Edgar Filing: LINN ENERGY, LLC

LINE 6.30.2014 10Q

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 June 30, 2014



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

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 July 31, 2014, there were 331,729,246 units outstanding.

TABLE OF CONTENTS



		Page

	Glossary of Terms	ii

	Part I – Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of June 30, 2014, and December 31, 2013	1
	Condensed Consolidated Statements of Operations for the three months and six months ended June 30, 2014, and June 30, 2013	2
	Condensed Consolidated Statement of Unitholders’ Capital for the six months ended June 30, 2014	3
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2014, and June 30, 2013	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	52

	Part II – Other Information
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	55
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	55
Item 3.	Defaults Upon Senior Securities	56
Item 4.	Mine Safety Disclosures	56
Item 5.	Other Information	56
Item 6.	Exhibits	57

	Signature	58

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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.

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PART I – FINANCIAL INFORMATION


Item 1.	Financial Statements

LINN ENERGY, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2014			December 31, 2013
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	38,339		$	52,171
Accounts receivable – trade, net	549,589			488,202
Derivative instruments	91,611			176,130
Other current assets	107,882			99,437
Total current assets	787,421			815,940

Noncurrent assets:
Oil and natural gas properties (successful efforts method)	18,684,209			17,888,559
Less accumulated depletion and amortization	(4,051,761		)	(3,546,284		)
	14,632,448			14,342,275

Other property and equipment	676,294			647,882
Less accumulated depreciation	(135,316		)	(110,939		)
	540,978			536,943

Derivative instruments	175,537			682,002
Other noncurrent assets	132,280			127,804
	307,817			809,806
Total noncurrent assets	15,481,243			15,689,024
Total assets	$	16,268,664		$	16,504,964

LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	860,171		$	849,624
Derivative instruments	59,907			28,176
Other accrued liabilities	138,378			163,375
Current portion of long-term debt	—			211,558
Total current liabilities	1,058,456			1,252,733

Noncurrent liabilities:
Credit facilities	3,418,175			2,733,175
Term loan	500,000			500,000
Senior notes, net	5,726,176			5,725,483
Derivative instruments	8,827			4,649
Other noncurrent liabilities	395,907			397,497
Total noncurrent liabilities	10,049,085			9,360,804

Commitments and contingencies (Note 10)

Unitholders’ capital:
331,667,975 units and 329,661,161 units issued and outstanding at June 30, 2014, and December 31, 2013, respectively	5,854,727			6,291,824
Accumulated deficit	(693,604		)	(400,397		)
	5,161,123			5,891,427
Total liabilities and unitholders’ capital	$	16,268,664		$	16,504,964

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands, except per unit amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	967,850		$	488,207		$	1,906,727		$	950,939
Gains (losses) on oil and natural gas derivatives	(408,788		)	326,733			(650,281		)	218,363
Marketing revenues	30,273			17,222			60,819			27,074
Other revenues	7,616			6,663			13,273			11,509
	596,951			838,825			1,330,538			1,207,885
Expenses:
Lease operating expenses	184,901			83,584			378,934			172,305
Transportation expenses	44,854			29,298			90,484			56,481
Marketing expenses	23,274			9,360			44,346			16,734
General and administrative expenses	66,906			46,305			146,134			104,871
Exploration costs	1,551			818			2,642			3,044
Depreciation, depletion and amortization	274,435			198,629			542,236			396,070
Impairment of long-lived assets	—			(14,851		)	—			42,202
Taxes, other than income taxes	68,531			32,397			134,244			72,068
(Gains) losses on sale of assets and other, net	5,467			(959		)	8,053			2,213
	669,919			384,581			1,347,073			865,988
Other income and (expenses):
Interest expense, net of amounts capitalized	(134,300		)	(103,847		)	(268,113		)	(204,206		)
Loss on extinguishment of debt	—			(4,187		)	—			(4,187		)
Other, net	(2,549		)	(2,182		)	(4,852		)	(3,825		)
	(136,849		)	(110,216		)	(272,965		)	(212,218		)
Income (loss) before income taxes	(209,817		)	344,028			(289,500		)	129,679
Income tax expense (benefit)	(1,947		)	(1,129		)	3,707			6,407
Net income (loss)	$	(207,870	)	$	345,157		$	(293,207	)	$	123,272

Net income (loss) per unit:
Basic	$	(0.64	)	$	1.47		$	(0.91	)	$	0.52
Diluted	$	(0.64	)	$	1.46		$	(0.91	)	$	0.52
Weighted average units outstanding:
Basic	328,844			233,448			328,588			233,313
Diluted	328,844			233,910			328,588			233,800

Distributions declared per unit	$	0.725		$	0.725		$	1.45		$	1.45

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL

(Unaudited)



	Units	Unitholders’ Capital			Accumulated Deficit			Total Unitholders’ Capital
	(in thousands)

December 31, 2013	329,661	$	6,291,824		$	(400,397	)	$	5,891,427
Issuance of units	2,007	7,887			—			7,887
Distributions to unitholders		(480,583		)	—			(480,583		)
Unit-based compensation expenses		32,583			—			32,583
Excess tax benefit from unit-based compensation		3,016			—			3,016
Net loss		—			(293,207		)	(293,207		)
June 30, 2014	331,668	$	5,854,727		$	(693,604	)	$	5,161,123

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
	2014			2013
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(293,207	)	$	123,272
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	542,236			396,070
Impairment of long-lived assets	—			42,202
Unit-based compensation expenses	32,583			19,575
Loss on extinguishment of debt	—			4,187
Amortization and write-off of deferred financing fees	6,202			10,905
Losses on sale of assets and other, net	3,506			16,814
Deferred income taxes	3,475			5,725
Derivatives activities:
Total (gains) losses	650,281			(218,363		)
Cash settlements	(23,123		)	144,502
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	(61,891		)	36,174
(Increase) decrease in other assets	(6,947		)	2,260
Increase (decrease) in accounts payable and accrued expenses	113,582			(5,319		)
Decrease in other liabilities	(51,062		)	(16,648		)
Net cash provided by operating activities	915,635			561,356

Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	(25,891		)	(64,381		)
Development of oil and natural gas properties	(805,617		)	(495,899		)
Purchases of other property and equipment	(31,411		)	(55,147		)
Proceeds from sale of properties and equipment and other	(11,730		)	210,899
Net cash used in investing activities	(874,649		)	(404,528		)

Cash flow from financing activities:
Proceeds from borrowings	1,095,000			775,000
Repayments of debt	(616,124		)	(560,737		)
Distributions to unitholders	(480,583		)	(341,117		)
Financing fees and other, net	(56,127		)	(30,656		)
Excess tax benefit from unit-based compensation	3,016			591
Net cash used in financing activities	(54,818		)	(156,919		)

Net decrease in cash and cash equivalents	(13,832		)	(91		)
Cash and cash equivalents:
Beginning	52,171			1,243
Ending	$	38,339		$	1,152

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

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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 the United States (“U.S.”), in the Mid-Continent, the Rockies, the Permian Basin, California, the Hugoton Basin, Michigan, Illinois and east Texas.

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, 2013. 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 Company’s other investment is accounted for at cost.

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 May 2014, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. The 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 consolidated financial statements and related disclosures.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Note 2 – Acquisitions, Joint-Venture Funding and Divestitures

For the six months ended June 30, 2014, the Company paid approximately $25 million, including interest, towards the future funding 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.

During the six months ended June 30, 2014, the Company completed small acquisitions of oil and natural gas properties located in its various operating regions. The Company, in the aggregate, paid approximately $1 million in total consideration for these properties.

Properties Exchange – Pending

On May 20, 2014, the Company, through two of its wholly owned subsidiaries, entered into a definitive agreement to trade a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., for operating interests in the Hugoton Basin. The Company anticipates the transaction will close in the third quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.

Acquisitions and Divestiture – Pending

On June 27, 2014, the Company, through one of its wholly owned subsidiaries, entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties and related assets located primarily in the Rockies, Mid-Continent, east Texas, north Louisiana and south Texas from affiliates of Devon Energy Corporation for a contract price of $2.3 billion. The Company anticipates the acquisition will close in the third quarter of 2014, subject to closing conditions, and has secured $2.3 billion of committed interim financing for the acquisition, subject to final documentation. There can be no assurance that all of the conditions to closing will be satisfied.

On July 18, 2014, the Company, through one of its wholly owned subsidiaries, entered into a definitive purchase and sale agreement to acquire certain oil and natural gas properties located in the Hugoton Basin from Pioneer Natural Resources Company for a contract price of $340 million, including a deposit of $34 million paid in July 2014. The Company anticipates the acquisition will close in the third quarter of 2014, subject to closing conditions, and will be financed with borrowings under the LINN Credit Facility, as defined in Note 6. There can be no assurance that all of the conditions to closing will be satisfied.

On July 24, 2014, the Company, through one of its wholly owned subsidiaries, entered into a definitive purchase and sale agreement to sell its interests in certain non-producing oil and natural gas properties located in the Mid-Continent region for a purchase price of approximately $90 million, subject to closing adjustments. The sale is anticipated to close in the fourth quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. The Company plans to use the net proceeds from the sale to repay borrowings under the LINN Credit Facility.

Acquisitions – 2013

Berry Acquisition

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

This acquisition was accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition date, while transaction and integration costs associated with the acquisitions were

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

expensed as incurred. The initial accounting for the business combination is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition date. The results of operations of the acquisition have been included in the condensed consolidated financial statements since the acquisition date.

The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the three months and six months ended June 30, 2013, assuming the Berry acquisition had been completed as of January 1, 2013, including adjustments to reflect the values assigned to the net assets acquired:



	Three Months Ended June 30, 2013		Six Months Ended June 30, 2013
	(in thousands, except per unit amounts)

Total revenues and other	$	1,161,137	$	1,806,346
Total operating expenses	$	586,909	$	1,256,821
Net income	$	441,935	$	284,615

Net income per unit:
Basic	$	1.34	$	0.86
Diluted	$	1.34	$	0.86

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


•	Reflect the results of Berry.


•	Reflect incremental depreciation, depletion and amortization expense, using the units-of-production method, related to oil and natural gas properties acquired and using an estimated useful life of 20 years for other property and equipment.


•	Reflect a reduction in interest expense related to the amortization of the adjustment to fair value of Berry’s debt using the effective interest method.


•	Exclude transaction costs included in the historical statements of operations for the three months and six months ended June 30, 2013, as they reflect nonrecurring charges not expected to have a continuing impact on the combined results.


•	Reflect approximately 93.8 million LINN Energy units assumed to be issued in conjunction with the transaction on January 1, 2013.

Divestiture – 2013

On May 31, 2013, the Company, through one of its wholly owned subsidiaries, together with the Company’s partners, Panther Energy, LLC and Red Willow Mid-Continent, LLC, completed the sale of its interests in certain oil and natural gas properties located in the Mid-Continent region (“Panther Operated Cleveland Properties”) to Midstates Petroleum Company, Inc. At March 31, 2013, the carrying value of the Panther Operated Cleveland Properties was reduced to fair value less costs to sell resulting in an impairment charge of approximately $57 million and the properties were classified as “assets held for sale.” On May 31, 2013, upon the completion of the sale, the Company recorded an adjustment of approximately $15 million to reduce the initial impairment charge recorded in March 2013 resulting in a total impairment charge of approximately $42 million for the six months ended June 30, 2013. The charge is included in “impairment of long-lived assets” on the condensed consolidated statement of operations. Proceeds received for the Company’s portion of its interests in the properties were approximately $219 million, net of costs to sell of approximately $2 million.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Note 3 – Unitholders’ Capital

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 July 1, 2014, the Company’s Board of Directors declared a cash distribution of $0.725 per unit with respect to the second quarter of 2014, to be paid in three equal installments of $0.2416 per unit. The first monthly distribution with respect to the second quarter of 2014, totaling approximately $80 million, was paid on July 16, 2014, to unitholders of record as of the close of business on July 11, 2014.

