Edgar Filing: LINN ENERGY, LLC

LINE 6.30.2015 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, 2015



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

for the transition period from _______________ to _______________

Commission File Number: 000-51719

LINN ENERGY, LLC

(Exact name of registrant as specified in its charter)



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

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

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

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

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

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

As of June 30, 2015, there were 355,204,907 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, 2015, and December 31, 2014	1
	Condensed Consolidated Statements of Operations for the three months and six months ended June 30, 2015, and June 30, 2014	2
	Condensed Consolidated Statement of Unitholders’ Capital for the six months ended June 30, 2015	3
	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2015, and June 30, 2014	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 4.	Controls and Procedures	57

	Part II – Other Information
Item 1.	Legal Proceedings	58
Item 1A.	Risk Factors	58
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 3.	Defaults Upon Senior Securities	59
Item 4.	Mine Safety Disclosures	59
Item 5.	Other Information	59
Item 6.	Exhibits	60

	Signature	61

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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, 2015			December 31, 2014
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	3,943		$	1,809
Accounts receivable – trade, net	305,404			471,684
Derivative instruments	895,723			1,077,142
Assets held for sale	104,987			—
Other current assets	148,263			155,955
Total current assets	1,458,320			1,706,590

Noncurrent assets:
Oil and natural gas properties (successful efforts method)	17,965,789			18,068,900
Less accumulated depletion and amortization	(5,513,440		)	(4,867,682		)
	12,452,349			13,201,218

Other property and equipment	696,300			669,149
Less accumulated depreciation	(173,013		)	(144,282		)
	523,287			524,867

Derivative instruments	704,099			848,097
Restricted cash	256,744			6,225
Other noncurrent assets	117,227			136,512
	1,078,070			990,834
Total noncurrent assets	14,053,706			14,716,919
Total assets	$	15,512,026		$	16,423,509

LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	579,289		$	814,809
Derivative instruments	3,333			—
Other accrued liabilities	157,384			167,736
Total current liabilities	740,006			982,545

Noncurrent liabilities:
Credit facilities	3,178,175			2,968,175
Term loan	500,000			500,000
Senior notes, net	6,646,372			6,827,634
Derivative instruments	1,639			684
Other noncurrent liabilities	584,505			600,866
Total noncurrent liabilities	10,910,691			10,897,359

Commitments and contingencies (Note 10)

Unitholders’ capital:
355,204,907 units and 331,974,913 units issued and outstanding at June 30, 2015, and December 31, 2014, respectively	5,431,822			5,395,811
Accumulated deficit	(1,570,493		)	(852,206		)
	3,861,329			4,543,605
Total liabilities and unitholders’ capital	$	15,512,026		$	16,423,509

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,
	2015			2014			2015			2014
	(in thousands, except per unit amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	496,419		$	967,850		$	946,988		$	1,906,727
Gains (losses) on oil and natural gas derivatives	(191,188		)	(408,788		)	233,593			(650,281		)
Marketing revenues	10,733			30,273			44,477			60,819
Other revenues	5,864			7,616			13,317			13,273
	321,828			596,951			1,238,375			1,330,538
Expenses:
Lease operating expenses	140,652			184,901			313,673			378,934
Transportation expenses	55,795			44,854			109,335			90,484
Marketing expenses	9,159			23,274			38,000			44,346
General and administrative expenses	98,650			66,906			177,618			146,134
Exploration costs	564			1,551			960			2,642
Depreciation, depletion and amortization	215,732			274,435			430,746			542,236
Impairment of long-lived assets	—			—			532,617			—
Taxes, other than income taxes	58,034			68,531			112,079			134,244
(Gains) losses on sale of assets and other, net	(17,996		)	5,467			(30,283		)	8,053
	560,590			669,919			1,684,745			1,347,073
Other income and (expenses):
Interest expense, net of amounts capitalized	(146,100		)	(134,300		)	(289,201		)	(268,113		)
Gain on extinguishment of debt	9,151			—			15,786			—
Other, net	(6,146		)	(2,549		)	(8,359		)	(4,852		)
	(143,095		)	(136,849		)	(281,774		)	(272,965		)
Loss before income taxes	(381,857		)	(209,817		)	(728,144		)	(289,500		)
Income tax expense (benefit)	(2,730		)	(1,947		)	(9,857		)	3,707
Net loss	$	(379,127	)	$	(207,870	)	$	(718,287	)	$	(293,207	)

Net loss per unit:
Basic	$	(1.12	)	$	(0.64	)	$	(2.15	)	$	(0.91	)
Diluted	$	(1.12	)	$	(0.64	)	$	(2.15	)	$	(0.91	)
Weighted average units outstanding:
Basic	340,934			328,844			335,817			328,588
Diluted	340,934			328,844			335,817			328,588

Distributions declared per unit	$	0.313		$	0.725		$	0.625		$	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, 2014	331,975	$	5,395,811		$	(852,206	)	$	4,543,605
Sale of units, net of offering costs of $8,824	19,622	224,603			—			224,603
Issuance of units	3,608	—			—			—
Distributions to unitholders		(212,631		)	—			(212,631		)
Unit-based compensation expenses		33,711			—			33,711
Excess tax benefit from unit-based compensation and other		(9,672		)	—			(9,672		)
Net loss		—			(718,287		)	(718,287		)
June 30, 2015	355,205	$	5,431,822		$	(1,570,493	)	$	3,861,329

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,
	2015			2014
	(in thousands)
Cash flow from operating activities:
Net loss	$	(718,287	)	$	(293,207	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	430,746			542,236
Impairment of long-lived assets	532,617			—
Unit-based compensation expenses	33,711			32,583
Gain on extinguishment of debt	(15,786		)	—
Amortization and write-off of deferred financing fees	17,546			6,202
(Gains) losses on sale of assets and other, net	(25,894		)	3,506
Deferred income taxes	(9,857		)	3,475
Derivatives activities:
Total (gains) losses	(236,653		)	650,281
Cash settlements	566,343			(23,123		)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	169,978			(61,891		)
(Increase) decrease in other assets	3,523			(6,947		)
Increase (decrease) in accounts payable and accrued expenses	(47,474		)	113,582
Decrease in other liabilities	(27,031		)	(51,062		)
Net cash provided by operating activities	673,482			915,635

Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			(25,891		)
Development of oil and natural gas properties	(416,347		)	(805,617		)
Purchases of other property and equipment	(29,287		)	(31,411		)
Proceeds from sale of properties and equipment and other	58,714			(11,730		)
Net cash used in investing activities	(386,920		)	(874,649		)

Cash flow from financing activities:
Proceeds from sale of units	233,427			—
Proceeds from borrowings	645,000			1,095,000
Repayments of debt	(850,051		)	(616,124		)
Distributions to unitholders	(212,631		)	(480,583		)
Financing fees and offering costs	(8,649		)	(16,479		)
Excess tax benefit from unit-based compensation	(9,467		)	3,016
Other	(82,057		)	(39,648		)
Net cash used in financing activities	(284,428		)	(54,818		)

Net increase (decrease) in cash and cash equivalents	2,134			(13,832		)
Cash and cash equivalents:
Beginning	1,809			52,171
Ending	$	3,943		$	38,339

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 eight operating regions in the United States (“U.S.”), in the Rockies, the Hugoton Basin, California, the Mid-Continent, the Permian Basin, TexLa, South Texas and Michigan/Illinois.

Principles of Consolidation and Reporting

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

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

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

Use of Estimates

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

Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2015, and interim periods within those years (early adoption permitted). Adoption of this ASU is expected

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

to result in a decrease to the Company’s assets and liabilities in its consolidated balance sheets, with no impact to the consolidated statements of operations.

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

Note 2 – Acquisitions, Divestiture and Joint-Venture Funding

The revenues and expenses related to certain oil and natural gas properties acquired in 2014 from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) are included in the condensed consolidated statements of operations of the Company as of August 29, 2014. The following unaudited pro forma financial information presents a summary of the Company’s condensed combined results of operations for the three months and six months ended June 30, 2014, assuming the Devon Assets Acquisition had been completed as of January 1, 2014, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information has been prepared for informational purposes only and does not purport to represent what the actual results of operations would have been had the transaction been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The pro forma financial information does not give effect to the costs of any integration activities or benefits that may result from the realization of future cost savings from operating efficiencies, or any other synergies that may result from the transaction.



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

Total revenues and other	$	729,179		$	1,608,294
Total operating expenses	$	(750,486	)	$	(1,515,977	)
Net loss	$	(190,367	)	$	(252,672	)

Net loss per unit:
Basic	$	(0.59	)	$	(0.78	)
Diluted	$	(0.59	)	$	(0.78	)

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


•	Reflect the results of the Devon Assets Acquisition.


