legal Entities [Member] | Non- Guarantor Subsidiary
Cash flow from operating activities:
Net loss	(322,725)	79,698
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	72,979	68,631
Impairment of long-lived assets	272,000
Unit-based compensation expenses	0	0
Gain on extinguishment of debt	0
Amortization and write-off of deferred financing fees	259	(3,478)
(Gains) losses on sale of assets and other, net	(1,857)	0
Equity in losses from consolidated subsidiaries	0	0
Deferred income taxes	(50)	(31)
Total (gains) losses	2,341	3,465
Derivatives activities:
Cash settlements	27,513	(2,655)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	16,392	(15,373)
(Increase) decrease in accounts receivable – affiliates	0	0
Increase in other assets	(3,878)	(1,040)
Increase (decrease) in accounts payable and accrued expenses	(25,734)	(4,177)
Increase (decrease) in accounts payable and accrued expenses – affiliates	19,856	(16,950)
Increase in other liabilities	(9,925)	(6,330)
Net cash provided by operating activities	42,489	94,830
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	0	0
Development of oil and natural gas properties	(1,609)	(134,750)
Purchases of other property and equipment	(1,092)	(1,833)
Investment in affiliates	0
Change in notes receivable with affiliate	0	0
Proceeds from sale of properties and equipment and other	3,813	0
Net cash used in investing activities	1,112	(136,583)
Cash flow from financing activities:
Proceeds from sale of units	0
Proceeds from borrowings	0	0
Repayments of debt	0	(1,188)
Distributions to unitholders	0	0
Financing fees and offering costs	0	(2,581)
Change in notes payable with affiliate	0	0
Distribution to affiliate	(43,778)
Excess tax benefit from unit-based compensation	0	0
Other	15	0
Net cash provided by (used in) financing activities	(43,763)	(3,769)
Net increase in cash and cash equivalents	(162)	(45,522)
Cash and cash equivalents:
Beginning	1,586	51,041
Ending	1,424	5,519
Eliminations
Cash flow from operating activities:
Net loss	286,275	(24,893)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	1,336	0
Impairment of long-lived assets	(64,800)
Unit-based compensation expenses	0	0
Gain on extinguishment of debt	0
Amortization and write-off of deferred financing fees	0	0
(Gains) losses on sale of assets and other, net	0	0
Equity in losses from consolidated subsidiaries	(222,811)	24,893
Deferred income taxes	0	0
Total (gains) losses	0	0
Derivatives activities:
Cash settlements	0	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	0	0
(Increase) decrease in accounts receivable – affiliates	2,774	(27,463)
Increase in other assets	0	0
Increase (decrease) in accounts payable and accrued expenses	0	0
Increase (decrease) in accounts payable and accrued expenses – affiliates	(2,774)	27,463
Increase in other liabilities	0	0
Net cash provided by operating activities	0	0
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	0	0
Development of oil and natural gas properties	0	0
Purchases of other property and equipment	0	0
Investment in affiliates	(43,778)
Change in notes receivable with affiliate	16,400	9,200
Proceeds from sale of properties and equipment and other	0	0
Net cash used in investing activities	(27,378)	9,200
Cash flow from financing activities:
Proceeds from sale of units	0
Proceeds from borrowings	0	0
Repayments of debt	0	0
Distributions to unitholders	0	0
Financing fees and offering costs	0	0
Change in notes payable with affiliate	(16,400)	(9,200)
Distribution to affiliate	43,778
Excess tax benefit from unit-based compensation	0	0
Other	0	0
Net cash provided by (used in) financing activities	27,378	(9,200)
Net increase in cash and cash equivalents	0	0
Cash and cash equivalents:
Beginning	0	0
Ending	$ 0	$ 0

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Derivatives (Commodity Derivatives) (Details)	Mar. 31, 2015 MMMBTU
2015 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	88,935
Average Price (in usd per energy unit)	5.19
2015 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	54,137
Average Price (in usd per energy unit)	5.00
2015 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	9,426	[1]
Average Price (in usd per energy unit)	93.33	[1]
2015 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	2,581
Average Price (in usd per energy unit)	90.00
2015 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	825
2015 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	65,670	[2],[3]
Hedged Differential (in usd per energy unit)	(0.33)	[2],[3]
2015 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	43,707	[2],[3]
Hedged Differential (in usd per energy unit)	(0.23)	[2],[3]
2015 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	7,040	[2],[3]
Hedged Differential (in usd per energy unit)	0.06	[2],[3]
2015 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	19,351	[2],[3]
Hedged Differential (in usd per energy unit)	(0.03)	[2],[3]
2015 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	3,823	[2],[3]
Hedged Differential (in usd per energy unit)	(0.21)	[2],[3]
2015 | Natural Gas Basis Differential Positions | SoCal basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	22,050	[3],[4]
Hedged Differential (in usd per energy unit)	(0.03)	[3],[4]
2015 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	5,463	[5]
Hedged Differential (in usd per energy unit)	0.24	[5]
2016 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	121,841
Average Price (in usd per energy unit)	4.20
2016 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	76,269
Average Price (in usd per energy unit)	5.00
2016 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	11,465	[1]
Average Price (in usd per energy unit)	90.56	[1]
2016 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	3,271
Average Price (in usd per energy unit)	90.00
2016 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0
2016 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	59,954	[2],[3]
Hedged Differential (in usd per energy unit)	(0.32)	[2],[3]
2016 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	65,794	[2],[3]
Hedged Differential (in usd per energy unit)	(0.24)	[2],[3]
2016 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	7,768	[2],[3]
Hedged Differential (in usd per energy unit)	0.05	[2],[3]
2016 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	34,364	[2],[3]
Hedged Differential (in usd per energy unit)	(0.02)	[2],[3]
2016 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	4,219	[2],[3]
Hedged Differential (in usd per energy unit)	(0.20)	[2],[3]
2016 | Natural Gas Basis Differential Positions | SoCal basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	32,940	[3],[4]
Hedged Differential (in usd per energy unit)	(0.03)	[3],[4]
2016 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	7,446	[5]
Hedged Differential (in usd per energy unit)	0.25	[5]
2017 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	120,122
Average Price (in usd per energy unit)	4.26
2017 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	66,886
Average Price (in usd per energy unit)	4.88
2017 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	4,755	[1]
Average Price (in usd per energy unit)	89.02	[1]
2017 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	384
Average Price (in usd per energy unit)	90.00
2017 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0
2017 | Oil Derivative Instruments | Extendible Fixed Price Swaps
Derivative [Line Items]
Average Price (in usd per energy unit)	100.00
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384
2017 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	59,138	[2],[3]
Hedged Differential (in usd per energy unit)	(0.33)	[2],[3]
2017 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	38,880	[2],[3]
Hedged Differential (in usd per energy unit)	(0.19)	[2],[3]
2017 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	7,437	[2],[3]
Hedged Differential (in usd per energy unit)	0.05	[2],[3]
2017 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	36,730	[2],[3]
Hedged Differential (in usd per energy unit)	(0.02)	[2],[3]
2017 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	4,819	[2],[3]
Hedged Differential (in usd per energy unit)	(0.20)	[2],[3]
2017 | Natural Gas Basis Differential Positions | SoCal basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[3],[4]
Hedged Differential (in usd per energy unit)	0.00	[3],[4]
2017 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	6,486	[5]
Hedged Differential (in usd per energy unit)	0.25	[5]
2018 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	36,500
Average Price (in usd per energy unit)	5.00
2018 | Natural Gas Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	0
Average Price (in usd per energy unit)	0.00
2018 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[1]
Average Price (in usd per energy unit)	0.00	[1]
2018 | Oil Derivative Instruments | Puts
Derivative [Line Items]
Hedged Volume (in energy unit)	0
Average Price (in usd per energy unit)	0.00
2018 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0
2018 | Oil Derivative Instruments | Extendible Fixed Price Swaps
Derivative [Line Items]
Average Price (in usd per energy unit)	100.00
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384
2018 | Natural Gas Basis Differential Positions | Panhandle Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	16,425	[2],[3]
Hedged Differential (in usd per energy unit)	(0.33)	[2],[3]
2018 | Natural Gas Basis Differential Positions | NWPL - Rockies basis swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	10,804	[2],[3]
Hedged Differential (in usd per energy unit)	(0.19)	[2],[3]
2018 | Natural Gas Basis Differential Positions | MichCon Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	2,044	[2],[3]
Hedged Differential (in usd per energy unit)	0.05	[2],[3]
2018 | Natural Gas Basis Differential Positions | Houston Ship Channel Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	986	[2],[3]
Hedged Differential (in usd per energy unit)	(0.08)	[2],[3]
2018 | Natural Gas Basis Differential Positions | Permian Basis Swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	1,314	[2],[3]
Hedged Differential (in usd per energy unit)	(0.20)	[2],[3]
2018 | Natural Gas Basis Differential Positions | SoCal basis swaps [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[3],[4]
Hedged Differential (in usd per energy unit)	0.00	[3],[4]
2018 | Oil Timing Differential Positions | Trade month roll swaps
Derivative [Line Items]
Hedged Volume (in energy unit)	0	[5]
Hedged Differential (in usd per energy unit)	0.00	[5]
2019 | Oil Derivative Instruments | Extendible Fixed Price Swaps
Derivative [Line Items]
Average Price (in usd per energy unit)	90.00
Amount of outstanding extendible fixed price oil swaps of daily production (in MBbls)	5,384
Short [Member] | 2015 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	70.00
Derivative, Cap Price	101.62
Short [Member] | 2016 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00
Derivative, Cap Price	0.00
Short [Member] | 2017 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00
Derivative, Cap Price	0.00
Short [Member] | 2018 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00
Derivative, Cap Price	0.00
Long [Member] | 2015 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	90.00
Long [Member] | 2016 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00
Long [Member] | 2017 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00
Long [Member] | 2018 | Oil Derivative Instruments | Crude Oil Sales - Three-way collars - Derivative 1 [Member]
Derivative [Line Items]
Derivative, Floor Price	0.00