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:



	June 30, 2014			December 31, 2013
	(in thousands)
Proved properties:
Leasehold acquisition	$	12,329,359		$	12,277,089
Development	4,468,702			3,660,277
Unproved properties	1,886,148			1,951,193
	18,684,209			17,888,559
Less accumulated depletion and amortization	(4,051,761		)	(3,546,284		)
	$	14,632,448		$	14,342,275

Note 5 – Unit-Based Compensation

During the six months ended June 30, 2014, the Company granted 1,447,577 restricted units and 214,875 phantom units to employees, primarily as part of its annual review of its employees’ compensation, including executives, with an aggregate fair value of approximately $56 million. The restricted units and phantom units vest over three years. The Company also granted 212,524 performance units (the maximum number of units available to be earned) to certain executive officers, with an aggregate fair value of approximately $5 million. The initial 2014 performance unit awards vest 50% in two years and 50% in three years from the award date. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands)

General and administrative expenses	$	9,496	$	7,136	$	27,719	$	17,001
Lease operating expenses	1,587		1,177		4,864		2,574
Total unit-based compensation expenses	$	11,083	$	8,313	$	32,583	$	19,575
Income tax benefit	$	4,095	$	3,072	$	12,039	$	7,233

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Note 6 – Debt

The following summarizes the Company’s outstanding debt:



	June 30, 2014			December 31, 2013
	(in thousands, except percentages)

LINN credit facility ⁽¹⁾	$	2,245,000		$	1,560,000
Berry credit facility ⁽²⁾	1,173,175			1,173,175
Term loan ⁽³⁾	500,000			500,000
10.25% Berry senior notes due June 2014	—			205,257
6.50% senior notes due May 2019	750,000			750,000
6.25% senior notes due November 2019	1,800,000			1,800,000
8.625% senior notes due April 2020	1,300,000			1,300,000
6.75% Berry senior notes due November 2020	299,970			300,000
7.75% senior notes due February 2021	1,000,000			1,000,000
6.375% Berry senior notes due September 2022	599,163			600,000
Net unamortized discounts and premiums	(22,957		)	(18,216		)
Total debt, net	9,644,351			9,170,216
Less current maturities	—			(211,558		)
Total long-term debt, net	$	9,644,351		$	8,958,658


⁽¹⁾	Variable interest rates of 1.90% and 1.92% at June 30, 2014, and December 31, 2013, respectively.


⁽²⁾	Variable interest rates of 2.66% and 2.67% at June 30, 2014, and December 31, 2013, respectively.


⁽³⁾	Variable interest rates of 2.65% and 2.67% at June 30, 2014, and December 31, 2013, 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, as defined below, 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.



	June 30, 2014				December 31, 2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)

Credit Facilities	$	3,418,175	$	3,418,175	$	2,733,175	$	2,733,175
Term loan	500,000		500,000		500,000		500,000
Senior notes, net	5,726,176		6,091,525		5,937,041		6,162,402
Total debt, net	$	9,644,351	$	10,009,700	$	9,170,216	$	9,395,577

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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 a revolving credit facility up to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount of $4.0 billion. At June 30, 2014, the LINN Credit Facility had a borrowing base of $4.5 billion and available borrowing capacity of approximately $1.8 billion, which includes a $5 million reduction for outstanding letters of credit. In April 2014, the Company entered into an amendment to the LINN Credit Facility to extend the maturity from April 2018 to April 2019, among other items.

Redetermination of the borrowing base under the LINN Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October. The administrative agent, at the direction 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 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 the 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, 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 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.

In addition, the Company has a $500 million senior secured term loan with certain participants in its lender group under the LINN Credit Facility. Upon the amendment of the LINN Credit Facility in April 2014, the term loan has a maturity date of April 2019, consistent with the maturity of the LINN Credit Facility, 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 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 the 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”) has a borrowing base of $1.4 billion, subject to lender commitments. At June 30, 2014, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit. In February 2014, Berry entered into an amendment to the Berry Credit Facility to amend the terms of certain financial and reporting covenants, and in April 2014,

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Berry entered into an amendment to the Berry Credit Facility to extend the maturity from May 2016 to April 2019 and to amend the terms of certain financial covenants and definitions, among other items.

Redetermination of the borrowing base under the Berry Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October. The lenders under the 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. 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 currently in compliance with all financial and other covenants of the Berry Credit Facility. At December 31, 2013, Berry’s Current Ratio (as defined in the Berry Credit Facility), fell short of the requirement under its covenant primarily due to factors related to the transactions between the Company, LinnCo and Berry, including a reassessment of the carrying value of items on Berry’s balance sheet as of the acquisition date and updated accruals as of December 31, 2013. In February 2014, Berry received a waiver of the applicability of that covenant and any noncompliance which may have resulted as of December 31, 2013, and entered into an amendment to its credit facility to address this covenant for future periods. The shortfall and related waiver and amendment had no effect on Berry’s compliance with the indentures governing its outstanding senior notes for the quarter ended December 31, 2013, and Berry was in compliance with all of the covenants under the indentures governing its senior notes at December 31, 2013.

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 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.”

Senior Notes Due May 2019

The Company has $750 million in aggregate principal amount of 6.50% senior notes due May 2019 (the “May 2019 Senior Notes”). In an exchange offer that expired in October 2012, the Company exchanged all of its $750 million outstanding principal amount of May 2019 Senior Notes for an equal amount of new May 2019 Senior Notes. The terms of the new May 2019 Senior Notes are substantially similar in all material respects to those of the outstanding May 2019 Senior Notes, except that the transfer restrictions, registration rights and additional interest provisions relating to the outstanding May 2019 Senior Notes do not apply to the new May 2019 Senior Notes.

Senior Notes Due November 2019

The Company has $1.8 billion in aggregate principal amount of 6.25% senior notes due November 2019 (the “November 2019 Senior Notes”). In connection with the issuance and sale of the November 2019 Senior Notes, the Company entered into a Registration Rights Agreement (“November 2019 Registration Rights Agreement”) with the initial purchasers. Under the November 2019 Registration Rights Agreement, the Company agreed to use its reasonable efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially similar to the November 2019 Senior Notes in exchange for outstanding November 2019 Senior Notes within 400 days after the notes were issued. On March 22, 2013, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the November 2019 Senior Notes. On June 2, 2014, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $1.8 billion outstanding principal amount of November 2019 Senior Notes for an equal amount of new November 2019 Senior Notes.

The terms of the new November 2019 Senior Notes are substantially similar in all material respects to those of the outstanding November 2019 Senior Notes, except that the transfer restrictions, registration rights and additional interest provisions relating

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(Unaudited)

to the outstanding November 2019 Senior Notes do not apply to the new November 2019 Senior Notes. The exchange offer expired on June 28, 2014. The effective date of the registration statement was past the deadline in the registration rights agreement, and therefore, the Company paid additional interest of approximately $15 million since the deadline.

Senior Notes Due April 2020 and Senior Notes Due February 2021

The Company has $1.3 billion in aggregate principal amount of 8.625% senior notes due April 2020 (the “April 2020 Senior Notes”) and $1.0 billion in aggregate principal amount of 7.75% senior notes due February 2021 (the “February 2021 Senior Notes,” and together with the April 2020 Senior Notes, the “2010 Issued Senior Notes”). The restrictive legends from each of the 2010 Issued Senior Notes have been removed making them freely tradable (other than with respect to persons that are affiliates of the Company), thereby terminating the Company’s obligations under each of the registration rights agreements entered into in connection with the issuance of the 2010 Issued Senior Notes.

Berry Senior Notes Due November 2020

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

Berry Senior Notes Due September 2022

Berry has $599 million in aggregate principal amount of 6.375% senior notes due September 2022 (the “Berry September 2022 Senior Notes”). The Berry September 2022 Senior Notes were recorded at their fair value of approximately $607 million on the Berry acquisition date including a $7 million premium which is being amortized to interest expense over the life of the related notes.

Repurchases of Berry Senior Notes

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

Payment of Berry June 2014 Senior Notes

On May 30, 2014, in accordance with the provisions of the indenture related to the Berry June 2014 Senior Notes, the Company paid in full the remaining outstanding principal amount of approximately $205 million.

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 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.

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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 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 to provide an economic hedge of the risk related to the future commodity prices received. The Company does not enter into derivative contracts for trading purposes. In connection with the Berry acquisition (see Note 2), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including oil swaps, oil trade month roll swaps and oil collars through 2014, and oil basis swaps and oil three-way collars through 2015. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

The following table summarizes derivative positions for the periods indicated as of June 30, 2014:



	July 1 - December 31, 2014		2015		2016		2017		2018
Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMMBtu)	49,100		118,041		121,841		120,122		36,500
Average price ($/MMBtu)	$	5.25	$	5.19	$	4.20	$	4.26	$	5.00
Put options (NYMEX Henry Hub):
Hedged volume (MMMBtu)	40,141		71,854		76,269		66,886		—
Average price ($/MMBtu)	$	5.00	$	5.00	$	5.00	$	4.88	$	—
Oil positions:
Fixed price swaps (NYMEX WTI): ⁽¹⁾
Hedged volume (MBbls)	8,485		11,599		11,465		4,755		—
Average price ($/Bbl)	$	92.44	$	96.23	$	90.56	$	89.02	$	—
Collars (NYMEX WTI):
Hedged volume (MBbls)	368		—		—		—		—
Average floor price ($/Bbl)	$	90.00	$	—	$	—	$	—	$	—
Average ceiling price ($/Bbl)	$	102.87	$	—	$	—	$	—	$	—
Three-way collars (NYMEX WTI):
Hedged volume (MBbls)	1,564		1,095		—		—		—
Short put ($/Bbl)	$	72.11	$	70.00	$	—	$	—	$	—
Long put ($/Bbl)	$	93.76	$	90.00	$	—	$	—	$	—
Short call ($/Bbl)	$	109.79	$	101.62	$	—	$	—	$	—

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	July 1 - December 31, 2014			2015			2016			2017			2018
Put options (NYMEX WTI):
Hedged volume (MBbls)	1,996			3,426			3,271			384			—
Average price ($/Bbl)	$	91.30		$	90.00		$	90.00		$	90.00		$	—
Three-way collars (ICE Brent):
Hedged volume (MBbls)	184			—			—			—			—
Short put ($/Bbl)	$	80.00		$	—		$	—		$	—		$	—
Long put ($/Bbl)	$	100.00		$	—		$	—		$	—		$	—
Short call ($/Bbl)	$	114.05		$	—		$	—		$	—		$	—
Natural gas basis differential positions: ⁽²⁾
Panhandle basis swaps:
Hedged volume (MMMBtu)	40,020			87,162			59,954			59,138			16,425
Hedged differential ($/MMBtu)	$	(0.33	)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)
NWPL Rockies basis swaps:
Hedged volume (MMMBtu)	20,619			43,292			46,294			38,880			10,804
Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	(0.19	)	$	(0.19	)
MichCon basis swaps:
Hedged volume (MMMBtu)	4,784			9,344			7,768			7,437			2,044
Hedged differential ($/MMBtu)	$	0.08		$	0.06		$	0.05		$	0.05		$	0.05
Houston Ship Channel basis swaps:
Hedged volume (MMMBtu)	2,650			4,891			4,575			3,604			986
Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.08	)	$	(0.08	)
Permian basis swaps:
Hedged volume (MMMBtu)	2,466			5,074			4,219			4,819			1,314
Hedged differential ($/MMBtu)	$	(0.21	)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)
Oil basis differential positions:
ICE Brent - NYMEX WTI basis swaps:
Hedged volume (MBbls)	1,840			2,920			—			—			—
Hedged differential ($/Bbl)	$	11.60		$	11.60		$	—		$	—		$	—
Oil timing differential positions:
Trade month roll swaps (NYMEX WTI): ⁽³⁾
Hedged volume (MBbls)	4,577			7,251			7,446			6,486			—
Hedged differential ($/Bbl)	$	0.24		$	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, if the counterparties determine that the strike prices are in-the-money 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.