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


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


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


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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Divestiture – Pending

On July 2, 2015, the Company, through certain of its wholly owned subsidiaries, entered into a definitive purchase and sale agreement to sell its remaining position in Howard County in the Permian Basin for a contract price of approximately $281 million, subject to closing adjustments. The sale is anticipated to close in the third quarter of 2015, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. At June 30, 2015, the Company’s condensed consolidated balance sheet included current assets of approximately $105 million as “assets held for sale” and current liabilities of approximately $3 million included in “other accrued liabilities” classified as “held for sale” related to the sale.

Joint-Venture Funding – 2014

During January and February of 2014, the Company paid approximately $25 million, including interest, to complete the total funding commitment of $400 million related to the joint-venture agreement it entered into with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) in April 2012.

Note 3 – Unitholders’ Capital

At-the-Market Offering Program

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

During the six months ended June 30, 2015, the Company, under its equity distribution agreement, sold 3,621,983 units representing limited liability company interests at an average unit price of $12.37 for net proceeds of approximately $44 million (net of approximately $448,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional services expenses of approximately $459,000. The Company used the net proceeds for general corporate purposes including the open market repurchases of a portion of its senior notes (see Note 6). At June 30, 2015, units totaling approximately $455 million in aggregate offering price remained available to be sold under the agreement.

Public Offering of Units

In May 2015, the Company sold 16,000,000 units representing limited liability company interests in an underwritten public offering at $11.79 per unit ($11.32 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering costs of approximately $8 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under the LINN Credit Facility, which included debt initially incurred to fund the open market repurchases of a portion of its senior notes during 2015 (see Note 6).

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, 2015, the Company’s Board of Directors declared a cash distribution of $0.3125 per unit with respect to the second quarter of 2015, to be paid in three equal installments of $0.1042 per unit. The first monthly

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

distribution with respect to the second quarter of 2015, totaling approximately $37 million, was paid on July 16, 2015, to unitholders of record as of the close of business on July 13, 2015.

Note 4 – Oil and Natural Gas Properties

Oil and Natural Gas Capitalized Costs

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



	June 30, 2015			December 31, 2014
	(in thousands)
Proved properties:
Leasehold acquisition	$	13,302,759		$	13,362,642
Development	2,807,595			2,830,841
Unproved properties	1,855,435			1,875,417
	17,965,789			18,068,900
Less accumulated depletion and amortization	(5,513,440		)	(4,867,682		)
	$	12,452,349		$	13,201,218

Impairment of Proved Properties

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

Based on the analysis described above, the Company recorded no impairment charges for the three months ended June 30, 2015, or the six months ended June 30, 2014. During the first quarter of 2015, the Company recorded noncash impairment charges, before and after tax, of approximately $533 million associated with proved oil and natural gas properties. The impairment was due to a decline in commodity prices. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. For the six months ended June 30, 2015, the following impairment charges are included in “impairment of long-lived assets” on the condensed consolidated statement of operations:


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


•	California region – $207 million;


•	TexLa region – $33 million;


•	South Texas region – $9 million; and


•	Mid-Continent region – $6 million.

Note 5 – Unit-Based Compensation

During the six months ended June 30, 2015, the Company granted 3,471,095 restricted units and 697,120 phantom units to employees, primarily as part of its annual review of its employees’ compensation, including executives, with an aggregate fair

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

value of approximately $42 million. The restricted units and phantom units vest over three years. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:



	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
	(in thousands)

General and administrative expenses	$	11,044	$	9,496	$	27,677	$	27,719
Lease operating expenses	2,157		1,587		6,034		4,864
Total unit-based compensation expenses	$	13,201	$	11,083	$	33,711	$	32,583
Income tax benefit	$	4,877	$	4,095	$	12,456	$	12,039

Cash-Based Performance Unit Awards

In January 2015, the Company also granted 567,320 performance units (the maximum number of units available to be earned) to certain executive officers. The 2015 performance unit awards vest three years from the award date. The vesting of these units is determined based on the Company’s performance compared to the performance of a predetermined group of peer companies over a specified performance period, and the value of vested units is to be paid in cash. To date, no performance units have vested and no amounts have been paid to settle any such awards. Performance unit awards that are settled in cash are recorded as a liability with the changes in fair value recognized over the vesting period. Based on the performance criteria, there was no liability recorded for these performance unit awards at June 30, 2015.

Note 6 – Debt

The following summarizes the Company’s outstanding debt:



	June 30, 2015			December 31, 2014
	(in thousands, except percentages)

LINN credit facility ⁽¹⁾	$	2,005,000		$	1,795,000
Berry credit facility ⁽²⁾	1,173,175			1,173,175
Term loan ⁽³⁾	500,000			500,000
6.50% senior notes due May 2019	1,200,000			1,200,000
6.25% senior notes due November 2019	1,800,000			1,800,000
8.625% senior notes due April 2020	1,173,619			1,300,000
6.75% Berry senior notes due November 2020	275,177			299,970
7.75% senior notes due February 2021	994,000			1,000,000
6.50% senior notes due September 2021	650,000			650,000
6.375% Berry senior notes due September 2022	572,700			599,163
Net unamortized discounts and premiums	(19,124		)	(21,499		)
Total debt, net	10,324,547			10,295,809
Less current maturities	—			—
Total long-term debt, net	$	10,324,547		$	10,295,809


⁽¹⁾	Variable interest rates of 1.94% and 1.92% at June 30, 2015, and December 31, 2014, respectively.


⁽²⁾	Variable interest rates of 2.69% and 2.67% at June 30, 2015, and December 31, 2014, respectively.


⁽³⁾	Variable interest rates of 2.69% and 2.66% at June 30, 2015, and December 31, 2014, respectively.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Fair Value

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



	June 30, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)

Credit facilities	$	3,178,175	$	3,178,175	$	2,968,175	$	2,968,175
Term loan	500,000		500,000		500,000		500,000
Senior notes, net	6,646,372		5,247,250		6,827,634		5,703,649
Total debt, net	$	10,324,547	$	8,925,425	$	10,295,809	$	9,171,824

Credit Facilities

LINN Credit Facility

The Company’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) provides for (1) a senior secured revolving credit facility and (2) a $500 million senior secured term loan, in aggregate subject to the then-effective borrowing base. Borrowing capacity under the revolving credit facility is limited to the lesser of: (i) the then-effective borrowing base reduced by the $500 million term loan and (ii) the maximum commitment amount of $4.0 billion, and is currently $3.55 billion. The maturity date is April 2019. At June 30, 2015, the borrowing base under the LINN Credit Facility was $4.05 billion and availability under the revolving credit facility was approximately $1.5 billion, which includes reductions for the $500 million term loan and $6 million of outstanding letters of credit.

Redetermination of the borrowing base under the LINN Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. The administrative agent, at the direction of a super-majority of certain of the lenders, has the right to request one interim borrowing base redetermination per year. The Company also has the right to request one interim borrowing base redetermination per year, as well as the right to an additional interim redetermination each year in connection with certain acquisitions. The spring 2015 semi-annual redetermination was completed in May 2015, and the borrowing base under the LINN Credit Facility decreased from $4.5 billion to $4.05 billion as a result of lower commodity prices. Continued low or further declining commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs, along with the maturity schedule of the Company’s hedges, are expected to result in further decreases in the borrowing base at the October 2015 redetermination and may also impact future redeterminations.

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

At the Company’s election, interest on borrowings under the LINN Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.5% and 2.5% per annum (depending on the then-current level of borrowings under the LINN Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.5% and 1.5% per annum (depending on the then-current level of borrowings under the LINN Credit Facility).

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR. The Company is required to pay a commitment fee to the lenders under the LINN Credit Facility, which accrues at a rate per annum between 0.375% and 0.5% (depending on the then-current level of borrowings under the LINN Credit Facility) on the average daily unused amount of the maximum commitment amount of the lenders.

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

Berry Credit Facility

Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) currently has a borrowing base of $1.2 billion, subject to lender commitments. The maturity date is April 2019. At June 30, 2015, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit.

Redetermination of the borrowing base under the Berry Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. A super-majority of the lenders under the Berry Credit Facility and Berry also have the right to request interim borrowing base redeterminations once between scheduled redeterminations. The spring 2015 semi-annual borrowing base redetermination was completed in May 2015, and the borrowing base under the Berry Credit Facility decreased from $1.4 billion to $1.2 billion as a result of lower commodity prices. Continued low or further declining commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs, along with the maturity schedule of the Company’s hedges, are expected to result in further decreases in the borrowing base at the October 2015 redetermination and may also impact future redeterminations.

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

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

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

Repurchases of Senior Notes

During the six months ended June 30, 2015, the Company repurchased on the open market approximately $184 million of its outstanding senior notes as follows:


•	8.625% senior notes due April 2020 – $127 million;


•	6.75% Berry senior notes due November 2020 – $25 million;


•	7.75% senior notes due February 2021 – $6 million; and


•	6.375% Berry senior notes due September 2022 – $26 million.

In connection with the repurchases, the Company recorded a gain on extinguishment of debt of approximately $16 million for the six months ended June 30, 2015.