[1] Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, at counterparty election on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

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

[3] Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.

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

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

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations Reconciliation

The following presents a reconciliation of the Company’s asset retirement obligations (in thousands):

Asset retirement obligations at December 31, 2014	$	497,570
Liabilities added from drilling	1,390
Current year accretion expense	7,399
Settlements	(1,783		)
Revision of estimates	(1,345		)
Asset retirement obligations at March 31, 2015	$	503,231

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Earnings Per Unit (Tables)

3 Months Ended

Mar. 31, 2015

Earnings Per Share [Abstract]

Reconciliation of numerators and denominators of the basic and diluted per unit computations for net income (loss)

The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net loss:

	Three Months Ended March 31,
	2015			2014
	(in thousands, except per unit data)
Net loss	$	(339,160	)	$	(85,337	)
Allocated to participating securities	(1,781		)	(2,199		)
	$	(340,941	)	$	(87,536	)
Basic net loss per unit	$	(1.03	)	$	(0.27	)
Diluted net loss per unit	$	(1.03	)	$	(0.27	)
Basic weighted average units outstanding	330,642			328,329
Dilutive effect of unit equivalents	—			—
Diluted weighted average units outstanding	330,642			328,329

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Basis of Presentation

3 Months Ended

Mar. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

Nature of Business

Linn Energy, LLC (“LINN Energy” or the “Company”) is an independent oil and natural gas company. LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. The Company’s properties are located in eight operating regions in the United States (“U.S.”), in the Rockies, the Hugoton Basin, California, the Mid-Continent, the Permian Basin, TexLa, South Texas and Michigan/Illinois.

Principles of Consolidation and Reporting

The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.

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

Use of Estimates

The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“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 is currently evaluating the impact of the adoption of this ASU on its condensed consolidated financial statements and 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, 2016, and interim periods within those years (early adoption prohibited). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its condensed consolidated financial statements and related disclosures.

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Tables)

3 Months Ended

Mar. 31, 2015

Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]

Other Accrued Liabilities

“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:

	March 31, 2015		December 31, 2014
	(in thousands)
Accrued interest	$	143,088	$	105,310
Accrued compensation	22,854		44,875
Asset retirement obligations	16,187		16,187
Other	2,301		1,364
	$	184,430	$	167,736

Supplemental Disclosures to the Condensed Conslidated Statements of Cash Flow

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

	Three Months Ended March 31,
	2015		2014
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	98,541	$	77,512
Cash payments for income taxes	$	57	$	—
Noncash investing activities:
Accrued capital expenditures	$	161,247	$	338,323

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Unit-Based Compensation (Compensation Expenses) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Unit-based compensation expense	$ 20,510	$ 21,500
Income tax benefit	7,579	7,944
General and administrative expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Unit-based compensation expense	16,633	18,223
Lease operating expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Unit-based compensation expense	$ 3,877	$ 3,277

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Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Related Party Transaction [Line Items]
General and administrative expenses	$ 78,968	$ 79,228
Distributions to unitholders	104,815	240,073
LinnCo [Member]
Related Party Transaction [Line Items]
Ownership percentage	39.00%
General and administrative expenses	1,400	734
Related party transaction, amounts of transaction	491	470
Director [Member]
Related Party Transaction [Line Items]
Related party transaction, amounts of transaction	3,000	4,000
FY 2014 [Member] | LinnCo [Member]
Related Party Transaction [Line Items]
General and administrative expenses paid on behalf of LinnCo	1,100	83
FY 2013 [Member] | LinnCo [Member]
Related Party Transaction [Line Items]
General and administrative expenses paid on behalf of LinnCo		11,000
Dividend Paid [Member] | LinnCo [Member]
Related Party Transaction [Line Items]
Distributions to unitholders	$ 40,000	$ 93,000

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 48,312	$ 1,809
Accounts receivable – trade, net	340,838	471,684
Derivative instruments	1,119,332	1,077,142
Other current assets	147,969	155,955
Total current assets	1,656,451	1,706,590
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	18,246,897	18,068,900
Less accumulated depletion and amortization	(5,592,674)	(4,867,682)
Oil and natural gas properties, successful efforts method, net	12,654,223	13,201,218
Other property and equipment	682,772	669,149
Less accumulated depreciation	(158,409)	(144,282)
Other property and equipment, net	524,363	524,867
Derivative instruments	949,879	848,097
Other noncurrent assets	135,259	142,737
Noncurrent assets, excluding property, total	1,085,138	990,834
Total noncurrent assets	14,263,724	14,716,919
Total assets	15,920,175	16,423,509
Current liabilities:
Accounts payable and accrued expenses	608,926	814,809
Derivative instruments	899	0
Other accrued liabilities	184,430	167,736
Total current liabilities	794,255	982,545
Noncurrent liabilities:
Credit facilities	3,148,175	2,968,175
Term loan	500,000	500,000
Senior notes, net	6,750,313	6,827,634
Derivative instruments	1,999	684
Other noncurrent liabilities	598,930	600,866
Total noncurrent liabilities	10,999,417	10,897,359
Commitments and contingencies (Note 10)
Unitholders’ capital:
336,887,489 units and 331,974,913 units issued and outstanding at March 31, 2015, and December 31, 2014, respectively	5,317,869	5,395,811
Accumulated deficit	(1,191,366)	(852,206)
Total unitholders' capital	4,126,503	4,543,605
Total liabilities and unitholders’ capital	$ 15,920,175	$ 16,423,509

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Derivatives (Balance Sheet Presentation) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 2,106,710
Assets:
Commodity derivatives	2,106,710	2,014,815
Liabilities:
Commodity derivatives	$ 40,397	$ 90,260

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CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Statement of Stockholders' Equity [Abstract]
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$ 594

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Acquisitions and Joint-Venture Funding Pro Forma Financial Information (Details) (Business Acquisition Devon [Member] [Member], USD $)	3 Months Ended
	Mar. 31, 2014	Jun. 27, 2014
Business Acquisition Devon [Member] [Member]
Business Acquisition, Pro Forma Information [Abstract]
Total revenues and other	$ 879,115,000
Total operating expenses	765,491,000
Net loss	(62,305,000)
Net loss per unit:
Basic	$ (0.20)
Diluted	$ (0.20)
Property, Plant and Equipment, Useful Life	10 years
Business acquisition interim financing		$ 2,300,000,000

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Subsidiary Guarantors

3 Months Ended

Mar. 31, 2015

Condensed Consolidating Financial Information [Abstract]

Subsidiary Guarantors

Subsidiary Guarantors

LINN Energy, LLC’s May 2019 senior notes, November 2019 senior notes, April 2020 senior notes, February 2021 senior notes and September 2021 senior notes are guaranteed by all of the Company’s material subsidiaries, other than Berry Petroleum Company, LLC, which is an indirect 100% wholly owned subsidiary of the Company.

The following condensed consolidating financial information presents the financial information of LINN Energy, LLC, the guarantor subsidiaries and the non-guarantor subsidiary in accordance with SEC Regulation S-X Rule 3‑10. The condensed consolidating financial information for the co-issuer, Linn Energy Finance Corp., is not presented as it has no assets, operations or cash flows. The financial information may not necessarily be indicative of the financial position or results of operations had the guarantor subsidiaries or non-guarantor subsidiary operated as independent entities. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.