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⁽³⁾

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”).

Settled derivatives on natural gas production for the three months and six months ended June 30, 2014, included volumes of 44,136 MMMBtu and 87,787 MMMBtu, respectively, at an average contract price of $5.14 per MMBtu. Settled derivatives on oil production for the three months and six months ended June 30, 2014, included volumes of 6,230 MBbls and 12,391 MBbls, respectively, at an average contract price of $92.39 per Bbl. Settled derivatives on natural gas production for the three months and six months ended June 30, 2013, included volumes of 43,253 MMMBtu and 86,031 MMMBtu, respectively, at an average contract price of $5.29 per MMBtu. Settled derivatives on oil production for the three months and six months ended June 30, 2013, included volumes of 3,734 MBbls and 7,426 MBbls, respectively, at an average contract price of $95.57 per Bbl. The natural gas derivatives are settled based on the closing price of NYMEX 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 prices of NYMEX WTI and ICE Brent 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:



	June 30, 2014		December 31, 2013
	(in thousands)
Assets:
Commodity derivatives	$	551,636	$	1,048,212
Liabilities:
Commodity derivatives	$	353,222	$	222,905

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 $552 million at June 30, 2014. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Gains (Losses) on Derivatives

Gains and losses on derivatives were net losses of approximately $409 million and $650 million for the three months and six months ended June 30, 2014, respectively. Net losses for the three months and six months ended June 30, 2014, include cash settlement payments of approximately $9 million and $23 million, respectively. Gains and losses on derivatives were net gains of approximately $327 million and $218 million for the three months and six months ended June 30, 2013, respectively. Net gains for the three months and six months ended June 30, 2013, include cash settlement receipts of approximately $59 million and $145 million, respectively. These amounts are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.”

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(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 securities 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.

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



	June 30, 2014
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	551,636	$	(284,488	)	$	267,148
Liabilities:
Commodity derivatives	$	353,222	$	(284,488	)	$	68,734



	December 31, 2013
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	1,048,212	$	(190,080	)	$	858,132
Liabilities:
Commodity derivatives	$	222,905	$	(190,080	)	$	32,825


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

Note 9 – Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other accrued liabilities” and “other noncurrent liabilities” on the 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 (2.0% for the six months ended June 30, 2014); and (iv) a credit-adjusted risk-free interest rate (average of 5.4% for the six months ended June 30, 2014). 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.

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(Unaudited)

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



Asset retirement obligations at December 31, 2013	$	289,321
Liabilities added from drilling	5,673
Current year accretion expense	9,570
Settlements	(9,947		)
Revision of estimates	9,130
Asset retirement obligations at June 30, 2014	$	303,747

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 parties in this case are currently engaged in settlement negotiations and based on the current status of those negotiations, the Company estimates a range of possible loss of $1 million to $4.5 million for which an appropriate reserve has been established. For a certain statewide class action royalty payment dispute where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to the Company. Based on the 10^th Circuit Court of Appeals’ decision to reverse class certification orders in two unrelated certification cases, the court has permitted additional limited discovery prior to the briefing and hearing on class certification. Briefing and the hearing on class certification have not yet been set by the court. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any. 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.

Prior to the Company’s acquisition of Berry, Berry became, and continues to be, a defendant in a certain statewide royalty class action case, in which the parties have entered into a settlement agreement to settle past claims for approximately $2.4 million. Subject to approval of the settlement agreement by the court, Berry and the Company anticipate distribution of settlement funds to begin late in the third quarter or early fourth quarter of 2014.

In the summer of 2013, several class action complaints were filed in the United States District Court, Southern District of Texas and the United States District Court, Southern District of New York (the “SDNY”) against LINN Energy, LinnCo, certain of their officers and directors and the various underwriters for LinnCo’s initial public offering (these cases were subsequently consolidated in the SDNY (the “Combined Actions”)). These cases collectively asserted claims based on allegations that LINN Energy made false or misleading statements relating to its hedging strategy, the cash flow available for distribution to unitholders, and LINN Energy’s energy production in its Exchange Act filings and additional claims based on alleged misstatements relating to these issues in the prospectus and registration statement for LinnCo’s initial public offering.

In November 2013, LINN Energy and the other defendants filed a motion to dismiss the Combined Actions. On July 8, 2014, the Court dismissed the plaintiff’s claims with prejudice concluding that the plaintiff failed to demonstrate any material misstatement or omission by LINN Energy or LinnCo.

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behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants (the “Parker Family Trust Action”) (the Lombardo Action, Feldman Rev. Trust Action, and Parker Family Trust Action together, the “Texas Federal Court Derivative Actions”) (the Texas State Court Derivative Action and Texas Federal Court Derivative Actions together, the “Texas Derivative Actions”). On May 28, 2014, Bill McKinnon, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants (the “McKinnon Action”) in the Delaware Court of Chancery (the “Delaware Derivative Action”) (the Delaware Derivative Action and the Texas Derivative Actions collectively, the “Derivative Actions”). The Derivative Actions assert derivative claims on behalf of LINN Energy against the individual defendants for alleged breaches of fiduciary duty, waste of corporate assets, mismanagement, abuse of control, and unjust enrichment based on factual allegations similar to those in the Combined Actions. The cases are in their preliminary stages and it is possible that additional similar actions could be filed in the District Court of Harris County, Texas, the Delaware Court of Chancery, or in other jurisdictions. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any.

During the six months ended June 30, 2014, and June 30, 2013, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

In 2008, Lehman Brothers Holdings Inc. and Lehman Brothers Commodity Services Inc. (together “Lehman”), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New York. In March 2011, the Company and Lehman entered into Termination Agreements under which the Company was granted general unsecured claims against Lehman in the amount of $51 million (the “Company Claim”). In December 2011, a Chapter 11 Plan (“Lehman Plan”) was approved by the Bankruptcy Court. Based on the recovery estimates described in the approved disclosure statement relating to the Lehman Plan, the Company expects to ultimately receive a substantial portion of the Company Claim. In April 2014 and April 2013, the Company received approximately $3 million and $5 million, respectively, of the Company Claim of which both amounts are included in “gains (losses) on oil and natural gas derivatives” on the condensed consolidated statements of operations. In the aggregate, the Company has received approximately $42 million of the Company Claim and additional distributions are expected to occur in the future.

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.

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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 income (loss):



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands, except per unit data)

Net income (loss)	$	(207,870	)	$	345,157		$	(293,207	)	$	123,272
Allocated to participating securities	(2,154		)	(2,629		)	(4,306		)	(2,599		)
	$	(210,024	)	$	342,528		$	(297,513	)	$	120,673

Basic net income (loss) per unit	$	(0.64	)	$	1.47		$	(0.91	)	$	0.52
Diluted net income (loss) per unit	$	(0.64	)	$	1.46		$	(0.91	)	$	0.52

Basic weighted average units outstanding	328,844			233,448			328,588			233,313
Dilutive effect of unit equivalents	—			462			—			487
Diluted weighted average units outstanding	328,844			233,910			328,588			233,800

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 6 million unit options and warrants for the three months and six months ended June 30, 2014, and 3 million for the three months and six months ended June 30, 2013. All equivalent units were antidilutive for the three months and six months ended June 30, 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:



	June 30, 2014		December 31, 2013
	(in thousands)

Accrued compensation	$	31,702	$	55,257
Accrued interest	92,019		93,998
Asset retirement obligations	12,616		6,270
Other	2,041		7,850
	$	138,378	$	163,375

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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



	Six Months Ended June 30,
	2014			2013
	(in thousands)

Cash payments for interest, net of amounts capitalized	$	264,141		$	192,517
Cash payments for income taxes	$	—		$	14

Noncash investing activities:
In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follows:
Fair value of assets acquired	$	4,242		$	7,655
Cash (paid) received	(1,139		)	3,231
Receivables from sellers	—			1,792
Payables to sellers	—			(6,854		)
Liabilities assumed	$	3,103		$	5,824

Included in “acquisition of oil and natural gas properties and joint-venture funding” on the condensed consolidated statements of cash flows for the six months ended June 30, 2014, and June 30, 2013, is approximately $25 million and $68 million, respectively, paid by the Company towards the future funding 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 June 30, 2014, and December 31, 2013, 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, 2013, net outstanding checks of approximately $48 million were reclassified and included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet. At June 30, 2014, there were no net outstanding checks reclassified. The Company presents net outstanding checks as cash flows from financing activities on the condensed consolidated statements of cash flows.

Note 14 – Related Party Transactions

LinnCo

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 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 June 30, 2014, 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 legal, accounting, tax advisory, financial advisory and engineering fees, printing costs or 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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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 accounted for as investment at cost.

For the three months and six months ended June 30, 2014, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $749,000 and $1.5 million, respectively, all of which had been paid by LINN Energy on LinnCo’s behalf as of June 30, 2014. The expenses for the three months and six months ended June 30, 2014, include approximately $471,000 and $941,000, respectively, 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 six months ended June 30, 2014, LINN Energy paid approximately $11 million on LinnCo’s behalf for general and administrative expenses incurred by LinnCo in 2013.

For the three months and six months ended June 30, 2013, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $3 million and $15 million, respectively, of which approximately $8 million had been paid by LINN Energy on LinnCo’s behalf as of June 30, 2013. The expenses for the three months and six months ended June 30, 2013, included approximately $2 million and $13 million, respectively, of transaction costs related to professional services rendered by third parties in connection with the Berry acquisition. The expenses for the three months and six months ended June 30, 2013, also included approximately $344,000 and $806,000, respectively, 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.

During the three months and six months ended June 30, 2014, the Company paid approximately $93 million and $186 million, respectively, in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy. During the three months and six months ended June 30, 2013, the Company paid approximately $25 million and $50 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 and six months ended June 30, 2014, the Company paid approximately $8 million and $12 million, respectively, and for the three months and six months ended June 30, 2013, the Company paid approximately $7 million and $13 million, respectively, to Superior and its subsidiaries for services rendered to the Company. The transactions associated with these payments were consummated on terms equivalent to those that prevail in arm’s-length transactions.

Note 15 – Subsidiary Guarantors

LINN Energy, LLC’s November 2019 Senior Notes, May 2019 Senior Notes and 2010 Issued Senior Notes are guaranteed by all of the Company’s material subsidiaries, other than Berry which is an indirect 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.