Repurchases of Senior Notes – Subsequent Event

In July 2015, the Company repurchased through privately negotiated transactions approximately $599 million of its outstanding senior notes as follows:


•	6.50% senior notes due May 2019 – $41 million;


•	6.25% senior notes due November 2019 – $316 million;


•	8.625% senior notes due April 2020 – $50 million;


•	6.75% Berry senior notes due November 2020 – $14 million;


•	7.75% senior notes due February 2021 – $30 million; and


•	6.50% senior notes due September 2021 – $148 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 or dividends on Berry’s equity or redeem its subordinated debt; (iii) create certain liens; (iv) enter into agreements that restrict distributions or other payments from Berry’s restricted subsidiaries to Berry; (v) sell assets; (vi) engage in transactions with affiliates; and (vii) consolidate, merge or transfer all or substantially all of Berry’s assets. Berry is in compliance with all financial and other covenants of its senior notes.

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Note 7 – Derivatives

Commodity Derivatives

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

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

The following table summarizes derivative positions for the periods indicated as of June 30, 2015:



	July 1 - December 31, 2015			2016			2017			2018
Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMMBtu)	59,506			121,841			120,122			36,500
Average price ($/MMBtu)	$	5.19		$	4.20		$	4.26		$	5.00
Put options (NYMEX Henry Hub):
Hedged volume (MMMBtu)	36,222			76,269			66,886			—
Average price ($/MMBtu)	$	5.00		$	5.00		$	4.88		$	—
Oil positions:
Fixed price swaps (NYMEX WTI): ⁽¹⁾
Hedged volume (MBbls)	7,810			11,465			4,755			—
Average price ($/Bbl)	$	87.12		$	90.56		$	89.02		$	—
Three-way collars (NYMEX WTI):
Hedged volume (MBbls)	552			—			—			—
Short put ($/Bbl)	$	70.00		$	—		$	—		$	—
Long put ($/Bbl)	$	90.00		$	—		$	—		$	—
Short call ($/Bbl)	$	101.62		$	—		$	—		$	—
Put options (NYMEX WTI):
Hedged volume (MBbls)	1,727			3,271			384			—
Average price ($/Bbl)	$	90.00		$	90.00		$	90.00		$	—
Natural gas basis differential positions: ⁽²⁾
Panhandle basis swaps: ⁽³⁾
Hedged volume (MMMBtu)	43,939			59,954			59,138			16,425
Hedged differential ($/MMBtu)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)



	July 1 - December 31, 2015			2016			2017			2018
NWPL Rockies basis swaps: ⁽³⁾
Hedged volume (MMMBtu)	29,731			65,794			38,880			10,804
Hedged differential ($/MMBtu)	$	(0.23	)	$	(0.24	)	$	(0.19	)	$	(0.19	)
MichCon basis swaps: ⁽³⁾
Hedged volume (MMMBtu)	4,710			7,768			7,437			2,044
Hedged differential ($/MMBtu)	$	0.06		$	0.05		$	0.05		$	0.05
Houston Ship Channel basis swaps: ⁽³⁾
Hedged volume (MMMBtu)	14,472			34,364			36,730			986
Hedged differential ($/MMBtu)	$	(0.03	)	$	(0.02	)	$	(0.02	)	$	(0.08	)
Permian basis swaps: ⁽³⁾
Hedged volume (MMMBtu)	2,558			4,219			4,819			1,314
Hedged differential ($/MMBtu)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)

SoCal basis swaps: ⁽⁴⁾
Hedged volume (MMMBtu)	16,560			32,940			—			—
Hedged differential ($/MMBtu)	$	(0.03	)	$	(0.03	)	$	—		$	—
Oil timing differential positions:
Trade month roll swaps (NYMEX WTI): ⁽⁵⁾
Hedged volume (MBbls)	3,655			7,446			6,486			—
Hedged differential ($/Bbl)	$	0.24		$	0.25		$	0.25		$	—

⁽¹⁾

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


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


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


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

⁽⁵⁾

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

During the six months ended June 30, 2015, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for May 2015 through December 2017, to hedge exposure to differentials in certain producing areas, and oil swaps for April 2015 through December 2015. In addition, the Company entered into natural gas basis swaps for May 2015 through December 2016 to hedge exposure to the differential in California, where it consumes natural gas in its heavy oil development operations.

Settled derivatives on natural gas production for the three months and six months ended June 30, 2015, included volumes of 47,344 MMMBtu and 94,167 MMMBtu, respectively, at an average contract price of $5.12 per MMBtu. Settled derivatives on oil production for the three months and six months ended June 30, 2015, included volumes of 4,820 MBbls and 8,795 MBbls, respectively, at average contract prices of $88.60 per Bbl and $91.20 per Bbl. Settled derivatives on natural gas production for

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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.

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

Balance Sheet Presentation

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



	June 30, 2015		December 31, 2014
	(in thousands)
Assets:
Commodity derivatives	$	1,636,607	$	2,014,815
Liabilities:
Commodity derivatives	$	41,757	$	90,260

By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facilities or were participants or affiliates of participants in its Credit Facilities at the time it originally entered into the derivatives. The Credit Facilities are secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $1.6 billion at June 30, 2015. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Gains (Losses) on Derivatives

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015		2014
	(in thousands)

Gains (losses) on oil and natural gas derivatives	$	(191,188	)	$	(408,788	)	$	233,593	$	(650,281	)
Lease operating expenses ⁽¹⁾	3,986			—			3,060		—
Total gains (losses) on oil and natural gas derivatives	$	(187,202	)	$	(408,788	)	$	236,653	$	(650,281	)


⁽¹⁾	Consists of gains and losses on derivatives used to hedge natural gas consumption which were entered into in March 2015.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

For the three months and six months ended June 30, 2015, the Company received net cash settlements of approximately $284 million and $566 million, respectively. For the three months and six months ended June 30, 2014, the Company paid net cash settlements of approximately $9 million and $23 million, respectively.

Note 8 – Fair Value Measurements on a Recurring Basis

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

Fair Value Hierarchy

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

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



	June 30, 2015
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	1,636,607	$	(36,785	)	$	1,599,822
Liabilities:
Commodity derivatives	$	41,757	$	(36,785	)	$	4,972



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


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

Note 9 – Asset Retirement Obligations

The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2% for the six months ended June 30, 2015); and (iv) a credit-adjusted

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

risk-free interest rate (average of 5.5% for the six months ended June 30, 2015). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

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



Asset retirement obligations at December 31, 2014	$	497,570
Liabilities added from drilling	1,875
Liabilities reclassified as held for sale	(2,000		)
Current year accretion expense	14,888
Settlements	(2,920		)
Revision of estimates	(15,228		)
Asset retirement obligations at June 30, 2015	$	494,185

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

During the six months ended June 30, 2015, and June 30, 2014, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

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. In both April 2015 and April 2014, the Company received approximately $3 million 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 $49 million of the Company Claim.

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 loss:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands, except per unit data)

Net loss	$	(379,127	)	$	(207,870	)	$	(718,287	)	$	(293,207	)
Allocated to participating securities	(1,662		)	(2,154		)	(3,273		)	(4,306		)
	$	(380,789	)	$	(210,024	)	$	(721,560	)	$	(297,513	)

Basic net loss per unit	$	(1.12	)	$	(0.64	)	$	(2.15	)	$	(0.91	)
Diluted net loss per unit	$	(1.12	)	$	(0.64	)	$	(2.15	)	$	(0.91	)

Basic weighted average units outstanding	340,934			328,844			335,817			328,588
Dilutive effect of unit equivalents	—			—			—			—
Diluted weighted average units outstanding	340,934			328,844			335,817			328,588

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 5 million unit options and warrants for both the three months and six months ended June 30, 2015, and approximately 6 million for both the three months and six months ended June 30, 2014. All equivalent units were antidilutive for both the three months and six months ended June 30, 2015, and 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, 2015		December 31, 2014
	(in thousands)

Accrued interest	$	101,003	$	105,310
Accrued compensation	36,632		44,875
Asset retirement obligations	16,187		16,187
Other	3,562		1,364
	$	157,384	$	167,736

Table of Contents

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,
	2015		2014
	(in thousands)

Cash payments for interest, net of amounts capitalized	$	280,018	$	264,141
Cash payments for income taxes	$	601	$	—

Noncash investing activities:
Accrued capital expenditures	$	105,115	$	316,427

Included in “acquisition of oil and natural gas properties and joint-venture funding” on the condensed consolidated statement of cash flows for the six months ended June 30, 2014, is approximately $25 million paid by the Company to fund the commitment related to the joint-venture agreement entered into with Anadarko in April 2012 (see Note 2).