CONDENSED CONSOLIDATING BALANCE SHEETS

March 31, 2015

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	3,864		$	43,024		$	1,424		$	—		$	48,312
Accounts receivable – trade, net	—			251,957			88,881			—			340,838
Accounts receivable – affiliates	4,011,808			33,061			—			(4,044,869		)	—
Derivative instruments	—			1,099,777			19,555			—			1,119,332
Other current assets	18			94,722			53,229			—			147,969
Total current assets	4,015,690			1,522,541			163,089			(4,044,869		)	1,656,451
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	—			13,318,736			4,928,161			—			18,246,897
Less accumulated depletion and amortization	—			(4,790,872		)	(865,266		)	63,464			(5,592,674		)
	—			8,527,864			4,062,895			63,464			12,654,223
Other property and equipment	—			564,928			117,844			—			682,772
Less accumulated depreciation	—			(147,307		)	(11,102		)	—			(158,409		)
	—			417,621			106,742			—			524,363
Derivative instruments	—			949,798			81			—			949,879
Notes receivable – affiliates	146,900			—			—			(146,900		)	—
Advance to affiliate	—			—			220,571			(220,571		)	—
Investments in consolidated subsidiaries	8,296,020			—			—			(8,296,020		)	—
Other noncurrent assets, net	110,256			11,660			13,343			—			135,259
	8,553,176			961,458			233,995			(8,663,491		)	1,085,138
Total noncurrent assets	8,553,176			9,906,943			4,403,632			(8,600,027		)	14,263,724
Total assets	$	12,568,866		$	11,429,484		$	4,566,721		$	(12,644,896	)	$	15,920,175
LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	5,150		$	422,042		$	181,734		$	—		$	608,926
Accounts payable – affiliates	—			4,011,808			33,061			(4,044,869		)	—
Advance from affiliate	—			220,571			—			(220,571		)	—
Derivative instruments	—			—			899			—			899
Other accrued liabilities	132,202			37,872			14,356			—			184,430
Total current liabilities	137,352			4,692,293			230,050			(4,265,440		)	794,255
Noncurrent liabilities:
Credit facilities	1,975,000			—			1,173,175			—			3,148,175
Term loan	500,000			—			—			—			500,000
Senior notes, net	5,836,998			—			913,315			—			6,750,313
Notes payable – affiliates	—			146,900			—			(146,900		)	—
Derivative instruments	—			1,770			229			—			1,999
Other noncurrent liabilities	—			401,479			197,451			—			598,930
Total noncurrent liabilities	8,311,998			550,149			2,284,170			(146,900		)	10,999,417
Unitholders’ capital:
Units issued and outstanding	5,310,882			4,831,265			2,372,603			(7,196,881		)	5,317,869
Accumulated income (deficit)	(1,191,366		)	1,355,777			(320,102		)	(1,035,675		)	(1,191,366		)
	4,119,516			6,187,042			2,052,501			(8,232,556		)	4,126,503
Total liabilities and unitholders’ capital	$	12,568,866		$	11,429,484		$	4,566,721		$	(12,644,896	)	$	15,920,175

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2014

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	38		$	185		$	1,586		$	—		$	1,809
Accounts receivable – trade, net	—			371,325			100,359			—			471,684
Accounts receivable – affiliates	4,028,890			13,205			—			(4,042,095		)	—
Derivative instruments	—			1,033,448			43,694			—			1,077,142
Other current assets	18			96,678			59,259			—			155,955
Total current assets	4,028,946			1,514,841			204,898			(4,042,095		)	1,706,590
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	—			13,196,841			4,872,059			—			18,068,900
Less accumulated depletion and amortization	—			(4,342,675		)	(525,007		)	—			(4,867,682		)
	—			8,854,166			4,347,052			—			13,201,218
Other property and equipment	—			553,150			115,999			—			669,149
Less accumulated depreciation	—			(135,830		)	(8,452		)	—			(144,282		)
	—			417,320			107,547			—			524,867
Derivative instruments	—			848,097			—			—			848,097
Notes receivable – affiliates	130,500			—			—			(130,500		)	—
Advance to affiliate	—			—			293,627			(293,627		)	—
Investments in consolidated subsidiaries	8,562,608			—			—			(8,562,608		)	—
Other noncurrent assets, net	116,637			11,816			14,284			—			142,737
	8,809,745			859,913			307,911			(8,986,735		)	990,834
Total noncurrent assets	8,809,745			10,131,399			4,762,510			(8,986,735		)	14,716,919
Total assets	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509
LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	3,784		$	581,880		$	229,145		$	—		$	814,809
Accounts payable – affiliates	—			4,028,890			13,205			(4,042,095		)	—
Advance from affiliate	—			293,627			—			(293,627		)	—
Derivative instruments	—			—			—			—			—
Other accrued liabilities	89,507			59,142			19,087			—			167,736
Total current liabilities	93,291			4,963,539			261,437			(4,335,722		)	982,545
Noncurrent liabilities:
Credit facilities	1,795,000			—			1,173,175			—			2,968,175
Term loan	500,000			—			—			—			500,000
Senior notes, net	5,913,857			—			913,777			—			6,827,634
Notes payable – affiliates	—			130,500			—			(130,500		)	—
Derivative instruments	—			684			—			—			684
Other noncurrent liabilities	—			400,851			200,015			—			600,866
Total noncurrent liabilities	8,208,857			532,035			2,286,967			(130,500		)	10,897,359
Unitholders’ capital:
Units issued and outstanding	5,388,749			4,831,339			2,416,381			(7,240,658		)	5,395,811
Accumulated income (deficit)	(852,206		)	1,319,327			2,623			(1,321,950		)	(852,206		)
	4,536,543			6,150,666			2,419,004			(8,562,608		)	4,543,605
Total liabilities and unitholders’ capital	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2015

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	293,983		$	156,586		$	—		$	450,569
Gains on oil and natural gas derivatives	—			421,514			3,267			—			424,781
Marketing revenues	—			26,212			7,532			—			33,744
Other revenues	—			5,557			1,896			—			7,453
	—			747,266			169,281			—			916,547
Expenses:
Lease operating expenses	—			105,832			67,189			—			173,021
Transportation expenses	—			40,934			12,606			—			53,540
Marketing expenses	—			23,196			5,645			—			28,841
General and administrative expenses	—			57,781			21,187			—			78,968
Exploration costs	—			396			—			—			396
Depreciation, depletion and amortization	—			140,699			72,979			1,336			215,014
Impairment of long-lived assets	—			325,417			272,000			(64,800		)	532,617
Taxes, other than income taxes	2			30,711			23,332			—			54,045
Gains on sale of assets and other, net	—			(7,814		)	(4,473		)	—			(12,287		)
	2			717,152			470,465			(63,464		)	1,124,155
Other income and (expenses):
Interest expense, net of amounts capitalized	(123,386		)	1,706			(21,421		)	—			(143,101		)
Interest expense – affiliates	—			(2,382		)	—			2,382			—
Interest income – affiliates	2,382			—			—			(2,382		)	—
Gain on extinguishment of debt	6,635			—			—			—			6,635
Equity in losses from consolidated subsidiaries	(222,811		)	—			—			222,811			—
Other, net	(1,978		)	(65		)	(170		)	—			(2,213		)
	(339,158		)	(741		)	(21,591		)	222,811			(138,679		)
Income (loss) before income taxes	(339,160		)	29,373			(322,775		)	286,275			(346,287		)
Income tax benefit	—			(7,077		)	(50		)	—			(7,127		)
Net income (loss)	$	(339,160	)	$	36,450		$	(322,725	)	$	286,275		$	(339,160	)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2014