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS

June 30, 2014



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	32		$	35,818		$	2,489		$	—		$	38,339
Accounts receivable – trade, net	—			393,012			156,577			—			549,589
Accounts receivable – affiliates	4,025,707			26,914			—			(4,052,621		)	—
Derivative instruments	—			89,541			2,070			—			91,611
Other current assets	476			77,171			30,235			—			107,882
Total current assets	4,026,215			622,456			191,371			(4,052,621		)	787,421

Noncurrent assets:
Oil and natural gas properties (successful efforts method)	—			13,558,084			5,126,125			—			18,684,209
Less accumulated depletion and amortization	—			(3,901,130		)	(150,631		)	—			(4,051,761		)
	—			9,656,954			4,975,494			—			14,632,448

Other property and equipment	—			586,438			89,856			—			676,294
Less accumulated depreciation	—			(131,526		)	(3,790		)	—			(135,316		)
	—			454,912			86,066			—			540,978

Derivative instruments	—			174,327			1,210			—			175,537
Notes receivable – affiliates	114,400			—			—			(114,400		)	—
Investments in consolidated subsidiaries	8,540,562			—			—			(8,540,562		)	—
Other noncurrent assets, net	105,004			11,072			16,204			—			132,280
	8,759,966			185,399			17,414			(8,654,962		)	307,817
Total noncurrent assets	8,759,966			10,297,265			5,078,974			(8,654,962		)	15,481,243
Total assets	$	12,786,181		$	10,919,721		$	5,270,345		$	(12,707,583	)	$	16,268,664

LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	1,822		$	570,680		$	287,669		$	—		$	860,171
Accounts payable – affiliates	—			4,026,182			26,439			(4,052,621		)	—
Derivative instruments	—			28,332			31,575			—			59,907
Other accrued liabilities	75,773			43,045			19,560			—			138,378
Total current liabilities	77,595			4,668,239			365,243			(4,052,621		)	1,058,456

Noncurrent liabilities:
Credit facilities	2,245,000			—			1,173,175			—			3,418,175
Term loan	500,000			—			—			—			500,000
Senior notes, net	4,811,496			—			914,680			—			5,726,176
Notes payable – affiliates	—			114,400			—			(114,400		)	—
Derivative instruments	—			8,827			—			—			8,827
Other noncurrent liabilities	—			211,316			184,591			—			395,907
Total noncurrent liabilities	7,556,496			334,543			2,272,446			(114,400		)	10,049,085

Unitholders’ capital:
Units issued and outstanding	5,845,694			4,833,310			2,493,923			(7,318,200		)	5,854,727
Accumulated income (deficit)	(693,604		)	1,083,629			138,733			(1,222,362		)	(693,604		)
	5,152,090			5,916,939			2,632,656			(8,540,562		)	5,161,123
Total liabilities and unitholders’ capital	$	12,786,181		$	10,919,721		$	5,270,345		$	(12,707,583	)	$	16,268,664

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2013



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	52		$	1,078		$	51,041		$	—		$	52,171
Accounts receivable – trade, net	—			365,347			122,855			—			488,202
Accounts receivable – affiliates	4,212,348			16,950			—			(4,229,298		)	—
Derivative instruments	—			170,534			5,596			—			176,130
Other current assets	330			68,274			30,833			—			99,437
Total current assets	4,212,730			622,183			210,325			(4,229,298		)	815,940

Noncurrent assets:
Oil and natural gas properties (successful efforts method)	—			13,074,900			4,813,659			—			17,888,559
Less accumulated depletion and amortization	—			(3,535,890		)	(10,394		)	—			(3,546,284		)
	—			9,539,010			4,803,265			—			14,342,275

Other property and equipment	—			564,756			83,126			—			647,882
Less accumulated depreciation	—			(110,706		)	(233		)	—			(110,939		)
	—			454,050			82,893			—			536,943

Derivative instruments	—			679,491			2,511			—			682,002
Notes receivable – affiliates	86,200			—			—			(86,200		)	—
Investments in consolidated subsidiaries	8,433,290			—			—			(8,433,290		)	—
Other noncurrent assets, net	108,785			10,968			8,051			—			127,804
	8,628,275			690,459			10,562			(8,519,490		)	809,806
Total noncurrent assets	8,628,275			10,683,519			4,896,720			(8,519,490		)	15,689,024
Total assets	$	12,841,005		$	11,305,702		$	5,107,045		$	(12,748,788	)	$	16,504,964

LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	14,529		$	587,774		$	247,321		$	—		$	849,624
Accounts payable – affiliates	—			4,212,348			16,950			(4,229,298		)	—
Derivative instruments	—			7,783			20,393			—			28,176
Other accrued liabilities	75,071			59,311			28,993			—			163,375
Current portion of long-term debt	—			—			211,558			—			211,558
Total current liabilities	89,600			4,867,216			525,215			(4,229,298		)	1,252,733

Noncurrent liabilities:
Credit facilities	1,560,000			—			1,173,175			—			2,733,175
Term loan	500,000			—			—			—			500,000
Senior notes, net	4,809,055			—			916,428			—			5,725,483
Notes payable – affiliates	—			86,200			—			(86,200		)	—
Derivative instruments	—			—			4,649			—			4,649
Other noncurrent liabilities	—			205,406			192,091			—			397,497
Total noncurrent liabilities	6,869,055			291,606			2,286,343			(86,200		)	9,360,804

Unitholders’ capital:
Units issued and outstanding	6,282,747			4,833,354			2,315,460			(7,139,737		)	6,291,824
Accumulated income (deficit)	(400,397		)	1,313,526			(19,973		)	(1,293,553		)	(400,397		)
	5,882,350			6,146,880			2,295,487			(8,433,290		)	5,891,427
Total liabilities and unitholders’ capital	$	12,841,005		$	11,305,702		$	5,107,045		$	(12,748,788	)	$	16,504,964

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended June 30, 2014



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	607,470		$	360,380		$	—		$	967,850
Losses on oil and natural gas derivatives	—			(383,226		)	(25,562		)	—			(408,788		)
Marketing revenues	—			17,839			12,434			—			30,273
Other revenues	—			7,607			9			—			7,616
	—			249,690			347,261			—			596,951
Expenses:
Lease operating expenses	—			91,547			93,354			—			184,901
Transportation expenses	—			37,371			7,483			—			44,854
Marketing expenses	—			13,549			9,725			—			23,274
General and administrative expenses	—			38,584			28,322			—			66,906
Exploration costs	—			1,551			—			—			1,551
Depreciation, depletion and amortization	—			196,682			77,753			—			274,435
Taxes, other than income taxes	—			45,052			23,479			—			68,531
Losses on sale of assets and other, net	—			1,210			4,257			—			5,467
	—			425,546			244,373			—			669,919
Other income and (expenses):
Interest expense, net of amounts capitalized	(111,603		)	789			(23,486		)	—			(134,300		)
Interest expense – affiliates	—			(1,859		)	—			1,859			—
Interest income – affiliates	1,859			—			—			(1,859		)	—
Equity in losses from consolidated subsidiaries	(96,084		)	—			—			96,084			—
Other, net	(2,042		)	(62		)	(445		)	—			(2,549		)
	(207,870		)	(1,132		)	(23,931		)	96,084			(136,849		)
Income (loss) before income taxes	(207,870		)	(176,988		)	78,957			96,084			(209,817		)
Income tax benefit	—			(1,896		)	(51		)	—			(1,947		)
Net income (loss)	$	(207,870	)	$	(175,092	)	$	79,008		$	96,084		$	(207,870	)

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended June 30, 2013



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary		Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	488,207		$	—	$	—		$	488,207
Gains on oil and natural gas derivatives	—			326,733			—		—			326,733
Marketing revenues	—			17,222			—		—			17,222
Other revenues	—			6,663			—		—			6,663
	—			838,825			—		—			838,825
Expenses:
Lease operating expenses	—			83,584			—		—			83,584
Transportation expenses	—			29,298			—		—			29,298
Marketing expenses	—			9,360			—		—			9,360
General and administrative expenses	—			46,305			—		—			46,305
Exploration costs	—			818			—		—			818
Depreciation, depletion and amortization	—			198,629			—		—			198,629
Impairment of long-lived assets	—			(14,851		)	—		—			(14,851		)
Taxes, other than income taxes	—			32,397			—		—			32,397
Gains on sale of assets and other, net	—			(959		)	—		—			(959		)
	—			384,581			—		—			384,581
Other income and (expenses):
Interest expense, net of amounts capitalized	(103,207		)	(640		)	—		—			(103,847		)
Interest expense – affiliates	—			(1,412		)	—		1,412			—
Interest income – affiliates	1,412			—			—		(1,412		)	—
Loss on extinguishment of debt	(4,187		)	—			—		—			(4,187		)
Equity in earnings from consolidated subsidiaries	453,288			—			—		(453,288		)	—
Other, net	(2,149		)	(33		)	—		—			(2,182		)
	345,157			(2,085		)	—		(453,288		)	(110,216		)
Income before income taxes	345,157			452,159			—		(453,288		)	344,028
Income tax benefit	—			(1,129		)	—		—			(1,129		)
Net income	$	345,157		$	453,288		$	—	$	(453,288	)	$	345,157

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Six Months Ended June 30, 2014



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	1,213,231		$	693,496		$	—		$	1,906,727
Losses on oil and natural gas derivatives	—			(628,184		)	(22,097		)	—			(650,281		)
Marketing revenues	—			33,570			27,249			—			60,819
Other revenues	—			13,280			(7		)	—			13,273
	—			631,897			698,641			—			1,330,538
Expenses:
Lease operating expenses	—			195,549			183,385			—			378,934
Transportation expenses	—			75,008			15,476			—			90,484
Marketing expenses	—			23,640			20,706			—			44,346
General and administrative expenses	—			74,321			71,813			—			146,134
Exploration costs	—			2,642			—			—			2,642
Depreciation, depletion and amortization	—			395,852			146,384			—			542,236
Taxes, other than income taxes	—			87,736			46,508			—			134,244
Losses on sale of assets and other, net	—			429			7,624			—			8,053
	—			855,177			491,896			—			1,347,073
Other income and (expenses):
Interest expense, net of amounts capitalized	(221,253		)	627			(47,487		)	—			(268,113		)
Interest expense – affiliates	—			(3,409		)	—			3,409			—
Interest income – affiliates	3,409			—			—			(3,409		)	—
Equity in losses from consolidated subsidiaries	(71,191		)	—			—			71,191			—
Other, net	(4,172		)	(46		)	(634		)	—			(4,852		)
	(293,207		)	(2,828		)	(48,121		)	71,191			(272,965		)
Income (loss) before income taxes	(293,207		)	(226,108		)	158,624			71,191			(289,500		)
Income tax expense (benefit)	—			3,789			(82		)	—			3,707
Net income (loss)	$	(293,207	)	$	(229,897	)	$	158,706		$	71,191		$	(293,207	)

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Six Months Ended June 30, 2013



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary		Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	950,939		$	—	$	—		$	950,939
Gains on oil and natural gas derivatives	—			218,363			—		—			218,363
Marketing revenues	—			27,074			—		—			27,074
Other revenues	—			11,509			—		—			11,509
	—			1,207,885			—		—			1,207,885
Expenses:
Lease operating expenses	—			172,305			—		—			172,305
Transportation expenses	—			56,481			—		—			56,481
Marketing expenses	—			16,734			—		—			16,734
General and administrative expenses	—			104,871			—		—			104,871
Exploration costs	—			3,044			—		—			3,044
Depreciation, depletion and amortization	—			396,070			—		—			396,070
Impairment of long-lived assets	—			42,202			—		—			42,202
Taxes, other than income taxes	—			72,068			—		—			72,068
Losses on sale of assets and other, net	724			1,489			—		—			2,213
	724			865,264			—		—			865,988
Other income and (expenses):
Interest expense, net of amounts capitalized	(204,064		)	(142		)	—		—			(204,206		)
Interest expense – affiliates	—			(2,554		)	—		2,554			—
Interest income – affiliates	2,554			—			—		(2,554		)	—
Loss on extinguishment of debt	(4,187		)	—			—		—			(4,187		)
Equity in earnings from consolidated subsidiaries	333,469			—			—		(333,469		)	—
Other, net	(3,776		)	(49		)	—		—			(3,825		)
	123,996			(2,745		)	—		(333,469		)	(212,218		)
Income before income taxes	123,272			339,876			—		(333,469		)	129,679
Income tax expense	—			6,407			—		—			6,407
Net income	$	123,272		$	333,469		$	—	$	(333,469	)	$	123,272