For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. “Restricted cash” on the condensed consolidated balance sheet at June 30, 2015, includes $250 million LINN Energy borrowed under the LINN Credit Facility and contributed to Berry in May 2015 to post as restricted cash with Berry’s lenders in connection with the reduction in the Berry Credit Facility’s borrowing base. Restricted cash also includes approximately $7 million and $6 million at June 30, 2015, and December 31, 2014, respectively, of cash deposited by the Company into a separate account 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 June 30, 2015, and December 31, 2014, net outstanding checks of approximately $13 million and $95 million, respectively, were reclassified and included in “accounts payable and accrued expenses” on the condensed consolidated balance sheets. Net outstanding checks are presented as cash flows from financing activities and included in “other” on the condensed consolidated statements of cash flows.

Note 14 – Related Party Transactions

LinnCo

LinnCo, LLC (“LinnCo”), an affiliate of LINN Energy, was formed on April 30, 2012. LinnCo’s initial sole purpose was to own units in LINN Energy. In connection with the 2013 acquisition of Berry, LinnCo amended its limited liability company agreement to permit, among other things, the acquisition and subsequent contribution of assets to LINN Energy. All of LinnCo’s common shares are held by the public. As of June 30, 2015, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy and owned approximately 37% of LINN Energy’s outstanding units.

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

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

For the three months and six months ended June 30, 2015, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $1.1 million and $2.5 million, respectively, of which approximately $2.2 million had been paid by LINN Energy on LinnCo’s behalf as of June 30, 2015. The expenses for the three months and six months ended June 30, 2015, include approximately $492,000 and $983,000, 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.

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.

During the three months and six months ended June 30, 2015, the Company paid approximately $40 million and $80 million, respectively, in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy. 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.

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, 2015, the Company incurred expenditures of approximately $2 million and $5 million, respectively, and for the three months and six months ended June 30, 2014, the Company incurred expenditures of approximately $8 million and $12 million, respectively, related to services rendered by Superior and its subsidiaries.

Note 15 – Subsidiary Guarantors

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

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

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS

June 30, 2015



	Linn Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	35		$	1,244		$	2,664		$	—		$	3,943
Accounts receivable – trade, net	—			222,090			83,314			—			305,404
Accounts receivable – affiliates	3,693,834			28,630			—			(3,722,464		)	—
Derivative instruments	—			880,189			15,534			—			895,723
Assets held for sale	—			104,987			—			—			104,987
Other current assets	—			105,032			43,238			(7		)	148,263
Total current assets	3,693,869			1,342,172			144,750			(3,722,471		)	1,458,320

Noncurrent assets:
Oil and natural gas properties (successful efforts method)	—			12,998,067			4,967,722			—			17,965,789
Less accumulated depletion and amortization	—			(4,649,099		)	(923,731		)	59,390			(5,513,440		)
	—			8,348,968			4,043,991			59,390			12,452,349

Other property and equipment	—			574,789			121,511			—			696,300
Less accumulated depreciation	—			(159,264		)	(13,749		)	—			(173,013		)
	—			415,525			107,762			—			523,287

Derivative instruments	—			703,123			976			—			704,099
Restricted cash	—			6,582			250,162			—			256,744
Notes receivable – affiliates	160,900			—			—			(160,900		)	—
Advance to affiliate	—			—			171,044			(171,044		)	—
Investments in consolidated subsidiaries	8,277,148			—			—			(8,277,148		)	—
Other noncurrent assets, net	100,442			5,198			11,587			—			117,227
	8,538,490			714,903			433,769			(8,609,092		)	1,078,070
Total noncurrent assets	8,538,490			9,479,396			4,585,522			(8,549,702		)	14,053,706
Total assets	$	12,232,359		$	10,821,568		$	4,730,272		$	(12,272,173	)	$	15,512,026

LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	963		$	388,422		$	189,904		$	—		$	579,289
Accounts payable – affiliates	—			3,693,834			28,630			(3,722,464		)	—
Advance from affiliate	—			171,044			—			(171,044		)	—
Derivative instruments	—			—			3,333			—			3,333
Other accrued liabilities	86,234			53,359			17,798			(7		)	157,384
Total current liabilities	87,197			4,306,659			239,665			(3,893,515		)	740,006

Noncurrent liabilities:
Credit facilities	2,005,000			—			1,173,175			—			3,178,175
Term loan	500,000			—			—			—			500,000
Senior notes, net	5,785,692			—			860,680			—			6,646,372
Notes payable – affiliates	—			160,900			—			(160,900		)	—
Derivative instruments	—			1,051			588			—			1,639
Other noncurrent liabilities	—			388,565			195,940			—			584,505
Total noncurrent liabilities	8,290,692			550,516			2,230,383			(160,900		)	10,910,691

Unitholders’ capital:
Units issued and outstanding	5,424,963			4,831,136			2,609,158			(7,433,435		)	5,431,822
Accumulated income (deficit)	(1,570,493		)	1,133,257			(348,934		)	(784,323		)	(1,570,493		)
	3,854,470			5,964,393			2,260,224			(8,217,758		)	3,861,329
Total liabilities and unitholders’ capital	$	12,232,359		$	10,821,568		$	4,730,272		$	(12,272,173	)	$	15,512,026

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2014



	Linn Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	38		$	185		$	1,586		$	—		$	1,809
Accounts receivable – trade, net	—			371,325			100,359			—			471,684
Accounts receivable – affiliates	4,028,890			13,205			—			(4,042,095		)	—
Derivative instruments	—			1,033,448			43,694			—			1,077,142
Other current assets	18			96,678			59,259			—			155,955
Total current assets	4,028,946			1,514,841			204,898			(4,042,095		)	1,706,590

Noncurrent assets:
Oil and natural gas properties (successful efforts method)	—			13,196,841			4,872,059			—			18,068,900
Less accumulated depletion and amortization	—			(4,342,675		)	(525,007		)	—			(4,867,682		)
	—			8,854,166			4,347,052			—			13,201,218

Other property and equipment	—			553,150			115,999			—			669,149
Less accumulated depreciation	—			(135,830		)	(8,452		)	—			(144,282		)
	—			417,320			107,547			—			524,867

Derivative instruments	—			848,097			—			—			848,097
Restricted cash	—			6,100			125			—			6,225
Notes receivable – affiliates	130,500			—			—			(130,500		)	—
Advance to affiliate	—			—			293,627			(293,627		)	—
Investments in consolidated subsidiaries	8,562,608			—			—			(8,562,608		)	—
Other noncurrent assets, net	116,637			5,716			14,159			—			136,512
	8,809,745			859,913			307,911			(8,986,735		)	990,834
Total noncurrent assets	8,809,745			10,131,399			4,762,510			(8,986,735		)	14,716,919
Total assets	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509

LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	3,784		$	581,880		$	229,145		$	—		$	814,809
Accounts payable – affiliates	—			4,028,890			13,205			(4,042,095		)	—
Advance from affiliate	—			293,627			—			(293,627		)	—
Derivative instruments	—			—			—			—			—
Other accrued liabilities	89,507			59,142			19,087			—			167,736
Total current liabilities	93,291			4,963,539			261,437			(4,335,722		)	982,545

Noncurrent liabilities:
Credit facilities	1,795,000			—			1,173,175			—			2,968,175
Term loan	500,000			—			—			—			500,000
Senior notes, net	5,913,857			—			913,777			—			6,827,634
Notes payable – affiliates	—			130,500			—			(130,500		)	—
Derivative instruments	—			684			—			—			684
Other noncurrent liabilities	—			400,851			200,015			—			600,866
Total noncurrent liabilities	8,208,857			532,035			2,286,967			(130,500		)	10,897,359

Unitholders’ capital:
Units issued and outstanding	5,388,749			4,831,339			2,416,381			(7,240,658		)	5,395,811
Accumulated income (deficit)	(852,206		)	1,319,327			2,623			(1,321,950		)	(852,206		)
	4,536,543			6,150,666			2,419,004			(8,562,608		)	4,543,605
Total liabilities and unitholders’ capital	$	12,838,691		$	11,646,240		$	4,967,408		$	(13,028,830	)	$	16,423,509

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, 2015



	Linn Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	323,038		$	173,381		$	—		$	496,419
Losses on oil and natural gas derivatives	—			(186,714		)	(4,474		)	—			(191,188		)
Marketing revenues	—			3,285			7,448			—			10,733
Other revenues	—			4,329			1,535			—			5,864
	—			143,938			177,890			—			321,828
Expenses:
Lease operating expenses	—			90,756			49,896			—			140,652
Transportation expenses	—			42,817			12,978			—			55,795
Marketing expenses	—			3,161			5,998			—			9,159
General and administrative expenses	—			61,548			37,102			—			98,650
Exploration costs	—			564			—			—			564
Depreciation, depletion and amortization	—			150,739			63,052			1,941			215,732
Impairment of long-lived assets	—			—			—			—			—
Taxes, other than income taxes	—			35,838			22,196			—			58,034
Gains on sale of assets and other, net	—			(17,185		)	(811		)	—			(17,996		)
	—			368,238			190,411			1,941			560,590
Other income and (expenses):
Interest expense, net of amounts capitalized	(123,555		)	145			(22,690		)	—			(146,100		)
Interest expense – affiliates	—			(3,235		)	—			3,235			—
Interest income – affiliates	3,235			—			—			(3,235		)	—
Gain on extinguishment of debt	2,320			—			6,831			—			9,151
Equity in losses from consolidated subsidiaries	(255,426		)	—			—			255,426			—
Other, net	(5,701		)	18			(463		)	—			(6,146		)
	(379,127		)	(3,072		)	(16,322		)	255,426			(143,095		)
Loss before income taxes	(379,127		)	(227,372		)	(28,843		)	253,485			(381,857		)
Income tax benefit	—			(2,719		)	(11		)	—			(2,730		)
Net loss	$	(379,127	)	$	(224,653	)	$	(28,832	)	$	253,485		$	(379,127	)