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	605,761		$	333,116		$	—		$	938,877
Gains (losses) on oil and natural gas derivatives	—			(244,958		)	3,465			—			(241,493		)
Marketing revenues	—			15,731			14,815			—			30,546
Other revenues	—			5,673			(16		)	—			5,657
	—			382,207			351,380			—			733,587
Expenses:
Lease operating expenses	—			104,002			90,031			—			194,033
Transportation expenses	—			37,637			7,993			—			45,630
Marketing expenses	—			10,091			10,981			—			21,072
General and administrative expenses	—			35,737			43,491			—			79,228
Exploration costs	—			1,091			—			—			1,091
Depreciation, depletion and amortization	—			199,170			68,631			—			267,801
Taxes, other than income taxes	—			42,684			23,029			—			65,713
(Gains) losses on sale of assets and other, net	—			(781		)	3,367			—			2,586
	—			429,631			247,523			—			677,154
Other income and (expenses):
Interest expense, net of amounts capitalized	(109,650		)	(162		)	(24,001		)	—			(133,813		)
Interest expense – affiliates	—			(1,550		)	—			1,550			—
Interest income – affiliates	1,550			—			—			(1,550		)	—
Equity in earnings from consolidated subsidiaries	24,893			—			—			(24,893		)	—
Other, net	(2,130		)	16			(189		)	—			(2,303		)
	(85,337		)	(1,696		)	(24,190		)	(24,893		)	(136,116		)
Income (loss) before income taxes	(85,337		)	(49,120		)	79,667			(24,893		)	(79,683		)
Income tax expense (benefit)	—			5,685			(31		)	—			5,654
Net income (loss)	$	(85,337	)	$	(54,805	)	$	79,698		$	(24,893	)	$	(85,337	)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2015

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(339,160	)	$	36,450		$	(322,725	)	$	286,275		$	(339,160	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			140,699			72,979			1,336			215,014
Impairment of long-lived assets	—			325,417			272,000			(64,800		)	532,617
Unit-based compensation expenses	—			20,510			—			—			20,510
Gain on extinguishment of debt	(6,635		)	—			—			—			(6,635		)
Amortization and write-off of deferred financing fees	6,453			—			259			—			6,712
Gains on sale of assets and other, net	—			(5,243		)	(1,857		)	—			(7,100		)
Equity in losses from consolidated subsidiaries	222,811			—			—			(222,811		)	—
Deferred income taxes	—			(7,108		)	(50		)	—			(7,158		)
Derivatives activities:
Total gains	—			(421,514		)	(2,341		)	—			(423,855		)
Cash settlements	—			254,569			27,513			—			282,082
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net	21,921			96,917			16,392			—			135,230
(Increase) decrease in accounts receivable – affiliates	17,082			(19,856		)	—			2,774			—
Increase in other assets	—			(8,521		)	(3,878		)	—			(12,399		)
Decrease in accounts payable and accrued expenses	(290		)	(3,844		)	(25,734		)	—			(29,868		)
Increase (decrease) in accounts payable and accrued expenses – affiliates	—			(17,082		)	19,856			(2,774		)	—
Increase (decrease) in other liabilities	42,695			(24,057		)	(9,925		)	—			8,713
Net cash provided by (used in) operating activities	(35,123		)	367,337			42,489			—			374,703
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			—			—			—			—
Development of oil and natural gas properties	—			(263,209		)	(1,609		)	—			(264,818		)
Purchases of other property and equipment	—			(11,309		)	(1,092		)	—			(12,401		)
Investment in affiliates	43,778			—			—			(43,778		)	—
Change in notes receivable with affiliate	(16,400		)	—			—			16,400			—
Proceeds from sale of properties and equipment and other	(1,121		)	24,808			3,813			—			27,500
Net cash provided by (used in) investing activities	26,257			(249,710		)	1,112			(27,378		)	(249,719		)

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from financing activities:
Proceeds from sale of units	15,900			—			—			—			15,900
Proceeds from borrowings	395,000			—			—			—			395,000
Repayments of debt	(280,287		)	—			—			—			(280,287		)
Distributions to unitholders	(104,815		)	—			—			—			(104,815		)
Financing fees and offering costs	(453		)	—			—			—			(453		)
Change in notes payable with affiliate	—			16,400			—			(16,400		)	—
Distribution to affiliate	—			—			(43,778		)	43,778			—
Excess tax benefit from unit-based compensation	(8,867		)	—			—			—			(8,867		)
Other	(3,786		)	(91,188		)	15			—			(94,959		)
Net cash provided by (used in) financing activities	12,692			(74,788		)	(43,763		)	27,378			(78,481		)
Net increase (decrease) in cash and cash equivalents	3,826			42,839			(162		)	—			46,503
Cash and cash equivalents:
Beginning	38			185			1,586			—			1,809
Ending	$	3,864		$	43,024		$	1,424		$	—		$	48,312

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2014

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(85,337	)	$	(54,805	)	$	79,698		$	(24,893	)	$	(85,337	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			199,170			68,631			—			267,801
Unit-based compensation expenses	—			21,500			—			—			21,500
Amortization and write-off of deferred financing fees	5,791			—			(3,478		)	—			2,313
Losses on sale of assets and other, net	—			1,327			—			—			1,327
Equity in earnings from consolidated subsidiaries	(24,893		)	—			—			24,893			—
Deferred income taxes	—			5,615			(31		)	—			5,584
Derivatives activities:
Total (gains) losses	—			244,958			(3,465		)	—			241,493
Cash settlements	—			(11,856		)	(2,655		)	—			(14,511		)
Changes in assets and liabilities:
Increase in accounts receivable – trade, net	—			(18,964		)	(15,373		)	—			(34,337		)
Decrease in accounts receivable – affiliates	10,513			16,950			—			(27,463		)	—
Increase in other assets	—			(3,136		)	(1,040		)	—			(4,176		)
Increase (decrease) in accounts payable and accrued expenses	30			20,252			(4,177		)	—			16,105
Decrease in accounts payable and accrued expenses – affiliates	—			(10,513		)	(16,950		)	27,463			—
Increase (decrease) in other liabilities	53,698			(30,648		)	(6,330		)	—			16,720
Net cash provided by (used in) operating activities	(40,198		)	379,850			94,830			—			434,482
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			(25,345		)	—			—			(25,345		)
Development of oil and natural gas properties	—			(260,093		)	(134,750		)	—			(394,843		)
Purchases of other property and equipment	—			(8,318		)	(1,833		)	—			(10,151		)
Change in notes receivable with affiliate	(9,200		)	—			—			9,200			—
Proceeds from sale of properties and equipment and other	(11,230		)	544			—			—			(10,686		)
Net cash used in investing activities	(20,430		)	(293,212		)	(136,583		)	9,200			(441,025		)

	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from financing activities:
Proceeds from borrowings	540,000			—			—			—			540,000
Repayments of debt	(240,000		)	—			(1,188		)	—			(241,188		)
Distributions to unitholders	(240,073		)	—			—			—			(240,073		)
Financing fees and offering costs	(81		)	—			(2,581		)	—			(2,662		)
Change in notes payable with affiliate	—			9,200			—			(9,200		)	—
Excess tax benefit from unit-based compensation	—			1,457			—			—			1,457
Other	763			(35,611		)	—			—			(34,848		)
Net cash provided by (used in) financing activities	60,609			(24,954		)	(3,769		)	(9,200		)	22,686
Net increase (decrease) in cash and cash equivalents	(19		)	61,684			(45,522		)	—			16,143
Cash and cash equivalents:
Beginning	52			1,078			51,041			—			52,171
Ending	$	33		$	62,762		$	5,519		$	—		$	68,314

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Unitholders' Capital (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		1 Months Ended			3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Jun. 30, 2015	May 31, 2015	Apr. 30, 2015	Jun. 30, 2015
Subsequent Event [Line Items]
Per unit cash dividend declared (in usd per unit)	$ 0.313	$ 0.725
Distributions to unitholders	$ 104,815	$ 240,073
Dividend Declared [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Per unit cash dividend declared (in usd per unit)			$ 0.1042	$ 0.1042	$ 0.1042	$ 0.3125
Dividend Paid [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Distributions to unitholders					$ 35,000

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Acquisitions and Joint-Venture Funding (Tables)

3 Months Ended

Mar. 31, 2015

Business Combinations [Abstract]

Schedule of Pro Forma Results of Business Combination

	Three Months Ended March 31, 2014
	(in thousands, except per unit amounts)
Total revenues and other	$	879,115
Total operating expenses	$	765,491
Net loss	$	(62,305	)
Net loss per unit:
Basic	$	(0.20	)
Diluted	$	(0.20	)

The pro forma condensed combined statement of operations includes adjustments to:

• Reflect the results of the Devon Assets Acquisition.

• Reflect incremental depreciation, depletion and amortization expense, using the unit-of-production method related to oil and natural gas properties acquired and an estimated useful life of 10 years for other property and equipment.

• Reflect incremental accretion expense related to asset retirement obligations on oil and natural gas properties acquired.

• Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price.