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2014



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(293,207	)	$	(229,897	)	$	158,706		$	71,191		$	(293,207	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	—			395,852			146,384			—			542,236
Unit-based compensation expenses	—			32,583			—			—			32,583
Amortization and write-off of deferred financing fees	11,694			—			(5,492		)	—			6,202
Losses on sale of assets and other, net	—			3,506			—			—			3,506
Equity in losses from consolidated subsidiaries	71,191			—			—			(71,191		)	—
Deferred income taxes	—			3,557			(82		)	—			3,475
Derivatives activities:
Total losses	—			628,184			22,097			—			650,281
Cash settlements	—			(12,651		)	(10,472		)	—			(23,123		)
Changes in assets and liabilities:
Increase in accounts receivable – trade, net	—			(27,597		)	(34,294		)	—			(61,891		)
(Increase) decrease in accounts receivable – affiliates	220,694			(9,964		)	—			(210,730		)	—
(Increase) decrease in other assets	(146		)	(8,287		)	1,486			—			(6,947		)
Increase in accounts payable and accrued expenses	2			111,675			1,905			—			113,582
Increase (decrease) in accounts payable and accrued expenses – affiliates	—			(220,694		)	9,964			210,730			—
Increase (decrease) in other liabilities	702			(26,291		)	(25,473		)	—			(51,062		)
Net cash provided by operating activities	10,930			639,976			264,729			—			915,635

Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			(25,891		)	—			—			(25,891		)
Development of oil and natural gas properties	—			(536,488		)	(269,129		)	—			(805,617		)
Purchases of other property and equipment	—			(25,786		)	(5,625		)	—			(31,411		)
Investment in affiliates	(178,463		)	—			—			178,463			—
Change in notes receivable with affiliate	(28,200		)	—			—			28,200			—
Proceeds from sale of properties and equipment and other	(12,983		)	1,253			—			—			(11,730		)
Net cash used in investing activities	(219,646		)	(586,912		)	(274,754		)	206,663			(874,649		)

Table of Contents

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	1,095,000			—			—			—			1,095,000
Repayments of debt	(410,000		)	—			(206,124		)	—			(616,124		)
Distributions to unitholders	(480,583		)	—			—			—			(480,583		)
Financing fees and other, net	1,263			(46,524		)	(10,866		)	—			(56,127		)
Change in notes payable with affiliate	—			28,200			—			(28,200		)	—
Capital contributions – affiliates	—			—			178,463			(178,463		)	—
Excess tax benefit from unit-based compensation	3,016			—			—			—			3,016
Net cash provided by (used in) financing activities	208,696			(18,324		)	(38,527		)	(206,663		)	(54,818		)

Net increase (decrease) in cash and cash equivalents	(20		)	34,740			(48,552		)	—			(13,832		)
Cash and cash equivalents:
Beginning	52			1,078			51,041			—			52,171
Ending	$	32		$	35,818		$	2,489		$	—		$	38,339

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 2013



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary		Eliminations			Consolidated
	(in thousands)
Cash flow from operating activities:
Net income	$	123,272		$	333,469		$	—	$	(333,469	)	$	123,272
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	—			396,070			—		—			396,070
Impairment of long-lived assets	—			42,202			—		—			42,202
Unit-based compensation expenses	—			19,575			—		—			19,575
Loss on extinguishment of debt	4,187			—			—		—			4,187
Amortization and write-off of deferred financing fees	10,905			—			—		—			10,905
Losses on sale of assets and other, net	—			16,814			—		—			16,814
Equity in earnings from consolidated subsidiaries	(333,469		)	—			—		333,469			—
Deferred income taxes	—			5,725			—		—			5,725
Derivatives activities:
Total gains	—			(218,363		)	—		—			(218,363		)
Cash settlements	—			144,502			—		—			144,502
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net	—			36,174			—		—			36,174
Decrease in accounts receivable – affiliates	366,386			—			—		(366,386		)	—
(Increase) decrease in other assets	(100		)	2,360			—		—			2,260
Decrease in accounts payable and accrued expenses	—			(5,319		)	—		—			(5,319		)
Decrease in accounts payable and accrued expenses – affiliates	—			(366,386		)	—		366,386			—
Increase (decrease) in other liabilities	771			(17,419		)	—		—			(16,648		)
Net cash provided by operating activities	171,952			389,404			—		—			561,356

Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			(64,381		)	—		—			(64,381		)
Development of oil and natural gas properties	—			(495,899		)	—		—			(495,899		)
Purchases of other property and equipment	—			(55,147		)	—		—			(55,147		)
Change in notes receivable with affiliate	(27,400		)	—			—		27,400			—
Proceeds from sale of properties and equipment and other	(8,409		)	219,308			—		—			210,899
Net cash used in investing activities	(35,809		)	(396,119		)	—		27,400			(404,528		)

Table of Contents

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	775,000			—			—		—			775,000
Repayments of debt	(560,737		)	—			—		—			(560,737		)
Distributions to unitholders	(341,117		)	—			—		—			(341,117		)
Financing fees and other, net	(9,366		)	(21,290		)	—		—			(30,656		)
Change in notes payable with affiliate	—			27,400			—		(27,400		)	—
Excess tax benefit from unit-based compensation	—			591			—		—			591
Net cash provided by (used in) financing activities	(136,220		)	6,701			—		(27,400		)	(156,919		)

Net decrease in cash and cash equivalents	(77		)	(14		)	—		—			(91		)
Cash and cash equivalents:
Beginning	107			1,136			—		—			1,243
Ending	$	30		$	1,122		$	—	$	—		$	1,152

Note 16 – SEC Inquiry

As disclosed on July 1, 2013, the Company and its affiliate, LinnCo, have been notified by the staff of the SEC that its Fort Worth Regional Office has commenced an inquiry regarding LINN Energy and LinnCo (the “SEC inquiry”). The SEC staff is investigating whether any violations of federal securities laws have occurred. The SEC staff has stated that the fact of the inquiry should not be construed as an indication that the SEC or its staff has a negative view of any entity, individual or security. Both LINN Energy and LinnCo are cooperating fully with the SEC in this matter. LINN Energy and LinnCo are unable to predict the timing or outcome of the SEC inquiry or estimate the nature or amount of any possible sanction the SEC could seek to impose, which could include a fine, penalty, or court or administrative order prohibiting specific conduct, or a potential restatement of LINN Energy’s or LinnCo’s financial statements, any of which could be material. No provision for losses has been recorded for this exposure.

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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” 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, 2013, 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, 2013. 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, including those acquired in the acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”), are located in seven operating regions in the United States (“U.S.”):


•	Mid-Continent, which includes properties in Oklahoma, Louisiana and the eastern portion of the Texas Panhandle (including the Granite Wash and Cleveland horizontal plays);


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


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


•	California, which includes the San Joaquin Valley Basin and the Los Angeles Basin;


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


•	Michigan/Illinois, which includes the Antrim Shale formation in the northern part of Michigan and oil properties in southern Illinois; and


•	East Texas, which includes properties located in east Texas.

Results for the three months ended June 30, 2014, included the following:


•	oil, natural gas and NGL sales of approximately $968 million compared to $488 million for the second quarter of 2013;


•	average daily production of approximately 1,131 MMcfe/d compared to 780 MMcfe/d for the second quarter of 2013;


•	net loss of approximately $208 million compared to net income of $345 million for the second quarter of 2013;


•	capital expenditures, excluding acquisitions, of approximately $407 million compared to $334 million for the second quarter of 2013; and


•	268 wells drilled (all successful) compared to 145 wells drilled (all successful) for the second quarter of 2013.

Results for the six months ended June 30, 2014, included the following:


•	oil, natural gas and NGL sales of approximately $1.9 billion compared to $951 million for the six months ended June 30, 2013;


•	average daily production of approximately 1,117 MMcfe/d compared to 788 MMcfe/d for the six months ended June 30, 2013;


•	net loss of approximately $293 million compared to net income of $123 million for the six months ended June 30, 2013;


•	net cash provided by operating activities of approximately $916 million compared to $561 million for the six months ended June 30, 2013;


•	capital expenditures, excluding acquisitions, of approximately $816 million compared to $606 million for the six months ended June 30, 2013; and


•	468 wells drilled (467 successful) compared to 258 wells drilled (all successful) for the six months ended June 30, 2013.

Table of Contents


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

Properties Exchange – Pending

Acquisitions and Divestiture – Pending

On July 24, 2014, the Company, through one of its wholly owned subsidiaries, entered into a definitive purchase and sale agreement to sell its interests in certain oil and natural gas properties located in the Mid-Continent region for a purchase price of approximately $90 million, subject to closing adjustments. The sale is anticipated to close in the fourth quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. The Company plans to use the net proceeds from the sale to repay borrowings under the LINN Credit Facility.

Financing and Liquidity

On May 30, 2014, in accordance with the provisions of the indenture related to Berry’s 10.25% senior notes due June 2014 (the “Berry June 2014 Senior Notes”), the Company paid in full the remaining outstanding principal amount of approximately $205 million.

On March 22, 2013, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the 6.25% senior notes due November 2019 (the “November 2019 Senior Notes”), except that the transfer restrictions, registration rights and additional interest provisions relating to the outstanding November 2019 Senior Notes do not apply to the new November 2019 Senior Notes. On June 2, 2014, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $1.8 billion outstanding principal amount of November 2019 Senior Notes for an equal amount of new November 2019 Senior Notes. The exchange offer expired on June 28, 2014.

Table of Contents


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

Results of Operations

Three Months Ended June 30, 2014, Compared to Three Months Ended June 30, 2013



	Three Months Ended June 30,
	2014			2013			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	205,050		$	160,766		$	44,284
Oil sales	651,509			261,912			389,597
NGL sales	111,291			65,529			45,762
Total oil, natural gas and NGL sales	967,850			488,207			479,643
Gains (losses) on oil and natural gas derivatives	(408,788		)	326,733			(735,521		)
Marketing and other revenues	37,889			23,885			14,004
	596,951			838,825			(241,874		)
Expenses:
Lease operating expenses	184,901			83,584			101,317
Transportation expenses	44,854			29,298			15,556
Marketing expenses	23,274			9,360			13,914
General and administrative expenses ⁽¹⁾	66,906			46,305			20,601
Exploration costs	1,551			818			733
Depreciation, depletion and amortization	274,435			198,629			75,806
Impairment of long-lived assets	—			(14,851		)	14,851
Taxes, other than income taxes	68,531			32,397			36,134
(Gains) losses on sale of assets and other, net	5,467			(959		)	6,426
	669,919			384,581			285,338
Other income and (expenses)	(136,849		)	(110,216		)	(26,633		)
Income (loss) before income taxes	(209,817		)	344,028			(553,845		)
Income tax benefit	(1,947		)	(1,129		)	(818		)
Net income (loss)	$	(207,870	)	$	345,157		$	(553,027	)


⁽¹⁾	General and administrative expenses for the three months ended June 30, 2014, and June 30, 2013, include approximately $9 million and $7 million, respectively, of noncash unit-based compensation expenses.

Table of Contents


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



	Three Months Ended June 30,
	2014		2013		Variance
Average daily production:
Natural gas (MMcf/d)	493		429		15	%
Oil (MBbls/d)	74.5		31.5		137	%
NGL (MBbls/d)	31.8		27.0		18	%
Total (MMcfe/d)	1,131		780		45	%

Weighted average prices: ⁽¹⁾
Natural gas (Mcf)	$	4.57	$	4.12	11	%
Oil (Bbl)	$	96.06	$	91.27	5	%
NGL (Bbl)	$	38.42	$	26.69	44	%

Average NYMEX prices:
Natural gas (MMBtu)	$	4.67	$	4.09	14	%
Oil (Bbl)	$	102.99	$	94.22	9	%

Costs per Mcfe of production:
Lease operating expenses	$	1.80	$	1.18	53	%
Transportation expenses	$	0.44	$	0.41	7	%
General and administrative expenses ⁽²⁾	$	0.65	$	0.65	—
Depreciation, depletion and amortization	$	2.67	$	2.80	(5	)%
Taxes, other than income taxes	$	0.67	$	0.46	46	%


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


⁽²⁾	General and administrative expenses for the three months ended June 30, 2014, and June 30, 2013, include approximately $9 million and $7 million, respectively, of noncash unit-based compensation expenses.