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 Six Months Ended June 30, 2015



	Linn Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	617,021		$	329,967		$	—		$	946,988
Gains (losses) on oil and natural gas derivatives	—			234,800			(1,207		)	—			233,593
Marketing revenues	—			29,497			14,980			—			44,477
Other revenues	—			9,886			3,431			—			13,317
	—			891,204			347,171			—			1,238,375
Expenses:
Lease operating expenses	—			196,588			117,085			—			313,673
Transportation expenses	—			83,751			25,584			—			109,335
Marketing expenses	—			26,357			11,643			—			38,000
General and administrative expenses	—			119,329			58,289			—			177,618
Exploration costs	—			960			—			—			960
Depreciation, depletion and amortization	—			291,438			136,031			3,277			430,746
Impairment of long-lived assets	—			325,417			272,000			(64,800		)	532,617
Taxes, other than income taxes	2			66,549			45,528			—			112,079
Gains on sale of assets and other, net	—			(24,999		)	(5,284		)	—			(30,283		)
	2			1,085,390			660,876			(61,523		)	1,684,745
Other income and (expenses):
Interest expense, net of amounts capitalized	(246,941		)	1,851			(44,111		)	—			(289,201		)
Interest expense – affiliates	—			(5,617		)	—			5,617			—
Interest income – affiliates	5,617			—			—			(5,617		)	—
Gain on extinguishment of debt	8,955			—			6,831			—			15,786
Equity in losses from consolidated subsidiaries	(478,237		)	—			—			478,237			—
Other, net	(7,679		)	(47		)	(633		)	—			(8,359		)
	(718,285		)	(3,813		)	(37,913		)	478,237			(281,774		)
Loss before income taxes	(718,287		)	(197,999		)	(351,618		)	539,760			(728,144		)
Income tax benefit	—			(9,796		)	(61		)	—			(9,857		)
Net loss	$	(718,287	)	$	(188,203	)	$	(351,557	)	$	539,760		$	(718,287	)

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	)

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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, 2015



	Linn Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from operating activities:
Net loss	$	(718,287	)	$	(188,203	)	$	(351,557	)	$	539,760		$	(718,287	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	—			291,438			136,031			3,277			430,746
Impairment of long-lived assets	—			325,417			272,000			(64,800		)	532,617
Unit-based compensation expenses	—			33,711			—			—			33,711
Gain on extinguishment of debt	(8,955		)	—			(6,831		)	—			(15,786		)
Amortization and write-off of deferred financing fees	16,692			—			854			—			17,546
Gains on sale of assets and other, net	—			(22,903		)	(2,991		)	—			(25,894		)
Equity in losses from consolidated subsidiaries	478,237			—			—			(478,237		)	—
Deferred income taxes	—			(9,796		)	(61		)	—			(9,857		)
Derivatives activities:
Total gains	—			(234,800		)	(1,853		)	—			(236,653		)
Cash settlements	—			533,400			32,943			—			566,343
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net	—			154,697			15,281			—			169,978
(Increase) decrease in accounts receivable – affiliates	371,275			(15,425		)	—			(355,850		)	—
Decrease in other assets	—			8			3,515			—			3,523
Decrease in accounts payable and accrued expenses	—			(43,427		)	(4,047		)	—			(47,474		)
Increase (decrease) in accounts payable and accrued expenses – affiliates	—			(371,275		)	15,425			355,850			—
Decrease in other liabilities	(3,597		)	(13,124		)	(10,310		)	—			(27,031		)
Net cash provided by operating activities	135,365			439,718			98,399			—			673,482

Cash flow from investing activities:
Development of oil and natural gas properties	—			(413,271		)	(3,076		)	—			(416,347		)
Purchases of other property and equipment	—			(26,305		)	(2,982		)	—			(29,287		)
Investment in affiliates	57,223			—			—			(57,223		)	—
Change in notes receivable with affiliate	(30,400		)	—			—			30,400			—
Proceeds from sale of properties and equipment and other	(2,168		)	49,580			11,302			—			58,714
Net cash provided by (used in) investing activities	24,655			(389,996		)	5,244			(26,823		)	(386,920		)

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)



	Linn Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
	(in thousands)
Cash flow from financing activities:
Proceeds from sale of units	233,427			—			—			—			233,427
Proceeds from borrowings	645,000			—			—			—			645,000
Repayments of debt	(804,698		)	—			(45,353		)	—			(850,051		)
Distributions to unitholders	(212,631		)	—			—			—			(212,631		)
Financing fees and offering costs	(8,646		)	—			(3		)	—			(8,649		)
Change in notes payable with affiliate	—			30,400			—			(30,400		)	—
Distributions to affiliate	—			—			(57,223		)	57,223			—
Excess tax benefit from unit-based compensation	(9,467		)	—			—			—			(9,467		)
Other	(3,008		)	(79,063		)	14			—			(82,057		)
Net cash used in financing activities	(160,023		)	(48,663		)	(102,565		)	26,823			(284,428		)

Net increase (decrease) in cash and cash equivalents	(3		)	1,059			1,078			—			2,134
Cash and cash equivalents:
Beginning	38			185			1,586			—			1,809
Ending	$	35		$	1,244		$	2,664		$	—		$	3,943

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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, 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 income (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		)

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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 offering costs	(5,613		)	—			(10,866		)	—			(16,479		)
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
Other	6,876			(46,524		)	—			—			(39,648		)
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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Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

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

Executive Overview

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


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


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


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


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


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


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


•	South Texas; and


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

Results for the three months ended June 30, 2015, included the following:


•	oil, natural gas and NGL sales of approximately $496 million compared to $968 million for the second quarter of 2014;


•	average daily production of approximately 1,219 MMcfe/d compared to 1,131 MMcfe/d for the second quarter of 2014;


•	net loss of approximately $379 million compared to $208 million for the second quarter of 2014;


•	capital expenditures, excluding acquisitions, of approximately $115 million compared to $407 million for the second quarter of 2014; and


•	148 wells drilled (all successful) compared to 268 wells drilled (all successful) for the second quarter of 2014.

Results for the six months ended June 30, 2015, included the following:


•	oil, natural gas and NGL sales of approximately $947 million compared to $1.9 billion for the six months ended June 30, 2014;


•	average daily production of approximately 1,210 MMcfe/d compared to 1,117 MMcfe/d for the six months ended June 30, 2014;


•	net loss of approximately $718 million compared to $293 million for the six months ended June 30, 2014;


•	net cash provided by operating activities of approximately $673 million compared to $916 million for the six months ended June 30, 2014;

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


•	capital expenditures, excluding acquisitions, of approximately $312 million compared to $816 million for the six months ended June 30, 2014; and


•	344 wells drilled (all successful) compared to 468 wells drilled (467 successful) for the six months ended June 30, 2014.

Reduction of 2015 Oil and Natural Gas Capital Budget and Distribution

The Company’s 2015 budget includes a 61% reduction in total capital expenditures to approximately $610 million, from approximately $1.6 billion spent in 2014, and includes approximately $530 million related to its oil and natural gas capital program. The 2015 budget contemplates significantly lower commodity prices as compared to 2014. In January 2015, the Company reduced its distribution to $1.25 per unit, from the previous level of $2.90 per unit, on an annualized basis. The reduction of the 2015 budget and the distribution was intended to solidify the Company’s financial position and allow it to regain a useful cost of capital.

In July 2015, the Company announced that management intends to recommend to the Board of Directors that it suspend payment of the Company’s distribution at the end of the third quarter of 2015.

Alliance with GSO Capital Partners

The Company signed definitive agreements dated June 30, 2015, with affiliates of private capital investor GSO Capital Partners LP (“GSO”), the credit platform of The Blackstone Group L.P., to fund oil and natural gas development (“DrillCo”). Funds managed by GSO and its affiliates have agreed to commit up to $500 million with 5-year availability to fund drilling programs on locations provided by LINN Energy. Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, GSO will fund 100% of the costs associated with new wells drilled under the DrillCo agreement and is expected to receive an 85% working interest in these wells until it achieves a 15% internal rate of return on annual groupings of wells, while LINN Energy is expected to receive a 15% carried working interest during this period. Upon reaching the internal rate of return target, GSO’s interest will be reduced to 5%, while LINN Energy’s interest will increase to 95%.