• Reflect incremental amortization of deferred financing fees associated with debt incurred to fund the purchase price.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Cash flow from operating activities:
Net loss	$ (339,160)	$ (85,337)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	215,014	267,801
Impairment of long-lived assets	532,617	0
Unit-based compensation expenses	20,510	21,500
Gain on extinguishment of debt	(6,635)	0
Amortization and write-off of deferred financing fees	6,712	2,313
(Gains) losses on sale of assets and other, net	(7,100)	1,327
Deferred income taxes	(7,158)	5,584
Derivatives activities:
Total (gains) losses	423,855	(241,493)
Cash settlements	282,082	(14,511)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	135,230	(34,337)
Increase in other assets	(12,399)	(4,176)
Increase (decrease) in accounts payable and accrued expenses	(29,868)	16,105
Increase in other liabilities	8,713	16,720
Net cash provided by operating activities	374,703	434,482
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	0	(25,345)
Development of oil and natural gas properties	(264,818)	(394,843)
Purchases of other property and equipment	(12,401)	(10,151)
Proceeds from sale of properties and equipment and other	27,500	(10,686)
Net cash used in investing activities	(249,719)	(441,025)
Cash flow from financing activities:
Proceeds from sale of units	15,900	0
Proceeds from borrowings	395,000	540,000
Repayments of debt	(280,287)	(241,188)
Distributions to unitholders	(104,815)	(240,073)
Financing fees and offering costs	(453)	(2,662)
Excess tax benefit from unit-based compensation	(8,867)	1,457
Other	(94,959)	(34,848)
Net cash provided by (used in) financing activities	(78,481)	22,686
Net increase in cash and cash equivalents	46,503	16,143
Cash and cash equivalents:
Beginning	1,809	52,171
Ending	$ 48,312	$ 68,314

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical)	Mar. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Unitholders' capital: Units issued	336,887,489	331,974,913
Unitholders' capital: Units outstanding	336,887,489	331,974,913

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. With respect to a certain statewide class action case, the Company’s motion to dismiss was denied by the Court, and the parties have agreed on a scheduling order, which provides for briefing on the class certification issues in late 2015 and the first part of 2016. The Company has denied that it has liability on the claims asserted in the case and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. For another statewide class action royalty payment dispute, briefing on class certification issues is expected to be completed during the summer of 2015. The Company has denied that it has any liability on the claims and has denied that class certification is proper. If the Court accepts the Company’s arguments, there will be no liability to the Company in the case. The Company is unable to estimate a possible loss, or range of possible loss, if any, in these cases. In addition, the Company is involved in various other disputes arising in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

During the three months ended March 31, 2015, and March 31, 2014, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

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Document And Entity Information	3 Months Ended
	Mar. 31, 2015
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Mar. 31, 2015
Amendment Flag	false
Entity Registrant Name	Linn Energy, LLC
Entity Central Index Key	0001326428
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	336,887,489
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1

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Earnings Per Unit

3 Months Ended

Mar. 31, 2015

Earnings Per Share [Abstract]

Earnings Per Unit

Earnings Per Unit

Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect.

The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net loss:

	Three Months Ended March 31,
	2015			2014
	(in thousands, except per unit data)
Net loss	$	(339,160	)	$	(85,337	)
Allocated to participating securities	(1,781		)	(2,199		)
	$	(340,941	)	$	(87,536	)
Basic net loss per unit	$	(1.03	)	$	(0.27	)
Diluted net loss per unit	$	(1.03	)	$	(0.27	)
Basic weighted average units outstanding	330,642			328,329
Dilutive effect of unit equivalents	—			—
Diluted weighted average units outstanding	330,642			328,329

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 5 million and 6 million unit options and warrants for the three months ended March 31, 2015, and March 31, 2014, respectively. All equivalent units were antidilutive for both the three months ended March 31, 2015, and March 31, 2014.

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Revenues and other:
Oil, natural gas and natural gas liquids sales	$ 450,569	$ 938,877
Gains (losses) on oil and natural gas derivatives	424,781	(241,493)
Marketing revenues	33,744	30,546
Other revenues	7,453	5,657
Total revenues	916,547	733,587
Expenses:
Lease operating expenses	173,021	194,033
Transportation expenses	53,540	45,630
Marketing expenses	28,841	21,072
General and administrative expenses	78,968	79,228
Exploration costs	396	1,091
Depreciation, depletion and amortization	215,014	267,801
Impairment of long-lived assets	532,617	0
Taxes, other than income taxes	54,045	65,713
(Gains) losses on sale of assets and other, net	(12,287)	2,586
Total expenses	1,124,155	677,154
Other income and (expenses):
Interest expense, net of amounts capitalized	(143,101)	(133,813)
Gain on extinguishment of debt	6,635	0
Other, net	(2,213)	(2,303)
Total other income and (expenses)	(138,679)	(136,116)
Loss before income taxes	(346,287)	(79,683)
Income tax expense (benefit)	(7,127)	5,654
Net loss	$ (339,160)	$ (85,337)
Net loss per unit:
Basic (in usd per unit)	$ (1.03)	$ (0.27)
Diluted (in usd per unit)	$ (1.03)	$ (0.27)
Weighted average units outstanding:
Basic (in units)	330,642	328,329
Diluted (in units)	330,642	328,329
Distributions declared per unit	$ 0.313	$ 0.725

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Unit-Based Compensation

3 Months Ended

Mar. 31, 2015

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

Unit-Based Compensation

Unit-Based Compensation

During the three months ended March 31, 2015, the Company granted 3,468,245 restricted units and 697,120 phantom units to employees, primarily as part of its annual review of its employees’ compensation, including executives, with an aggregate fair value of approximately $42 million. The restricted units and phantom units vest over three years. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:

	Three Months Ended March 31,
	2015		2014
	(in thousands)
General and administrative expenses	$	16,633	$	18,223
Lease operating expenses	3,877		3,277
Total unit-based compensation expenses	$	20,510	$	21,500
Income tax benefit	$	7,579	$	7,944

Cash-Based Performance Unit Awards

The Company also granted 567,320 performance units (the maximum number of units available to be earned) to certain executive officers. The 2015 performance unit awards vest three years from the award date. The vesting of these units is determined based on the Company’s performance compared to the performance of a predetermined group of peer companies over a specified performance period, and the value of vested units is to be paid in cash. To date, no performance units have vested and no amounts have been paid to settle any such awards. Performance unit awards that are settled in cash are recorded as a liability with the changes in fair value recognized over the vesting period. For the three months ended March 31, 2015, the Company recognized expense for cash-based performance unit awards of approximately $266,000, included in “general and administrative expenses” on the condensed consolidated statement of operations. At March 31, 2015, the Company’s liability related to these performance unit awards was also approximately $266,000.

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Oil and Natural Gas Properties

3 Months Ended

Mar. 31, 2015

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Oil and Natural Gas Properties

Oil and Natural Gas Properties

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:

	March 31, 2015			December 31, 2014
	(in thousands)
Proved properties:
Leasehold acquisition	$	13,368,818		$	13,362,642
Development	3,012,467			2,830,841
Unproved properties	1,865,612			1,875,417
	18,246,897			18,068,900
Less accumulated depletion and amortization	(5,592,674		)	(4,867,682		)
	$	12,654,223		$	13,201,218

Impairment of Proved Properties

The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

Based on the analysis described above, for the three months ended March 31, 2015, the Company recorded noncash impairment charges, before and after tax, of approximately $533 million associated with proved oil and natural gas properties. The impairment was due to a decline in commodity prices. 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 condensed consolidated statement of operations. Following are the impairment charges recorded:

• Shallow Texas Panhandle Brown Dolomite formation – $278 million;

• California region – $207 million;

• TexLa region – $33 million;

• South Texas region – $9 million; and

• Mid-Continent region – $6 million.

The Company recorded no impairment charges for the three months ended March 31, 2014.

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Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Principles of Consolidation and Reporting

Principles of Consolidation and Reporting

The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.

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

Use of Estimates

Use of Estimates

The preparation of the accompanying condensed consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“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 is currently evaluating the impact of the adoption of this ASU on its condensed consolidated financial statements and 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, 2016, and interim periods within those years (early adoption prohibited). The Company is currently evaluating the impact, if any, of the adoption of this ASU on its condensed consolidated financial statements and related disclosures.

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Income Taxes

3 Months Ended

Mar. 31, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Company is not a taxable entity, it does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Company. Amounts recognized for income taxes are reported in “income tax expense (benefit)” on the condensed consolidated statements of operations.