Table of Contents


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 increased approximately $480 million or 98% to approximately $968 million for the three months ended June 30, 2014, from approximately $488 million for the three months ended June 30, 2013, due to higher production volumes and higher NGL, oil and natural gas prices. Higher NGL, oil and natural gas prices resulted in an increase in revenues of approximately $34 million, $33 million and $20 million, respectively.

Average daily production volumes increased to approximately 1,131 MMcfe/d for the three months ended June 30, 2014, from 780 MMcfe/d for the three months ended June 30, 2013. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $357 million, $24 million and $12 million, respectively.

The following table sets forth average daily production by region:



	Three Months Ended June 30,
	2014	2013	Variance
Average daily production (MMcfe/d):
Mid-Continent	297	315	(18	)	(6	)%
Rockies	278	173	105		61	%
Permian Basin	169	84	85		101	%
California	172	13	159		1,262	%
Hugoton Basin	151	140	11		8	%
Michigan/Illinois	33	33	—		—
East Texas	31	22	9		41	%
	1,131	780	351		45	%

The decrease in average daily production volumes in the Mid-Continent region primarily reflects a reduction of approximately 9 MMcfe/d of production volumes related to the sale of the Panther Operated Cleveland Properties on May 31, 2013, and decreased development capital spending in the Granite Wash. The increase in average daily production volumes in the Rockies region primarily reflects the impact of the Berry acquisition in December 2013 and development capital spending. The increase in average daily production volumes in the Permian Basin region primarily reflects the impact of an acquisition in October 2013, the Berry acquisition and development capital spending. The increase in average daily production volumes in the California and East Texas regions primarily reflects the impact of the Berry acquisition. The increase in average daily production volumes in the Hugoton Basin region primarily reflects development capital spending. The Michigan/Illinois region consists of a low-decline asset base and continues to produce at consistent levels.

Gains (Losses) on Oil and Natural Gas Derivatives

Losses on oil and natural gas derivatives were approximately $409 million for the three months ended June 30, 2014, compared to gains of approximately $327 million for the three months ended June 30, 2013, representing a variance of approximately $736 million. Losses on oil and natural gas derivatives were primarily due to changes in fair value on unsettled derivative contracts and lower cash settlements during the period. The results for 2014 and 2013 also include gains of approximately $3 million and $5 million, respectively, related to the recoveries of a bankruptcy claim (see Note 10). 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 June 30, 2014, the Company had commodity derivative contracts for approximately 98% of its natural gas production and 92% of its oil production. During the three months ended June 30, 2013, the Company had commodity derivative contracts for approximately 111% of its natural gas production and 130% of its oil production.

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” in “Liquidity and Capital Resources” below.

Table of Contents


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

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 $14 million or 59% to approximately $38 million for the three months ended June 30, 2014, from approximately $24 million for the three months ended June 30, 2013, primarily due to electricity sales revenues generated from the Company’s California cogeneration facilities acquired and certain contracts assumed in the Berry acquisition in December 2013, as well as higher revenues generated from the Jayhawk natural gas processing plant.

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 increased by approximately $101 million or 121% to approximately $185 million for the three months ended June 30, 2014, from approximately $84 million for the three months ended June 30, 2013. Lease operating expenses increased primarily due to costs associated with properties acquired in the Berry acquisition. Lease operating expenses per Mcfe also increased to $1.80 per Mcfe for the three months ended June 30, 2014, from $1.18 per Mcfe for the three months ended June 30, 2013, primarily due to higher rates on newly acquired oil properties.

Transportation Expenses

Transportation expenses increased by approximately $16 million or 53% to approximately $45 million for the three months ended June 30, 2014, from approximately $29 million for the three months ended June 30, 2013, primarily due to the Berry acquisition.

Marketing Expenses

Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $14 million or 149% to approximately $23 million for the three months ended June 30, 2014, from approximately $9 million for the three months ended June 30, 2013, primarily due to electricity generation expenses incurred from the Company’s California cogeneration facilities acquired and certain contracts assumed in the Berry acquisition, as well as higher expenses associated with the Jayhawk natural gas processing plant.

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 increased by approximately $21 million or 45% to approximately $67 million for the three months ended June 30, 2014, from approximately $46 million for the three months ended June 30, 2013. The increase was primarily due to higher salaries and benefits related expenses, primarily driven by increased employee headcount and unit-based compensation, higher professional services expenses and higher various other administrative expenses partially offset by lower non-payroll related acquisition expenses. Although general and administrative expenses increased, the unit rate remained consistent at $0.65 per Mcfe for the three months ended June 30, 2014, and 2013.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $75 million or 38% to approximately $274 million for the three months ended June 30, 2014, from approximately $199 million for the three months ended June 30, 2013. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per Mcfe decreased to $2.67 per Mcfe for the three months ended June 30, 2014, from $2.80 per Mcfe for the three months ended June 30, 2013.

Impairment of Long-Lived Assets

The Company recorded no impairment charge for the three months ended June 30, 2014. During the three months ended June 30, 2013, the Company recorded an adjustment of approximately $15 million to reduce the initial impairment charge recorded in March 2013 to reflect the fair value less costs to sell the Panther Operated Cleveland Properties sold in May 2013 (see Note 2). At March 31, 2013, the carrying value of the Panther Operated Cleveland Properties was reduced to fair value less costs to sell resulting in an impairment charge of approximately $57 million and the properties were classified as “assets held for sale.”

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

Taxes, Other Than Income Taxes



	Three Months Ended June 30,
	2014		2013		Variance
	(in thousands)

Severance taxes	$	35,765	$	22,736	$	13,029
Ad valorem taxes	28,046		9,476		18,570
California carbon allowances	4,607		178		4,429
Other	113		7		106
	$	68,531	$	32,397	$	36,134

Taxes, other than income taxes increased by approximately $36 million or 112% for the three months ended June 30, 2014, compared to the three months ended June 30, 2013. Severance taxes, which are a function of revenues generated from production, increased primarily due to higher production volumes and higher NGL, oil and natural gas prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, as well as California carbon allowances, increased primarily due to the Berry acquisition.

Other Income and (Expenses)



	Three Months Ended June 30,
	2014			2013			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(134,300	)	$	(103,847	)	$	(30,453	)
Loss on extinguishment of debt	—			(4,187		)	4,187
Other, net	(2,549		)	(2,182		)	(367		)
	$	(136,849	)	$	(110,216	)	$	(26,633	)

Other income and (expenses) increased by approximately $27 million for the three months ended June 30, 2014, compared to the three months ended June 30, 2013. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with amendments made to the Company’s Credit Facilities during 2013 and 2014. In addition, for the three months ended June 30, 2013, the Company recorded a loss on extinguishment of debt of approximately $4 million as a result of the redemption of the remaining outstanding 2017 Senior Notes. See “Debt” in “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 $2 million and $1 million for the three months ended June 30, 2014, and June 30, 2013, respectively. Income tax benefit increased primarily due to lower income from the Company’s taxable subsidiaries during the three months ended June 30, 2014, compared to the same period in 2013.

Net Income (Loss)

Net income decreased by approximately $553 million to a net loss of approximately $208 million for the three months ended June 30, 2014, from net income of approximately $345 million for the three months ended June 30, 2013. The decrease was primarily due to higher losses on oil and natural gas derivatives and higher expenses, including interest, partially offset by higher production revenues. See discussions above for explanations of variances.

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

Results of Operations

Six Months Ended June 30, 2014, Compared to Six Months Ended June 30, 2013



	Six Months Ended June 30,
	2014			2013			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	431,739		$	295,510		$	136,229
Oil sales	1,247,154			503,710			743,444
NGL sales	227,834			151,719			76,115
Total oil, natural gas and NGL sales	1,906,727			950,939			955,788
Gains (losses) on oil and natural gas derivatives	(650,281		)	218,363			(868,644		)
Marketing and other revenues	74,092			38,583			35,509
	1,330,538			1,207,885			122,653
Expenses:
Lease operating expenses	378,934			172,305			206,629
Transportation expenses	90,484			56,481			34,003
Marketing expenses	44,346			16,734			27,612
General and administrative expenses ⁽¹⁾	146,134			104,871			41,263
Exploration costs	2,642			3,044			(402		)
Depreciation, depletion and amortization	542,236			396,070			146,166
Impairment of long-lived assets	—			42,202			(42,202		)
Taxes, other than income taxes	134,244			72,068			62,176
Losses on sale of assets and other, net	8,053			2,213			5,840
	1,347,073			865,988			481,085
Other income and (expenses)	(272,965		)	(212,218		)	(60,747		)
Income (loss) before income taxes	(289,500		)	129,679			(419,179		)
Income tax expense	3,707			6,407			(2,700		)
Net income (loss)	$	(293,207	)	$	123,272		$	(416,479	)


⁽¹⁾	General and administrative expenses for the six months ended June 30, 2014, and June 30, 2013, include approximately $28 million and $17 million, respectively, of noncash unit-based compensation expenses.

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



	Six Months Ended June 30,
	2014		2013		Variance
Average daily production:
Natural gas (MMcf/d)	487		436		12	%
Oil (MBbls/d)	72.9		30.8		137	%
NGL (MBbls/d)	32.2		27.8		16	%
Total (MMcfe/d)	1,117		788		42	%

Weighted average prices: ⁽¹⁾
Natural gas (Mcf)	$	4.90	$	3.75	31	%
Oil (Bbl)	$	94.55	$	90.23	5	%
NGL (Bbl)	$	39.14	$	30.12	30	%

Average NYMEX prices:
Natural gas (MMBtu)	$	4.80	$	3.71	29	%
Oil (Bbl)	$	100.84	$	94.30	7	%

Costs per Mcfe of production:
Lease operating expenses	$	1.87	$	1.21	55	%
Transportation expenses	$	0.45	$	0.40	13	%
General and administrative expenses ⁽²⁾	$	0.72	$	0.74	(3	)%
Depreciation, depletion and amortization	$	2.68	$	2.78	(4	)%
Taxes, other than income taxes	$	0.66	$	0.51	29	%


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


⁽²⁾	General and administrative expenses for the six months ended June 30, 2014, and June 30, 2013, include approximately $28 million and $17 million, respectively, of noncash unit-based compensation expenses.

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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 increased approximately $956 million or 101% to approximately $1.9 billion for the six months ended June 30, 2014, from approximately $951 million for the six months ended June 30, 2013, due to higher production volumes and higher natural gas, oil and NGL prices. Higher natural gas, oil and NGL prices resulted in an increase in revenues of approximately $101 million, $57 million and $52 million, respectively.

Average daily production volumes increased to 1,117 MMcfe/d for the six months ended June 30, 2014, from 788 MMcfe/d for the six months ended June 30, 2013. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $687 million, $35 million and $24 million, respectively.

The following sets forth average daily production by region:



	Six Months Ended June 30,
	2014	2013	Variance
Average daily production (MMcfe/d):
Mid-Continent	300	321	(21	)	(7	)%
Rockies	275	177	98		55	%
Permian Basin	167	82	85		104	%
California	164	12	152		1,214	%
Hugoton Basin	147	141	6		4	%
Michigan/Illinois	33	34	(1	)	(2	)%
East Texas	31	21	10		46	%
	1,117	788	329		42	%

The decrease in average daily production volumes in the Mid-Continent region primarily reflects a reduction of approximately 14 MMcfe/d of production volumes related to the sale of the Panther Operated Cleveland Properties on May 31, 2013, and decreased development capital spending in the Granite Wash. The increase in average daily production volumes in the Rockies region primarily reflects the impact of the Berry acquisition in December 2013 and development capital spending. The increase in average daily production volumes in the Permian Basin region primarily reflects the impact of an acquisition in October 2013, the Berry acquisition and development capital spending. The increase in average daily production volumes in the California and East Texas regions primarily reflects the impact of the Berry acquisition. The increase in average daily production volumes in the Hugoton Basin region primarily reflects development capital spending. The Michigan/Illinois region consists of a low-decline asset base and continues to produce at consistent levels.