Alliance with Quantum Energy Partners

The Company signed definitive agreements dated June 30, 2015, with affiliates of private capital investor Quantum Energy Partners (“Quantum”) to fund selected future oil and natural gas acquisitions and the development of those acquired assets (“AcqCo”). See the Company’s Current Report on Form 8-K filed on July 7, 2015, for additional details regarding this transaction.

Divestiture – Pending

On July 2, 2015, the Company, through certain of its wholly owned subsidiaries, entered into a definitive purchase and sale agreement to sell its remaining position in Howard County in the Permian Basin for a contract price of approximately $281 million, subject to closing adjustments. The sale is anticipated to close in the third quarter of 2015, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. Upon completion of this sale, the Company will have divested all of its remaining capital intensive, high-decline rate properties.

Financing Activities

The spring 2015 semi-annual borrowing base redetermination of the Company’s Credit Facilities, as defined in Note 6, was completed in May 2015, and the borrowing base under the LINN Credit Facility decreased from $4.5 billion to $4.05 billion and the borrowing base under the Berry Credit Facility decreased from $1.4 billion to $1.2 billion as a result of lower commodity prices. Continued low or further declining commodity prices, reductions in the Company’s capital budget and the resulting reserve write-downs, along with the maturity schedule of the Company’s hedges, are expected to result in further decreases in both borrowing bases at the October 2015 redetermination and may also impact future redeterminations.

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

be used to satisfy obligations under the Berry Credit Facility or, subject to restrictions in the indentures governing Berry’s senior notes, may be returned to LINN Energy in the future.

During the six months ended June 30, 2015, the Company, under its equity distribution agreement, sold 3,621,983 units representing limited liability company interests at an average unit price of $12.37 for net proceeds of approximately $44 million (net of approximately $448,000 in commissions). The Company used the net proceeds for general corporate purposes including the open market repurchases of a portion of its senior notes (see Note 6). At June 30, 2015, units totaling approximately $455 million in aggregate offering price remained available to be sold under the agreement.

During the six months ended June 30, 2015, the Company repurchased on the open market approximately $184 million of its outstanding senior notes. In addition, in July 2015, the Company repurchased through privately negotiated transactions approximately $599 million of its outstanding senior notes. See Note 6 for additional details.

Commodity Derivatives

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

Results of Operations

Three Months Ended June 30, 2015, Compared to Three Months Ended June 30, 2014



	Three Months Ended June 30,
	2015			2014			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	149,908		$	205,050		$	(55,142	)
Oil sales	310,454			651,509			(341,055		)
NGL sales	36,057			111,291			(75,234		)
Total oil, natural gas and NGL sales	496,419			967,850			(471,431		)
Losses on oil and natural gas derivatives	(191,188		)	(408,788		)	217,600
Marketing and other revenues	16,597			37,889			(21,292		)
	321,828			596,951			(275,123		)
Expenses:
Lease operating expenses	140,652			184,901			(44,249		)
Transportation expenses	55,795			44,854			10,941
Marketing expenses	9,159			23,274			(14,115		)
General and administrative expenses ⁽¹⁾	98,650			66,906			31,744
Exploration costs	564			1,551			(987		)
Depreciation, depletion and amortization	215,732			274,435			(58,703		)
Taxes, other than income taxes	58,034			68,531			(10,497		)
(Gains) losses on sale of assets and other, net	(17,996		)	5,467			(23,463		)
	560,590			669,919			(109,329		)
Other income and (expenses)	(143,095		)	(136,849		)	(6,246		)
Loss before income taxes	(381,857		)	(209,817		)	(172,040		)
Income tax benefit	(2,730		)	(1,947		)	(783		)
Net loss	$	(379,127	)	$	(207,870	)	$	(171,257	)


⁽¹⁾	General and administrative expenses for the three months ended June 30, 2015, and June 30, 2014, include approximately $11 million and $9 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



	Three Months Ended June 30,
	2015		2014		Variance
Average daily production:
Natural gas (MMcf/d)	666		493		35	%
Oil (MBbls/d)	64.8		74.5		(13	)%
NGL (MBbls/d)	27.4		31.8		(14	)%
Total (MMcfe/d)	1,219		1,131		8	%

Weighted average prices: ⁽¹⁾
Natural gas (Mcf)	$	2.47	$	4.57	(46	)%
Oil (Bbl)	$	52.65	$	96.06	(45	)%
NGL (Bbl)	$	14.44	$	38.42	(62	)%

Average NYMEX prices:
Natural gas (MMBtu)	$	2.64	$	4.67	(43	)%
Oil (Bbl)	$	57.94	$	102.99	(44	)%

Costs per Mcfe of production:
Lease operating expenses	$	1.27	$	1.80	(29	)%
Transportation expenses	$	0.50	$	0.44	14	%
General and administrative expenses ⁽²⁾	$	0.89	$	0.65	37	%
Depreciation, depletion and amortization	$	1.94	$	2.67	(27	)%
Taxes, other than income taxes	$	0.52	$	0.67	(22	)%


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


⁽²⁾	General and administrative expenses for the three months ended June 30, 2015, and June 30, 2014, include approximately $11 million and $9 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 decreased by approximately $472 million or 49% to approximately $496 million for the three months ended June 30, 2015, from approximately $968 million for the three months ended June 30, 2014, due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $256 million, $127 million and $60 million, respectively.

Average daily production volumes increased to approximately 1,219 MMcfe/d for the three months ended June 30, 2015, from 1,131 MMcfe/d for the three months ended June 30, 2014. Higher natural gas production volumes resulted in an increase in revenues of approximately $72 million. Lower oil and NGL production volumes resulted in a decrease in revenues of approximately $85 million and $16 million, respectively.

The following table sets forth average daily production by region:



	Three Months Ended June 30,
	2015	2014	Variance
Average daily production (MMcfe/d):
Rockies	445	278	167		60	%
Hugoton Basin	255	151	104		69	%
California	187	172	15		9	%
Mid-Continent	100	297	(197	)	(66	)%
Permian Basin	85	169	(84	)	(50	)%
TexLa	80	31	49		156	%
South Texas	36	—	36		—
Michigan/Illinois	31	33	(2	)	(5	)%
	1,219	1,131	88		8	%

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

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

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



	Three Months Ended June 30,
	2015		2014
	(in thousands)

Oil and natural gas	$	99,430	$	389,313
Plant and pipeline	2,749		6,268
Other	12,614		10,932
Capital expenditures, excluding acquisitions	$	114,793	$	406,513

Gains (Losses) on Oil and Natural Gas Derivatives

Losses on oil and natural gas derivatives were approximately $191 million for the three months ended June 30, 2015, compared to approximately $409 million for the three months ended June 30, 2014, representing a variance of approximately $218 million. Losses on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts. The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.

During the three months ended June 30, 2015, the Company had commodity derivative contracts for approximately 78% of its natural gas production and 82% of its oil production. 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. The Company does not hedge the portion of natural gas production used to economically offset natural gas consumption related to its heavy oil development operations in California.

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Note 7 and Note 8 for additional information about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.

Marketing and Other Revenues

Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing and other revenues decreased by approximately $21 million or 56% to approximately $17 million for the three months ended June 30, 2015, from approximately $38 million for the three months ended June 30, 2014. The decrease was primarily due to lower revenues generated by the Jayhawk natural gas processing plant in Kansas, lower electricity sales revenues generated by the Company’s California cogeneration facilities and the impact of properties sold during the fourth quarter of 2014, partially offset by higher helium sales revenues in the Hugoton Basin.

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $44 million or 24% to approximately $141 million for the three months ended June 30, 2015, from approximately $185 million for the three months ended June 30, 2014. The decrease was primarily due to lower costs as a result of the properties sold during the fourth quarter of 2014, a decrease in steam costs caused by a lower price of natural gas used in steam generation and cost savings initiatives, partially offset by costs associated with properties acquired during the third quarter of 2014. Lease operating expenses per Mcfe also decreased to $1.27 per Mcfe for the three months ended June 30, 2015, from $1.80 per Mcfe for the three months ended June 30, 2014.

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

Transportation Expenses

Transportation expenses increased by approximately $11 million or 24% to approximately $56 million for the three months ended June 30, 2015, from approximately $45 million for the three months ended June 30, 2014. The increase was primarily due to costs associated with properties acquired during the third quarter of 2014 partially offset by lower costs as a result of the properties sold during the fourth quarter of 2014. Transportation expenses per Mcfe also increased to $0.50 per Mcfe for the three months ended June 30, 2015, from $0.44 per Mcfe for the three months ended June 30, 2014.