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Fair Value Measurements on a Recurring Basis

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements on a Recurring Basis

Fair Value Measurements on a Recurring Basis

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

Fair Value Hierarchy

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

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

	March 31, 2015
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	2,106,710	$	(37,499	)	$	2,069,211
Liabilities:
Commodity derivatives	$	40,397	$	(37,499	)	$	2,898

	December 31, 2014
	Level 2		Netting (1)			Total
	(in thousands)
Assets:
Commodity derivatives	$	2,014,815	$	(89,576	)	$	1,925,239
Liabilities:
Commodity derivatives	$	90,260	$	(89,576	)	$	684

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

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Debt

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Debt

Debt

The following summarizes the Company’s outstanding debt:

	March 31, 2015			December 31, 2014
	(in thousands, except percentages)
LINN credit facility (1)	$	1,975,000		$	1,795,000
Berry credit facility (2)	1,173,175			1,173,175
Term loan (3)	500,000			500,000
6.50% senior notes due May 2019	1,200,000			1,200,000
6.25% senior notes due November 2019	1,800,000			1,800,000
8.625% senior notes due April 2020	1,220,800			1,300,000
6.75% Berry senior notes due November 2020	299,970			299,970
7.75% senior notes due February 2021	1,000,000			1,000,000
6.50% senior notes due September 2021	650,000			650,000
6.375% Berry senior notes due September 2022	599,163			599,163
Net unamortized discounts and premiums	(19,620		)	(21,499		)
Total debt, net	10,398,488			10,295,809
Less current maturities	—			—
Total long-term debt, net	$	10,398,488		$	10,295,809

⁽¹⁾  Variable interest rates of 1.93% and 1.92% at March 31, 2015, and December 31, 2014, respectively.

⁽²⁾  Variable interest rates of 2.68% and 2.67% at March 31, 2015, and December 31, 2014, respectively.

⁽³⁾  Variable interest rates of 2.68% and 2.66% at March 31, 2015, and December 31, 2014, respectively.

Fair Value

The Company’s debt is recorded at the carrying amount in the condensed consolidated balance sheets. The carrying amounts of the Company’s credit facilities and term loan approximate fair value because the interest rates are variable and reflective of market rates. The Company uses a market approach to determine the fair value of its senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.

	March 31, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Credit facilities	$	3,148,175	$	3,148,175	$	2,968,175	$	2,968,175
Term loan	500,000		500,000		500,000		500,000
Senior notes, net	6,750,313		5,454,065		6,827,634		5,703,649
Total debt, net	$	10,398,488	$	9,102,240	$	10,295,809	$	9,171,824

Credit Facilities

LINN Credit Facility

The Company’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) provides for (1) a senior secured revolving credit facility and (2) a $500 million senior secured term loan, in aggregate subject to the then-effective borrowing base. Borrowing capacity under the revolving credit facility is limited to the lesser of (i) the then-effective borrowing base reduced by the $500 million term loan and (ii) the maximum commitment amount of $4.0 billion, and is currently $4.0 billion. The maturity date is April 2019. At March 31, 2015, the borrowing base under the LINN Credit Facility was $4.5 billion and availability under the revolving credit facility was approximately $2.0 billion, which includes a $6 million reduction for outstanding letters of credit.

Redetermination of the borrowing base under the LINN Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. The administrative agent, at the direction of a super-majority of certain of the lenders, has the right to request one interim borrowing base redetermination per year. The Company also has the right to request one interim borrowing base redetermination per year, as well as the right to an additional interim redetermination each year in connection with certain acquisitions. Significant declines in commodity prices may result in a decrease in the borrowing base. The spring 2015 semi-annual redetermination is scheduled for May 2015, and the Company anticipates its lenders will recommend a decrease in the borrowing base under the LINN Credit Facility.

The Company’s obligations under the LINN Credit Facility are secured by mortgages on certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in the Company’s direct and indirect material subsidiaries. The Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report, or 2) a Collateral Coverage Ratio of at least 2.5 to 1. Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount. Additionally, the obligations under the LINN Credit Facility are guaranteed by all of the Company’s material subsidiaries, other than Berry Petroleum Company, LLC (“Berry”), and are required to be guaranteed by any future material subsidiaries. The Company is in compliance with all financial and other covenants of the LINN Credit Facility.

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

The $500 million term loan has a maturity date of April 2019 and incurs interest based on either the LIBOR plus a margin of 2.5% per annum or the ABR plus a margin of 1.5% per annum, at the Company’s election. Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR. The term loan may be repaid at the option of the Company without premium or penalty, subject to breakage costs. While the term loan is outstanding, the Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report, or 2) a Term Loan Collateral Coverage Ratio of at least 2.5 to 1. The Term Loan Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount and the aggregate amount of the term loan outstanding. The other terms and conditions of the LINN Credit Facility, including the financial and other restrictive covenants set forth therein, are applicable to the term loan.

Berry Credit Facility

Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) currently has a borrowing base of $1.4 billion, subject to lender commitments. The maturity date is April 2019. At March 31, 2015, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit.

Redetermination of the borrowing base under the Berry Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. A super-majority of the lenders under the Berry Credit Facility and Berry also have the right to request interim borrowing base redeterminations once between scheduled redeterminations. Significant declines in commodity prices may result in a decrease in the borrowing base. The spring 2015 semi-annual redetermination is scheduled for May 2015, and the Company anticipates its lenders will recommend a decrease in the borrowing base under the Berry Credit Facility.

Berry’s obligations under the Berry Credit Facility are secured by mortgages on its oil and natural gas properties and other personal property. Berry is required to maintain mortgages on properties representing at least 80% of the present value of its oil and natural gas proved reserves. Berry is in compliance with all financial and other covenants of the Berry Credit Facility.

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

The Company refers to the LINN Credit Facility and the Berry Credit Facility, collectively, as the “Credit Facilities.”

Repurchases of Senior Notes

During the three months ended March 31, 2015, the Company repurchased on the open market approximately $79 million of its 8.625% senior notes due April 2020. In connection with the repurchases, the Company recorded a gain on extinguishment of debt of approximately $7 million for the three months ended March 31, 2015.

Senior Notes Covenants

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

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

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

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Derivatives

3 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

Derivatives

Commodity Derivatives

The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company directly hedges only its oil and natural gas production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials.

The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. In connection with the 2013 acquisition of Berry, the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

The following table summarizes derivative positions for the periods indicated as of March 31, 2015:

	April 1 - December 31, 2015		2016		2017		2018
Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMMBtu)	88,935		121,841		120,122		36,500
Average price ($/MMBtu)	$	5.19	$	4.20	$	4.26	$	5.00
Put options (NYMEX Henry Hub):
Hedged volume (MMMBtu)	54,137		76,269		66,886		—
Average price ($/MMBtu)	$	5.00	$	5.00	$	4.88	$	—
Oil positions:
Fixed price swaps (NYMEX WTI): (1)
Hedged volume (MBbls)	9,426		11,465		4,755		—
Average price ($/Bbl)	$	93.33	$	90.56	$	89.02	$	—
Three-way collars (NYMEX WTI):
Hedged volume (MBbls)	825		—		—		—
Short put ($/Bbl)	$	70.00	$	—	$	—	$	—
Long put ($/Bbl)	$	90.00	$	—	$	—	$	—
Short call ($/Bbl)	$	101.62	$	—	$	—	$	—
Put options (NYMEX WTI):
Hedged volume (MBbls)	2,581		3,271		384		—
Average price ($/Bbl)	$	90.00	$	90.00	$	90.00	$	—

	April 1 - December 31, 2015			2016			2017			2018
Natural gas basis differential positions:(2)
Panhandle basis swaps: (3)
Hedged volume (MMMBtu)	65,670			59,954			59,138			16,425
Hedged differential ($/MMBtu)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)
NWPL Rockies basis swaps: (3)
Hedged volume (MMMBtu)	43,707			65,794			38,880			10,804
Hedged differential ($/MMBtu)	$	(0.23	)	$	(0.24	)	$	(0.19	)	$	(0.19	)
MichCon basis swaps: (3)
Hedged volume (MMMBtu)	7,040			7,768			7,437			2,044
Hedged differential ($/MMBtu)	$	0.06		$	0.05		$	0.05		$	0.05
Houston Ship Channel basis swaps: (3)
Hedged volume (MMMBtu)	19,351			34,364			36,730			986
Hedged differential ($/MMBtu)	$	(0.03	)	$	(0.02	)	$	(0.02	)	$	(0.08	)
Permian basis swaps: (3)
Hedged volume (MMMBtu)	3,823			4,219			4,819			1,314
Hedged differential ($/MMBtu)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)
SoCal basis swaps: (4)
Hedged volume (MMMBtu)	22,050			32,940			—			—
Hedged differential ($/MMBtu)	$	(0.03	)	$	(0.03	)	$	—		$	—
Oil timing differential positions:
Trade month roll swaps (NYMEX WTI): (5)
Hedged volume (MBbls)	5,463			7,446			6,486			—
Hedged differential ($/Bbl)	$	0.24		$	0.25		$	0.25		$	—

⁽¹⁾  Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, at counterparty election on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

⁽²⁾  Settle on the respective pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.