Gains (Losses) on Oil and Natural Gas Derivatives

Losses on oil and natural gas derivatives were approximately $650 million for the six months ended June 30, 2014, compared to gains of approximately $218 million for the six months ended June 30, 2013, representing a variance of approximately $868 million. Losses on oil and natural gas derivatives were primarily due to changes in fair value on unsettled derivatives contracts and lower cash settlements during the period. The results for 2014 and 2013 also include gains of approximately $3 million and $5 million, respectively, related to the recoveries of a bankruptcy claim (see Note 10). 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 six months ended June 30, 2014, the Company had commodity derivative contracts for approximately 100% of its natural gas production and 94% of its oil production. During the six months ended June 30, 2013, the Company had commodity derivative contracts for approximately 109% of its natural gas production and 133% of its oil production.

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

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 $35 million or 92% to approximately $74 million for the six months ended June 30, 2014, from approximately $39 million for the six months ended June 30, 2013, primarily due to electricity sales revenues generated by the Company’s California cogeneration facilities acquired and certain contracts assumed in the Berry acquisition in December 2013, as well as higher revenues generated from the Jayhawk natural gas processing plant.

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 increased by approximately $207 million or 120% to approximately $379 million for the six months ended June 30, 2014, from approximately $172 million for the six months ended June 30, 2013. Lease operating expenses increased primarily due to costs associated with properties acquired in the Berry acquisition. Lease operating expenses per Mcfe also increased to $1.87 per Mcfe for the six months ended June 30, 2014, from $1.21 per Mcfe for the six months ended June 30, 2013, primarily due to higher rates on newly acquired oil properties.

Transportation Expenses

Transportation expenses increased by approximately $34 million or 60% to approximately $90 million for the six months ended June 30, 2014, from approximately $56 million for the six months ended June 30, 2013, primarily due to the Berry acquisition.

Marketing Expenses

Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $27 million or 165% to approximately $44 million for the six months ended June 30, 2014, from approximately $17 million for the six months ended June 30, 2013, primarily due to electricity generation expenses incurred from the Company’s California cogeneration facilities acquired and certain contracts assumed in the Berry acquisition, as well as higher expenses associated with the Jayhawk natural gas processing plant.

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 increased by approximately $41 million or 39% to approximately $146 million for the six months ended June 30, 2014, from approximately $105 million for the six months ended June 30, 2013. The increase was primarily due to higher salaries and benefits related expenses, primarily driven by increased employee headcount and unit-based compensation, higher professional services expenses and higher various other administrative expenses partially offset by lower non-payroll related acquisition expenses. Although general and administrative expenses increased, the unit rate decreased slightly to $0.72 per Mcfe for the six months ended June 30, 2014, from $0.74 per Mcfe for the six months ended June 30, 2013.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $146 million or 37% to approximately $542 million for the six months ended June 30, 2014, from approximately $396 million for the six months ended June 30, 2013. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per Mcfe decreased to $2.68 per Mcfe for the six months ended June 30, 2014, from $2.78 per Mcfe for the six months ended June 30, 2013.

Impairment of Long-Lived Assets

The Company recorded no impairment charge for the six months ended June 30, 2014. During the six months ended June 30, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $42 million associated with the write-down of the carrying value of the Panther Operated Cleveland Properties sold in May 2013 (see Note 2).

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

Taxes, Other Than Income Taxes



	Six Months Ended June 30,
	2014		2013		Variance
	(in thousands)

Severance taxes	$	67,881	$	43,388	$	24,493
Ad valorem taxes	57,122		28,484		28,638
California carbon allowances	9,126		178		8,948
Other	115		18		97
	$	134,244	$	72,068	$	62,176

Taxes, other than income taxes increased by approximately $62 million or 86% for the six months ended June 30, 2014, compared to the six months ended June 30, 2013. Severance taxes, which are a function of revenues generated from production, increased primarily due to higher production volumes and higher natural gas, oil and NGL prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, as well as California carbon allowances, increased primarily due to the Berry acquisition.

Other Income and (Expenses)



	Six Months Ended June 30,
	2014			2013			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(268,113	)	$	(204,206	)	$	(63,907	)
Loss on extinguishment of debt	—			(4,187		)	4,187
Other, net	(4,852		)	(3,825		)	(1,027		)
	$	(272,965	)	$	(212,218	)	$	(60,747	)

Other income and (expenses) increased by approximately $61 million for the six months ended June 30, 2014, compared to the six months ended June 30, 2013. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with amendments made to the Company’s Credit Facilities during 2013 and 2014. In addition, for the six months ended June 30, 2013, the Company recorded a loss on extinguishment of debt of approximately $4 million as a result of the redemption of the remaining outstanding 2017 Senior Notes. See “Debt” in “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 income tax expense of approximately $4 million and $6 million for the six months ended June 30, 2014, and June 30, 2013, respectively. Income tax expense decreased primarily due to lower income from the Company’s taxable subsidiaries during the six months ended June 30, 2014, compared to the same period in 2013.

Net Income (Loss)

Net income decreased by approximately $416 million to a net loss of approximately $293 million for the six months ended June 30, 2014, from net income of approximately $123 million for the six months ended June 30, 2013. The decrease was primarily due to higher losses on oil and natural gas derivatives and higher expenses, including interest, partially offset by higher production revenues. See discussions above for explanations of variances.

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

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 six months ended June 30, 2014, the Company’s total capital expenditures, excluding acquisitions, were approximately $816 million. For 2014, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $1.6 billion, including approximately $1.55 billion related to its oil and natural gas capital program and approximately $35 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 these capital expenditures primarily with net cash provided by operating activities and bank borrowings. At June 30, 2014, there was approximately $1.8 billion of available borrowing capacity under the Company’s Credit Facilities but less than $1 million available under the Berry Credit Facility.

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 has secured $2.3 billion of committed interim financing for the pending acquisition of oil and natural gas properties from Devon, subject to final documentation. The acquisition is intended to be financed ultimately through the sale of the Company’s Granite Wash assets as well as certain non-producing acreage in its portfolio. 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:



	Six Months Ended June 30,
	2014			2013			Variance
	(in thousands)
Net cash:
Provided by operating activities	$	915,635		$	561,356		$	354,279
Used in investing activities	(874,649		)	(404,528		)	(470,121		)
Used in financing activities	(54,818		)	(156,919		)	102,101
Net decrease in cash and cash equivalents	$	(13,832	)	$	(91	)	$	(13,741	)

Operating Activities

Cash provided by operating activities for the six months ended June 30, 2014, was approximately $916 million, compared to approximately $561 million for the six months ended June 30, 2013. The increase was primarily due to higher production related revenues principally due to increased production volumes and higher commodity prices, partially offset by higher expenses and lower cash settlements on derivatives.

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

Investing Activities

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



	Six Months Ended June 30,
	2014			2013
	(in thousands)
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	$	(25,891	)	$	(64,381	)
Capital expenditures	(837,028		)	(551,046		)
Proceeds from sale of properties and equipment and other	(11,730		)	210,899
	$	(874,649	)	$	(404,528	)

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 increased primarily due to development activities of properties in the Rockies, California and Permian Basin regions.

Financing Activities

Cash used in financing activities for the six months ended June 30, 2014, was approximately $55 million, compared to approximately $157 million for the six months ended June 30, 2013. The decrease in net cash used in financing activities was primarily attributable to higher net borrowings partially offset by higher distributions to unitholders during the six months ended June 30, 2014. The following provides a comparative summary of proceeds from borrowings and repayments of debt:



	Six Months Ended June 30,
	2014			2013
	(in thousands)
Proceeds from borrowings:
LINN Credit Facility	$	1,095,000		$	775,000
Repayments of debt:
LINN Credit Facility	$	(410,000	)	$	(520,000	)
Senior notes	(206,124		)	(40,737		)
	$	(616,124	)	$	(560,737	)

Debt

As of June 30, 2014, the Company was in compliance with all financial and other covenants of its Credit Facilities. If an event of default would occur and were continuing, the Company would be unable to make borrowings and its financial condition and liquidity would be adversely affected. For information related to the Credit Facilities, see Note 6.

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

The Company depends, in part, on its Credit Facilities for future capital needs. At June 30, 2014, there was approximately $1.8 billion of available borrowing capacity under the Company’s Credit Facilities but less than $1 million available under the Berry Credit Facility. 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. If an event of default occurs and is continuing under the Credit Facilities, the Company would be unable to make borrowings to fund distributions. For additional information, see “Distribution Practices” below.

Upon the amendment of the LINN Credit Facility in April 2014, the $500 million senior secured term loan’s maturity was also extended from April 2018 to April 2019.

In February 2014, in accordance with the indentures related to Berry’s senior notes, the Company repurchased through cash tender offers $321,000, $30,000 and $837,000 of Berry’s June 2014 Senior Notes, November 2020 Senior Notes and September 2022 Senior Notes, respectively.

The Company plans to file Berry’s stand-alone financial statements with the Securities and Exchange Commission at a later date.

On March 22, 2013, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the November 2019 Senior Notes, except that the transfer restrictions, registration rights and additional interest provisions relating to the outstanding November 2019 Senior Notes do not apply to the new November 2019 Senior Notes. On June 2, 2014, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $1.8 billion outstanding principal amount of November 2019 Senior Notes for an equal amount of new November 2019 Senior Notes. The exchange offer expired on June 28, 2014.

The Company has secured $2.3 billion of committed interim financing for the pending acquisition of oil and natural gas properties from Devon, subject to final documentation. The acquisition is intended to be financed ultimately through the sale of the Company’s Granite Wash assets as well as certain non-producing acreage in its portfolio.

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

Distributions



Date Paid	Distributions Per Unit		Total Distributions
			(in millions)

June 2014	$	0.2416	$	80
May 2014	$	0.2416	$	80
April 2014	$	0.2416	$	80
March 2014	$	0.2416	$	80
February 2014	$	0.2416	$	80
January 2014	$	0.2416	$	80

On July 1, 2014, the Company’s Board of Directors declared a cash distribution of $0.725 per unit with respect to the second quarter of 2014, to be paid in three equal installments of $0.2416 per unit. The first monthly distribution with respect to the second quarter of 2014, totaling approximately $80 million, was paid on July 16, 2014, to unitholders of record as of the close of business on July 11, 2014.

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 2013 Annual Report on Form 10-K. With the exceptions of: (i) the Company’s payment of the remaining outstanding principal amount of the Berry June 2014 Senior Notes; (ii) an amendment to the LINN Credit Facility and term loan that extended the maturity dates from April 2018 to April 2019; and (iii) an amendment to the Berry Credit Facility that extended the maturity date from May 2016 to April 2019, there have been no significant changes to the Company’s contractual obligations from December 31, 2013. See Note 6 for additional information about the Company’s debt instruments.

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. To date in 2014, the Company’s Board of Directors has considered past shortfalls and the current excess of net cash provided by operating activities after distributions and discretionary adjustments as well as forecasts of expected future net cash provided by operating activities and has decided

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

to maintain the distribution at its current level. 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.