Marketing Expenses

Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses decreased by approximately $14 million or 61% to approximately $9 million for the three months ended June 30, 2015, from approximately $23 million for the three months ended June 30, 2014. The decrease was primarily due to lower expenses associated with the Jayhawk natural gas processing plant in Kansas and lower electricity generation expenses incurred by the Company’s California cogeneration facilities.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. General and administrative expenses increased by approximately $32 million or 47% to approximately $99 million for the three months ended June 30, 2015, from approximately $67 million for the three months ended June 30, 2014. The increase was primarily due to higher advisory fees related to the alliance agreements and higher salaries and benefits related expenses, principally driven by severance costs. General and administrative expenses per Mcfe also increased to $0.89 per Mcfe for the three months ended June 30, 2015, from $0.65 per Mcfe for the three months ended June 30, 2014.

Exploration Costs

Exploration costs decreased by approximately $1 million or 64% to approximately $564,000 for the three months ended June 30, 2015, from approximately $2 million for the three months ended June 30, 2014. The decrease was primarily due to lower leasehold impairment expenses on unproved properties.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization decreased by approximately $58 million or 21% to approximately $216 million for the three months ended June 30, 2015, from approximately $274 million for the three months ended June 30, 2014. The decrease was primarily due to the 2014 divestitures of properties with higher rates compared to the rates of properties acquired in 2014, as well as lower rates as a result of the impairments recorded in the prior year and the first quarter of 2015, partially offset by higher total production volumes. Depreciation, depletion and amortization per Mcfe also decreased to $1.94 per Mcfe for the three months ended June 30, 2015, from $2.67 per Mcfe for the three months ended June 30, 2014.

Taxes, Other Than Income Taxes



	Three Months Ended June 30,
	2015		2014		Variance
	(in thousands)

Severance taxes	$	20,676	$	35,765	$	(15,089	)
Ad valorem taxes	31,780		28,046		3,734
California carbon allowances	5,548		4,607		941
Other	30		113		(83		)
	$	58,034	$	68,531	$	(10,497	)

Taxes, other than income taxes decreased by approximately $10 million or 15% for the three months ended June 30, 2015, compared to the three months ended June 30, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to acquisitions completed during the third quarter of 2014. California carbon allowances increased primarily due to an

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

increase in estimated emissions for which credits are needed, caused by production increases and higher costs for acquired allowances.

Other Income and (Expenses)



	Three Months Ended June 30,
	2015			2014			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(146,100	)	$	(134,300	)	$	(11,800	)
Gain on extinguishment of debt	9,151			—			9,151
Other, net	(6,146		)	(2,549		)	(3,597		)
	$	(143,095	)	$	(136,849	)	$	(6,246	)

Other income and (expenses) increased by approximately $6 million for the three months ended June 30, 2015, compared to the three months ended June 30, 2014. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with the senior notes issued in September 2014 and amendments made to the Company’s Credit Facilities during 2014. For the three months ended June 30, 2015, the Company recorded a gain on extinguishment of debt of approximately $9 million as a result of the repurchases of a portion of its senior notes. See “Debt” under “Liquidity and Capital Resources” below for additional details. Other expenses increased primarily due to write-offs of deferred financing fees related to the Credit Facilities during 2015.

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 $3 million and $2 million for the three months ended June 30, 2015, and June 30, 2014, respectively. The income tax benefit increased primarily due to lower income from the Company’s taxable subsidiaries during the three months ended June 30, 2015, compared to the same period in 2014.

Net Income (Loss)

Net loss increased by approximately $171 million or 82% to approximately $379 million for the three months ended June 30, 2015, from approximately $208 million for the three months ended June 30, 2014. The increase was primarily due to lower production revenues, partially offset by decreased losses on oil and natural gas derivatives and lower expenses. 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, 2015, Compared to Six Months Ended June 30, 2014



	Six Months Ended June 30,
	2015			2014			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	322,004		$	431,739		$	(109,735	)
Oil sales	545,691			1,247,154			(701,463		)
NGL sales	79,293			227,834			(148,541		)
Total oil, natural gas and NGL sales	946,988			1,906,727			(959,739		)
Gains (losses) on oil and natural gas derivatives	233,593			(650,281		)	883,874
Marketing and other revenues	57,794			74,092			(16,298		)
	1,238,375			1,330,538			(92,163		)
Expenses:
Lease operating expenses	313,673			378,934			(65,261		)
Transportation expenses	109,335			90,484			18,851
Marketing expenses	38,000			44,346			(6,346		)
General and administrative expenses ⁽¹⁾	177,618			146,134			31,484
Exploration costs	960			2,642			(1,682		)
Depreciation, depletion and amortization	430,746			542,236			(111,490		)
Impairment of long-lived assets	532,617			—			532,617
Taxes, other than income taxes	112,079			134,244			(22,165		)
(Gains) losses on sale of assets and other, net	(30,283		)	8,053			(38,336		)
	1,684,745			1,347,073			337,672
Other income and (expenses)	(281,774		)	(272,965		)	(8,809		)
Loss before income taxes	(728,144		)	(289,500		)	(438,644		)
Income tax expense (benefit)	(9,857		)	3,707			(13,564		)
Net loss	$	(718,287	)	$	(293,207	)	$	(425,080	)


⁽¹⁾	General and administrative expenses for both the six months ended June 30, 2015, and June 30, 2014, include approximately $28 million 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,
	2015		2014		Variance
Average daily production:
Natural gas (MMcf/d)	659		487		35	%
Oil (MBbls/d)	63.8		72.9		(12	)%
NGL (MBbls/d)	28.1		32.2		(13	)%
Total (MMcfe/d)	1,210		1,117		8	%

Weighted average prices: ⁽¹⁾
Natural gas (Mcf)	$	2.70	$	4.90	(45	)%
Oil (Bbl)	$	47.27	$	94.55	(50	)%
NGL (Bbl)	$	15.58	$	39.14	(60	)%

Average NYMEX prices:
Natural gas (MMBtu)	$	2.81	$	4.80	(41	)%
Oil (Bbl)	$	53.29	$	100.84	(47	)%

Costs per Mcfe of production:
Lease operating expenses	$	1.43	$	1.87	(24	)%
Transportation expenses	$	0.50	$	0.45	11	%
General and administrative expenses ⁽²⁾	$	0.81	$	0.72	13	%
Depreciation, depletion and amortization	$	1.97	$	2.68	(26	)%
Taxes, other than income taxes	$	0.51	$	0.66	(23	)%


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


⁽²⁾	General and administrative expenses for both the six months ended June 30, 2015, and June 30, 2014, include approximately $28 million 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 decreased by approximately $960 million or 50% to approximately $947 million for the six months ended June 30, 2015, from approximately $1.9 billion for the six months ended June 30, 2014, due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $545 million, $262 million and $120 million, respectively.

Average daily production volumes increased to approximately 1,210 MMcfe/d for the six months ended June 30, 2015, from 1,117 MMcfe/d for the six months ended June 30, 2014. Higher natural gas production volumes resulted in an increase in revenues of approximately $152 million. Lower oil and NGL production volumes resulted in a decrease in revenues of approximately $156 million and $29 million, respectively.

The following table sets forth average daily production by region:



	Six Months Ended June 30,
	2015	2014	Variance
Average daily production (MMcfe/d):
Rockies	434	275	159		58	%
Hugoton Basin	251	147	104		70	%
California	189	164	25		15	%
Mid-Continent	101	300	(199	)	(66	)%
Permian Basin	90	167	(77	)	(46	)%
TexLa	79	31	48		152	%
South Texas	35	—	35		—
Michigan/Illinois	31	33	(2	)	(6	)%
	1,210	1,117	93		8	%

The increase in average daily production volumes in the Rockies region primarily reflects the impact of the Devon Assets Acquisition on August 29, 2014, and development capital spending. The increase in average daily production volumes in the Hugoton Basin region primarily reflects the impact of the properties received in the exchange with Exxon XTO on August 15, 2014, and the Pioneer Assets Acquisition on September 11, 2014. The increase in average daily production volumes in the California region primarily reflects the impact of the properties received in the exchange with ExxonMobil on November 21, 2014, and development capital spending. The decrease in average daily production volumes in the Mid-Continent region primarily reflects lower production volumes as a result of the Granite Wash Assets Sale on December 15, 2014, partially offset by the impact of the Devon Assets Acquisition. The decrease in average daily production volumes in the Permian Basin region primarily reflects lower production volumes as a result of the properties relinquished in the two exchanges with Exxon XTO and ExxonMobil and the properties sold in the Permian Basin Assets Sale on November 14, 2014. The increase in average daily production volumes in the TexLa region primarily reflects the impact of the Devon Assets Acquisition. Average daily production volumes in the South Texas region reflect the impact of the Devon Assets Acquisition. The decrease in average daily production volumes in the Michigan/Illinois region primarily reflects a low-decline asset base and minimal development capital spending.