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

⁽⁴⁾  For positions which hedge exposure to differentials in consuming areas, the Company pays the NYMEX Henry Hub natural gas price plus the respective spread and receives the specified index price. Cash settlements are made on a net basis.

⁽⁵⁾  The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX WTI price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

During the three months ended March 31, 2015, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for May 2015 through December 2017, to hedge exposure to differentials in certain producing areas, and oil swaps for April 2015 through December 2015. In addition, the Company entered into natural gas basis swaps for May 2015 through December 2016 to hedge exposure to the differential in California, where it consumes natural gas in its heavy oil development operations.

Settled derivatives on natural gas production for the three months ended March 31, 2015, included volumes of 46,823 MMMBtu at an average contract price of $5.12 per MMBtu. Settled derivatives on oil production for the three months ended March 31, 2015, included volumes of 3,975 MBbls at an average contract price of $94.29 per Bbl. Settled derivatives on natural gas production for the three months ended March 31, 2014, included volumes of 43,651 MMMBtu at an average contract price of $5.14 per MMBtu. Settled derivatives on oil production for the three months ended March 31, 2014, included volumes of 6,161 MBbls at an average contract price of $92.39 per Bbl.

The natural gas derivatives are settled based on the closing price of NYMEX Henry Hub natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX WTI crude oil for each day of the delivery month.

Balance Sheet Presentation

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

	March 31, 2015		December 31, 2014
	(in thousands)
Assets:
Commodity derivatives	$	2,106,710	$	2,014,815
Liabilities:
Commodity derivatives	$	40,397	$	90,260

By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facilities or were participants or affiliates of participants in its Credit Facilities at the time it originally entered into the derivatives. The Credit Facilities are secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $2.1 billion at March 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

Gains and losses on derivatives used to hedge production were net gains of approximately $425 million for the three months March 31, 2015, and net losses of approximately $241 million for the three months ended March 31, 2014, and are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.” Gains and losses on derivatives used to hedge natural gas consumption, entered into in March 2015, were net losses of approximately $1 million for the three months ended March 31, 2015, and are reported on the condensed consolidated statement of operations in “lease operating expenses.” For the three months ended March 31, 2015, and March 31, 2014, the Company received net cash settlements of approximately $282 million and paid net cash settlements of approximately $15 million, respectively.

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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2% for the three months ended March 31, 2015); and (iv) a credit-adjusted risk-free interest rate (average of 5.6% for the three months ended March 31, 2015). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

The following presents a reconciliation of the Company’s asset retirement obligations (in thousands):

Asset retirement obligations at December 31, 2014	$	497,570
Liabilities added from drilling	1,390
Current year accretion expense	7,399
Settlements	(1,783		)
Revision of estimates	(1,345		)
Asset retirement obligations at March 31, 2015	$	503,231

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Acquisitions and Joint-Venture Funding (Details) (USD $)	0 Months Ended	3 Months Ended
	Apr. 03, 2012	Mar. 31, 2015	Jun. 27, 2014
Business Acquisition Anadarko [Member]
Business Acquisition [Line Items]
Future Funding Commitment Of Joint Venture Consideration Transferred		$ 25,000,000
Future Funding Of Joint Venture Agreement	400,000,000
Business Acquisition Devon [Member] [Member]
Business Acquisition [Line Items]
Business acquisition interim financing			$ 2,300,000,000

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Balance Sheets) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Restricted cash	$ 6,000,000	$ 6,000,000
Net Outstanding Checks	0	95,000,000
Other accrued liabilities
Accrued interest	143,088,000	105,310,000
Accrued compensation	22,854,000	44,875,000
Asset retirement obligations	16,187,000	16,187,000
Other	2,301,000	1,364,000
Other accrued liabilities	$ 184,430,000	$ 167,736,000

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Related Party Transactions

3 Months Ended

Mar. 31, 2015

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

LinnCo

LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, was formed on April 30, 2012. LinnCo’s initial sole purpose was to own units in LINN Energy. In connection with the 2013 acquisition of Berry, LinnCo amended its limited liability company agreement to permit, among other things, the acquisition and subsequent contribution of assets to LINN Energy. All of LinnCo’s common shares are held by the public. As of March 31, 2015, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy and owned approximately 39% of LINN Energy’s outstanding units.

LINN Energy has agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any financial, legal, accounting, tax advisory, financial advisory and engineering fees, and other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity. These expenses include costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees. In addition, the Company has agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities. All expenses and costs paid by LINN Energy on LinnCo’s behalf are expensed by LINN Energy.

For the three months ended March 31, 2015, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $1.4 million, of which approximately $1.1 million had been paid by LINN Energy on LinnCo’s behalf as of March 31, 2015. The expenses for the three months ended March 31, 2015, include approximately $491,000 related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses.

For the three months ended March 31, 2014, LinnCo incurred total general and administrative expenses of approximately $734,000, of which approximately $83,000 had been paid by LINN Energy on LinnCo’s behalf as of March 31, 2014. The expenses for the three months ended March 31, 2014, include approximately $470,000 related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses. In addition, during the three months ended March 31, 2014, LINN Energy paid approximately $11 million on LinnCo’s behalf for general and administrative expenses incurred by LinnCo in 2013.

During the three months ended March 31, 2015, and March 31, 2014, the Company paid approximately $40 million and $93 million, respectively, in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy.

Other

One of the Company’s directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the three months ended March 31, 2015, and March 31, 2014, the Company incurred expenditures of approximately $3 million and $4 million, respectively, related to services rendered by Superior and its subsidiaries.

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Unit-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2015

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

Employee Service Share-Based Compensation Expense

A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:

	Three Months Ended March 31,
	2015		2014
	(in thousands)
General and administrative expenses	$	16,633	$	18,223
Lease operating expenses	3,877		3,277
Total unit-based compensation expenses	$	20,510	$	21,500
Income tax benefit	$	7,579	$	7,944

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Commitments and Contingencies (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Payments for Legal Settlements	$ 0	$ 0

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Debt (Details) (USD $)	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014	Dec. 31, 2014		Apr. 30, 2012
Debt Instrument [Line Items]
Less current maturities	$ 0			$ 0
Term loan	500,000,000			500,000,000
Gain on extinguishment of debt	6,635,000		0
Percent of future net income allowable to increase Berry's restricted payments basket	50.00%
Berry [Member] | Line of Credit | Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	1,200,000,000
Debt Instrument, Interest Rate at Period End (in hundredths)	2.68%			2.67%
Line of Credit Facility, Maximum Borrowing Capacity	1,400,000,000
Line of Credit Facility, Remaining Borrowing Capacity	1,000,000
The percentage of properties that the company is required to maintain mortgages on (in hundredths)	80.00%
Berry [Member] | Line of Credit | Credit Facility | Minimum
Debt Instrument [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.375%
Berry [Member] | Line of Credit | Credit Facility | Maximum
Debt Instrument [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
Berry [Member] | Line of Credit | Credit Facility | London Interbank Offered Rate (LIBOR) [Member] | Minimum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Berry [Member] | Line of Credit | Credit Facility | London Interbank Offered Rate (LIBOR) [Member] | Maximum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
Berry [Member] | Line of Credit | Credit Facility | ABR | Minimum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
Berry [Member] | Line of Credit | Credit Facility | ABR | Maximum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Berry [Member] | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.75%
Linn Energy, LLC [Member] | Line of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	4,000,000,000					4,000,000,000
Line of Credit Facility, Maximum Borrowing Capacity	4,500,000,000
Line of Credit Facility, Remaining Borrowing Capacity	2,000,000,000
Letters of Credit Outstanding, Amount	6,000,000
Line Of Credit Facility Collateral Coverage Ratio	2.5
Linn Energy, LLC [Member] | Line of Credit | Credit Facility
Debt Instrument [Line Items]
Debt Instrument, Interest Rate at Period End (in hundredths)	1.93%			1.92%
Linn Energy, LLC [Member] | Line of Credit | Credit Facility | Minimum
Debt Instrument [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.375%
Linn Energy, LLC [Member] | Line of Credit | Credit Facility | Maximum
Debt Instrument [Line Items]
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
Linn Energy, LLC [Member] | Line of Credit | Credit Facility | London Interbank Offered Rate (LIBOR) [Member] | Minimum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Linn Energy, LLC [Member] | Line of Credit | Credit Facility | London Interbank Offered Rate (LIBOR) [Member] | Maximum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
Linn Energy, LLC [Member] | Line of Credit | Credit Facility | ABR | Minimum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
Linn Energy, LLC [Member] | Line of Credit | Credit Facility | ABR | Maximum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Linn Energy, LLC [Member] | Senior Notes [Member] | Senior Notes Due 2020
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.625%
Extinguishment of debt	79,000,000
Linn Energy, LLC [Member] | Loans Payable [Member]
Debt Instrument [Line Items]
Term loan	$ 500,000,000	[1]		$ 500,000,000	[1]
Debt Instrument, Interest Rate at Period End (in hundredths)	2.68%			2.66%
The percentage of properties that the company is required to maintain mortgages on (in hundredths)	80.00%
Linn Energy, LLC [Member] | Loans Payable [Member] | Credit Facility
Debt Instrument [Line Items]
The percentage of properties that the company is required to maintain mortgages on (in hundredths)	80.00%
Line Of Credit Facility Collateral Coverage Ratio	2.5
Linn Energy, LLC [Member] | Loans Payable [Member] | Credit Facility | London Interbank Offered Rate (LIBOR) [Member] | Maximum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
Linn Energy, LLC [Member] | Loans Payable [Member] | Credit Facility | ABR | Maximum
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%