The Company intends 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. The Company funds premiums paid for derivatives, acquisitions and other capital expenditures 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 operating cash flows and may be used to fund distributions. 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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands)

Net cash provided by operating activities	$	481,153		$	226,762		$	915,635		$	561,356
Distributions to unitholders	(240,510		)	(170,163		)	(480,583		)	(341,117		)
Excess of net cash provided by operating activities after distributions to unitholders	240,643			56,599			435,052			220,239
Discretionary adjustments considered by the Board of Directors:
Discretionary reductions for a portion of oil and natural gas development costs ⁽¹⁾	(199,448		)	(111,912		)	(392,868		)	(222,210		)
Cash recoveries of bankruptcy claim ⁽²⁾	(2,913		)	(5,073		)	(2,913		)	(5,073		)
Cash paid for acquisitions or divestitures – revenues less operating expenses ⁽³⁾	—			(6,790		)	—			(6,790		)
Provision for legal matters ⁽⁴⁾	2,400			—			1,598			—
Changes in operating assets and liabilities and other, net ⁽⁵⁾	(8,626		)	49,132			(11,806		)	(24,630		)
Excess (shortfall) of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors ⁽⁶⁾	$	32,056		$	(18,044	)	$	29,063		$	(38,464	)

⁽¹⁾

Represent discretionary reductions for a portion of oil and natural gas development costs, an estimated component of total development costs, which are amounts established by the Board of Directors at the end of each year for the following year, allocated across four quarters, that are 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.

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

See below for total development of oil and natural gas properties as presented in the statements of cash flows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands)

Total development of oil and natural gas properties	$	410,774	$	260,095	$	805,617	$	495,899


⁽²⁾	Represent the recoveries of a bankruptcy claim against Lehman Brothers which was not a transaction occurring in the ordinary course of the Company’s business.

⁽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 is retained by the Company for future operations, future capital expenditures, future debt service or other future obligations. Any shortfall is 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 and is not currently being distributed to LINN Energy for further distribution to its unitholders. 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 $266 million at June 30, 2014, 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 June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands)

Net cash provided by operating activities	$	481,153		$	226,762		$	915,635		$	561,356
Distributions to unitholders	(240,510		)	(170,163		)	(480,583		)	(341,117		)
Excess of net operating cash flow after distributions to unitholders	240,643			56,599			435,052			220,239
Plus (less):
Net cash provided by financing activities (excluding distributions to unitholders)	163,006			64,048			425,765			184,198
Acquisition of oil and natural gas properties and joint-venture funding	(546		)	(49,253		)	(25,891		)	(64,381		)
Development of oil and natural gas properties	(410,774		)	(260,095		)	(805,617		)	(495,899		)
Purchases of other property and equipment	(21,260		)	(29,304		)	(31,411		)	(55,147		)
Proceeds from sale of properties and equipment and other	(1,044		)	213,123			(11,730		)	210,899
Net decrease in cash and cash equivalents	$	(29,975	)	$	(4,882	)	$	(13,832	)	$	(91	)

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

Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations is based upon the condensed consolidated financial statements, which have been prepared in accordance with GAAP. 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.

Recently Issued Accounting Standards

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

Cautionary Statement

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 content about the Company’s:


•	business strategy;


•	acquisition strategy;


•	financial strategy;


•	effects of the pending SEC inquiry and other 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 forward-looking statements or 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 this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2013, and elsewhere in the Annual Report. The forward-looking statements speak only as of the date made and,

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

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.

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 2013 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. 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.

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. The Company did not purchase any put options in 2013 or to date in 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 June 30, 2014, the fair value of fixed price swaps, put option contracts, collars and three-way collars was a net asset of approximately $197 million. A 10% increase in the index oil and natural gas prices above the June 30, 2014, prices would result in a net liability of approximately $494 million, which represents a decrease in the fair value of approximately $691 million; conversely, a 10% decrease in the index oil and natural gas prices below June 30, 2014, prices would result in a net asset of approximately $888 million, which represents an increase in the fair value of approximately $691 million.

At December 31, 2013, the fair value of fixed price swaps, put option contracts, collars and three-way collars was a net asset of approximately $751 million. A 10% increase in the index oil and natural gas prices above December 31, 2013, prices would result in a net liability of approximately $15 million, which represents a decrease in the fair value of approximately $766 million; conversely, a 10% decrease in the index oil and natural gas prices below December 31, 2013, prices would result in a net asset of approximately $1.5 billion, which represents an increase in the fair value of approximately $781 million.

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

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 June 30, 2014, and December 31, 2013, 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 flow and ability to pay distributions could be impacted.

Interest Rate Risk

At June 30, 2014, the Company had long-term debt outstanding under its Credit Facilities and term loan of approximately $3.9 billion which incurred interest at floating rates (see Note 6). A 1% increase in the London Interbank Offered Rate (“LIBOR”) would result in an estimated $39 million increase in annual interest expense.

At December 31, 2013, the Company had long-term debt outstanding under its Credit Facilities and term loan of approximately $3.2 billion which incurred interest at floating rates. A 1% increase in the LIBOR would result in an estimated $32 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 June 30, 2014, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 1.22%. A 1% increase in the average public bond yield spread would result in an estimated $1 million increase in net income for the six months ended June 30, 2014. At June 30, 2014, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 2.30%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $3 million decrease in net income for the six months ended June 30, 2014.

At December 31, 2013, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 1.21%. A 1% increase in the average public bond yield spread would result in an estimated $188,000 increase in net income for the year ended December 31, 2013. At December 31, 2013, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 2.68%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $16 million decrease in net income for the year ended December 31, 2013.

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

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Item 4. Controls and Procedures - Continued

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 June 30, 2014.

Changes in the Company’s Internal Control Over Financial Reporting

The Company’s management is also responsible for establishing and maintaining adequate internal controls 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 controls over financial reporting during the second quarter of 2014 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting. The Company continues to integrate certain business operations, information systems, processes and related internal control over financial reporting as a result of the acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC. The Company will continue to assess the effectiveness of its internal control over financial reporting as integration activities continue.

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Part II - Other Information


Item 1.	Legal Proceedings

On July 10, 2013, Judy Mesirov, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against Mark E. Ellis, Kolja Rockov, David B. Rottino, Arden L. Walker, Jr., Charlene A. Ripley, Michael C. Linn, Joseph P. McCoy, George A. Alcorn, Terrence S. Jacobs, David D. Dunlap, Jeffrey C. Swoveland, and Linda M. Stephens in the District Court of Harris County, Texas (the “Mesirov Action”). On July 12, 2013, John Peters, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants in the District Court of Harris County, Texas (the “Peters Action”). On August 26, 2013, Joseph Abdalla, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants in the District Court of Harris County, Texas (the “Abdalla Action”) (the Mesirov Action, Peters Action, and Abdalla Actions together, the “Texas State Court Derivative Actions”). On August 19, 2013, the Charlote J. Lombardo Trust of 2004, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants in the United States District Court for the Southern District of Texas (the “Lombardo Action”). On September 30, 2013, the Thelma Feldman Rev. Trust, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants (the “Feldman Rev. Trust Action”). On October 21, 2013, the Parker Family Trust of 2012, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants (the “Parker Family Trust Action”) (the Lombardo Action, Feldman Rev. Trust Action, and Parker Family Trust Action together, the “Texas Federal Court Derivative Actions”) (the Texas State Court Derivative Action and Texas Federal Court Derivative Actions together, the “Texas Derivative Actions”). On May 28, 2014, Bill McKinnon, derivatively on behalf of nominal defendant LINN Energy, filed a shareholder derivative petition against many of the same defendants (the “McKinnon Action”) in the Delaware Court of Chancery (the “Delaware Derivative Action”) (the Delaware Derivative Action and the Texas Derivative Actions collectively, the “Derivative Actions”). The Derivative Actions assert derivative claims on behalf of LINN Energy against the individual defendants for alleged breaches of fiduciary duty, waste of corporate assets, mismanagement, abuse of control, and unjust enrichment based on factual allegations similar to those in the Combined Actions. The cases are in their preliminary stages and it is possible that additional similar actions could be filed in the District Court of Harris County,

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Item 1. Legal Proceedings - Continued

Texas, the Delaware Court of Chancery, or in other jurisdictions. As a result, the Company is unable to estimate a possible loss, or range of possible loss, if any.


Item 1A.	Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, results of operations, liquidity or 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, 2013. Except as set forth below, 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.

Unitholders are required to pay taxes on their share of our taxable income, including their share of ordinary income and capital gain upon dispositions of properties by us, even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, gain, loss and deduction, or specific items thereof, may be substantially different than the unitholder’s interest in our economic profits.

Our unitholders are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

For example, we may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the proceeds to our unitholders, and some or all of our unitholders may be allocated substantial taxable income with respect to that sale. A unitholder’s share of our taxable income upon a disposition of property by us may be ordinary income or capital gain or some combination thereof. Even where we dispose of properties that are capital assets, what otherwise would be capital gains may be recharacterized as ordinary income in order to “recapture” ordinary deductions that were previously allocated to that unitholder related to the same property.

In particular, as announced in June 2014, we plan to divest certain of our higher decline, capital intensive properties and acquire more mature, long-life oil and natural gas properties with lower decline rates. If we are unable to complete these transactions in a tax efficient manner or we receive proceeds from the sale of those properties in excess of the purchase price for the acquisition portion of those transactions, we may have substantial taxable income to allocate to some or all of our unitholders.

A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our economic profits. This may occur, for example, in the case of a unitholder who purchases units at a time when the value of our units or of one or more of our properties is relatively low or a unitholder who acquires units directly from us in exchange for property whose fair market value exceeds its tax basis at the time of the exchange.


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

Issuer Purchases of Equity Securities

In October 2008, the Board of Directors of the Company authorized the repurchase of up to $100 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. 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 six months ended June 30, 2014. At June 30, 2014, approximately $56 million was available for unit repurchase under the program. In August 2014, the Board of Directors of the Company increased the repurchase authorization to up to $250 million of the Company’s outstanding units.

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Item 3.	Defaults Upon Senior Securities

None


Item 4.	Mine Safety Disclosures

Not applicable


Item 5.	Other Information

None

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Item 6.	Exhibits



Exhibit Number		Description
2.1†	—	Exchange Agreement by and among Linn Energy Holdings, LLC, Berry Petroleum Company, LLC, XTO Energy Inc., ExxonMobil Oil Corporation, Mobil E&P U.S. Development Corporation and Exxon Mobil Corporation, dated as of May 20, 2014 (incorporated herein by reference to Exhibit 2.5 to Amendment No. 2 to Registration Statement on Form S-4 (File No. 333-187458) filed on May 28, 2014)
2.2†	—	First Amendment to Exchange Agreement by and among Linn Energy Holdings, LLC, Berry Petroleum Company, LLC, XTO Energy Inc., ExxonMobil Oil Corporation, Mobil E&P U.S. Development Corporation and Exxon Mobil Corporation, dated as of May 22, 2014 (incorporated herein by reference to Exhibit 2.6 to Amendment No. 2 to Registration Statement on Form S-4 (File No. 333-187458) filed on May 28, 2014)
2.3*†	—	Purchase and Sale Agreement by and between Devon Energy Production, L.P. and Devon Uinta Basin Corporation, as seller, and Linn Energy Holdings, LLC as buyer, executed as of June 27, 2014
10.1	—	Third Amendment to Sixth Amended and Restated Credit Agreement, dated April 30, 2014, among Linn Energy, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders and agents party thereto (incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q filed on May 1, 2014)
10.2	—	Ninth Amendment to Second Amended and Restated Credit Agreement of Berry Petroleum Company, LLC, dated April 30, 2014, among Berry Petroleum Company, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders and agents party thereto (incorporated by reference to Exhibit 10.4 to Quarterly Report on Form 10-Q filed on May 1, 2014)
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.


†	The schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K. The Company will furnish copies of such schedules to the Securities and Exchange Commission upon request.

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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: August 7, 2014	/s/ David B. Rottino
	David B. Rottino
	Executive Vice President, Business Development and Chief Accounting Officer
	(As Duly Authorized Officer and Chief Accounting Officer)