[1] Variable interest rates of 2.68% and 2.66% at March 31, 2015, and December 31, 2014, respectively.

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CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS' CAPITAL (Unaudited) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Increase (Decrease) in Unitholders' Capital
December 31, 2014 (in units)	331,974,913
December 31, 2014	$ 4,543,605
Sale of units (in units)	1,328,192
Sale of units, net of offering costs of $594	15,306
Issuance of units	0
Distributions to unitholders	(104,815)
Unit-based compensation expenses	20,510
Excess tax benefit from unit-based compensation and other	(8,943)
Net loss	(339,160)
March 31, 2015 (in units)	336,887,489
March 31, 2015	4,126,503
Member Units [Member]
Increase (Decrease) in Unitholders' Capital
December 31, 2014 (in units)	331,975,000
Sale of units (in units)	1,328,000
Issuance of units (in units)	3,584,000
March 31, 2015 (in units)	336,887,000
Common Stock Including Additional Paid in Capital [Member]
Increase (Decrease) in Unitholders' Capital
December 31, 2014	5,395,811
Sale of units, net of offering costs of $594	15,306
Issuance of units	0
Distributions to unitholders	(104,815)
Unit-based compensation expenses	20,510
Excess tax benefit from unit-based compensation and other	(8,943)
Net loss	0
March 31, 2015	5,317,869
Accumulated Deficit
Increase (Decrease) in Unitholders' Capital
December 31, 2014	(852,206)
Sale of units, net of offering costs of $594	0
Issuance of units	0
Distributions to unitholders	0
Unit-based compensation expenses	0
Excess tax benefit from unit-based compensation and other	0
Net loss	(339,160)
March 31, 2015	$ (1,191,366)

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Unitholders' Capital

3 Months Ended

Mar. 31, 2015

Equity [Abstract]

Unitholders' Capital

Unitholders’ Capital

At-the-Market Offering Program

The Company has the authority to sell up to $500 million of units under an at-the-market offering program. Sales of units, if any, will be made under an equity distribution agreement by means of ordinary brokers’ transactions, through the facilities of the NASDAQ Global Select Market, any other national securities exchange or facility thereof, a trading facility of a national securities association or an alternate trading system, to or through a market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, at market prices, in block transactions, or as otherwise agreed with a sales agent. The Company expects to use the net proceeds from any sale of the units for general corporate purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt.

During the three months ended March 31, 2015, the Company, under its equity distribution agreement, issued and sold 1,328,192 units representing limited liability company interests at an average unit price of $11.97 for net proceeds of approximately $16 million (net of approximately $159,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional service expenses of approximately $435,000. The Company used the net proceeds for general corporate purposes including the open market repurchases of a portion of its 8.625% senior notes due April 2020 (see Note 6). At March 31, 2015, units totaling approximately $484 million in aggregate offering price remained available to be issued and sold under the agreement.

Distributions

Under the Company’s limited liability company agreement, unitholders are entitled to receive a distribution of available cash, which includes cash on hand plus borrowings less any reserves established by the Company’s Board of Directors to provide for the proper conduct of the Company’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions over the next four quarters. Distributions paid by the Company are presented on the condensed consolidated statement of unitholders’ capital and the condensed consolidated statements of cash flows. On April 1, 2015, the Company’s Board of Directors declared a cash distribution of $0.3125 per unit with respect to the first quarter of 2015, to be paid in three equal installments of $0.1042 per unit. The first monthly distribution with respect to the first quarter of 2015, totaling approximately $35 million, was paid on April 16, 2015, to unitholders of record as of the close of business on April 13, 2015.

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Debt (Tables)

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Summary of Outstanding Debt

The following summarizes the Company’s outstanding debt:

	March 31, 2015			December 31, 2014
	(in thousands, except percentages)
LINN credit facility (1)	$	1,975,000		$	1,795,000
Berry credit facility (2)	1,173,175			1,173,175
Term loan (3)	500,000			500,000
6.50% senior notes due May 2019	1,200,000			1,200,000
6.25% senior notes due November 2019	1,800,000			1,800,000
8.625% senior notes due April 2020	1,220,800			1,300,000
6.75% Berry senior notes due November 2020	299,970			299,970
7.75% senior notes due February 2021	1,000,000			1,000,000
6.50% senior notes due September 2021	650,000			650,000
6.375% Berry senior notes due September 2022	599,163			599,163
Net unamortized discounts and premiums	(19,620		)	(21,499		)
Total debt, net	10,398,488			10,295,809
Less current maturities	—			—
Total long-term debt, net	$	10,398,488		$	10,295,809

⁽¹⁾  Variable interest rates of 1.93% and 1.92% at March 31, 2015, and December 31, 2014, respectively.

⁽²⁾  Variable interest rates of 2.68% and 2.67% at March 31, 2015, and December 31, 2014, respectively.

⁽³⁾  Variable interest rates of 2.68% and 2.66% at March 31, 2015, and December 31, 2014, respectively.

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

	March 31, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Credit facilities	$	3,148,175	$	3,148,175	$	2,968,175	$	2,968,175
Term loan	500,000		500,000		500,000		500,000
Senior notes, net	6,750,313		5,454,065		6,827,634		5,703,649
Total debt, net	$	10,398,488	$	9,102,240	$	10,295,809	$	9,171,824

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Oil and Natural Gas Properties (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	$ 532,617	$ 0
Proved properties:
Leasehold acquisition	13,368,818		13,362,642
Development	3,012,467		2,830,841
Unproved properties	1,865,612		1,875,417
Oil and natural gas properties (successful efforts method)	18,246,897		18,068,900
Less accumulated depletion and amortization	(5,592,674)		(4,867,682)
Oil and natural gas properties, successful efforts method, net	12,654,223		13,201,218
Shallow Texas Panhandle Brown Dolomite formation [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	278,000
California operating region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	207,000
TexLa operating region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	33,000
South Texas operating region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	9,000
Mid-Continent operating region [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	$ 6,000

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Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows

3 Months Ended

Mar. 31, 2015

Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows

“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following:

	March 31, 2015		December 31, 2014
	(in thousands)
Accrued interest	$	143,088	$	105,310
Accrued compensation	22,854		44,875
Asset retirement obligations	16,187		16,187
Other	2,301		1,364
	$	184,430	$	167,736

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

	Three Months Ended March 31,
	2015		2014
	(in thousands)
Cash payments for interest, net of amounts capitalized	$	98,541	$	77,512
Cash payments for income taxes	$	57	$	—
Noncash investing activities:
Accrued capital expenditures	$	161,247	$	338,323

Included in “acquisition of oil and natural gas properties and joint-venture funding” on the condensed consolidated statement of cash flows for the three months ended March 31, 2014, is approximately $25 million paid by the Company to fund the commitment related to the joint-venture agreement entered into with Anadarko in April 2012 (see Note 2).

For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $6 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at both March 31, 2015, and December 31, 2014, and primarily represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facilities. At December 31, 2014, net outstanding checks of approximately $95 million were reclassified and included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet. At March 31, 2015, no net outstanding checks were reclassified. Net outstanding checks are presented as cash flows from financing activities and included in “other” on the condensed consolidated statements of cash flows.