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

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



	Six Months Ended June 30,
	2015		2014
	(in thousands)

Oil and natural gas	$	282,403	$	786,513
Plant and pipeline	5,002		11,663
Other	24,175		17,777
Capital expenditures, excluding acquisitions	$	311,580	$	815,953

Gains (Losses) on Oil and Natural Gas Derivatives

Gains on oil and natural gas derivatives were approximately $234 million for the six months ended June 30, 2015, compared to losses of approximately $650 million for the six months ended June 30, 2014, representing a variance of approximately $884 million. Gains on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts. The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.

During the six months ended June 30, 2015, the Company had commodity derivative contracts for approximately 79% of its natural gas production and 76% of its oil production. 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. The Company does not hedge the portion of natural gas production used to economically offset natural gas consumption related to its heavy oil development operations in California.

Marketing and Other Revenues

Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing and other revenues decreased by approximately $16 million or 22% to approximately $58 million for the six months ended June 30, 2015, from approximately $74 million for the six months ended June 30, 2014. The decrease was primarily due to lower electricity sales revenues generated by the Company’s California cogeneration facilities, lower revenues generated by the Jayhawk natural gas processing plant in Kansas and the impact of properties sold during the fourth quarter of 2014, partially offset by higher helium sales in the Hugoton Basin.

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $65 million or 17% to approximately $314 million for the six months ended June 30, 2015, from approximately $379 million for the six months ended June 30, 2014. The decrease was primarily due to lower costs as a result of the properties sold during the fourth quarter of 2014, a decrease in steam costs caused by a lower price of natural gas used in steam generation and cost savings initiatives, partially offset by costs associated with properties acquired during the third quarter of 2014. Lease operating expenses per Mcfe also decreased to $1.43 per Mcfe for the six months ended June 30, 2015, from $1.87 per Mcfe for the six months ended June 30, 2014.

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

Transportation Expenses

Transportation expenses increased by approximately $19 million or 21% to approximately $109 million for the six months ended June 30, 2015, from approximately $90 million for the six months ended June 30, 2014. The increase was primarily due to costs associated with properties acquired during the third quarter of 2014 partially offset by lower costs as a result of the properties sold during the fourth quarter of 2014. Transportation expenses per Mcfe also increased to $0.50 per Mcfe for the six months ended June 30, 2015, from $0.45 per Mcfe for the six months ended June 30, 2014.

Marketing Expenses

Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses decreased by approximately $6 million or 14% to approximately $38 million for the six months ended June 30, 2015, from approximately $44 million for the six months ended June 30, 2014. The decrease was primarily due to lower electricity generation expenses incurred by the Company’s California cogeneration facilities and lower expenses associated with the Jayhawk natural gas processing plant in Kansas.

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 $32 million or 22% to approximately $178 million for the six months ended June 30, 2015, from approximately $146 million for the six months ended June 30, 2014. The increase was primarily due to higher advisory fees related to the alliance agreements and higher salaries and benefits related expenses, principally driven by severance costs. General and administrative expenses per Mcfe also increased to $0.81 per Mcfe for the six months ended June 30, 2015, from $0.72 per Mcfe for the six months ended June 30, 2014.

Exploration Costs

Exploration costs decreased by approximately $2 million or 64% to approximately $1 million for the six months ended June 30, 2015, from approximately $3 million for the six months ended June 30, 2014. The decrease was primarily due to lower leasehold impairment expenses on unproved properties.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization decreased by approximately $111 million or 21% to approximately $431 million for the six months ended June 30, 2015, from approximately $542 million for the six months ended June 30, 2014. The decrease was primarily due to the 2014 divestitures of properties with higher rates compared to the rates of properties acquired in 2014, as well as lower rates as a result of the impairments recorded in the prior year and the first quarter of 2015, partially offset by higher total production volumes. Depreciation, depletion and amortization per Mcfe also decreased to $1.97 per Mcfe for the six months ended June 30, 2015, from $2.68 per Mcfe for the six months ended June 30, 2014.

Impairment of Long-Lived Assets

The Company recorded no impairment charges for the three months ended June 30, 2015, or the six months ended June 30, 2014. During the first quarter of 2015, the Company recorded noncash impairment charges, before and after tax, of approximately $533 million associated with proved oil and natural gas properties. The impairment was due to a decline in commodity prices. Following are the impairment charges recorded:


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


•	California region – $207 million;


•	TexLa region – $33 million;


•	South Texas region – $9 million; and


•	Mid-Continent region – $6 million.

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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,
	2015			2014		Variance
	(in thousands)

Severance taxes	$	34,566		$	67,881	$	(33,315	)
Ad valorem taxes	65,896			57,122		8,774
California carbon allowances	11,699			9,126		2,573
Other	(82		)	115		(197		)
	$	112,079		$	134,244	$	(22,165	)

Taxes, other than income taxes decreased by approximately $22 million or 17% for the six months ended June 30, 2015, compared to the six months ended June 30, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices partially offset by higher production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to acquisitions completed during the third quarter of 2014. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed, caused by production increases and higher costs for acquired allowances.

Other Income and (Expenses)



	Six Months Ended June 30,
	2015			2014			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(289,201	)	$	(268,113	)	$	(21,088	)
Gain on extinguishment of debt	15,786			—			15,786
Other, net	(8,359		)	(4,852		)	(3,507		)
	$	(281,774	)	$	(272,965	)	$	(8,809	)

Other income and (expenses) increased by approximately $9 million for the six months ended June 30, 2015, compared to the six months ended June 30, 2014. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with the senior notes issued in September 2014 and amendments made to the Company’s Credit Facilities during 2014. For the six months ended June 30, 2015, the Company recorded a gain on extinguishment of debt of approximately $16 million as a result of the repurchases of a portion of its senior notes. See “Debt” under “Liquidity and Capital Resources” below for additional details. Other expenses increased primarily due to write-offs of deferred financing fees related to the Credit Facilities during 2015.

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 $10 million for the six months ended June 30, 2015, compared to income tax expense of approximately $4 million for the six months ended June 30, 2014. The income tax benefit was primarily due to lower income from the Company’s taxable subsidiaries during the six months ended June 30, 2015, compared to the same period in 2014.

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

Net Income (Loss)

Net loss increased by approximately $425 million or 145% to approximately $718 million for the six months ended June 30, 2015, from approximately $293 million for the six months ended June 30, 2014. The increase was primarily due to lower production revenues and higher impairment charges, partially offset by higher gains on oil and natural gas derivatives and lower expenses. See discussions above for explanations of variances.

Liquidity and Capital Resources

The Company utilizes funds from debt and equity offerings, borrowings under its Credit Facilities and net cash provided by operating activities for capital resources and liquidity. To date, the primary use of capital has been for acquisitions and the development of oil and natural gas properties. For the six months ended June 30, 2015, the Company’s total capital expenditures, excluding acquisitions, were approximately $312 million. For 2015, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $610 million, including approximately $530 million related to its oil and natural gas capital program and approximately $40 million related to its plant and pipeline capital. This estimate reflects amounts for the development of properties associated with acquisitions (see Note 2), is under continuous review and subject to ongoing adjustments. The Company expects to fund the capital expenditures primarily with net cash provided by operating activities. At June 30, 2015, there was approximately $1.5 billion of available borrowing capacity under the LINN Credit Facility but less than $1 million available under the Berry Credit Facility, each as defined in Note 6.

The spring 2015 semi-annual borrowing base redetermination of the Company’s Credit Facilities was completed in May 2015, and the borrowing base under the LINN Credit Facility decreased from $4.5 billion to $4.05 billion and the borrowing base under the Berry Credit Facility decreased from $1.4 billion to $1.2 billion as a result of lower commodity prices. In connection with the reduction in Berry’s borrowing base, LINN Energy borrowed $250 million under the LINN Credit Facility, which it contributed to Berry to post as restricted cash with Berry’s lenders. As directed by LINN Energy, the $250 million was deposited on Berry’s behalf in a security account with the administrative agent subject to a security control agreement. Berry’s ability to withdraw funds from this account is subject to a concurrent reduction of the borrowing base under the Berry Credit Facility or lender consent in connection with a redetermination of such borrowing base. The $250 million may be used to satisfy obligations under the Berry Credit Facility or, subject to restrictions in the indentures governing Berry’s senior notes, may be returned to LINN Energy in the future.

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

Statements of Cash Flows

The following is a comparative cash flow summary:



	Six Months Ended June 30,
	2015			2014			Variance
	(in thousands)
Net cash:
Provided by operating activities	$	673,482		$	915,635		$	(242,153	)
Used in investing activities	(386,920		)	(874,649		)	487,729
Used in financing activities	(284,428		)	(54,818		)	(229,610		)
Net increase (decrease) in cash and cash equivalents	$	2,134		$	(13,832	)	$	15,966

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

Operating Activities

Cash provided by operating activities for the six months ended June 30, 2015, was approximately $673 million, compared to approximately $916 million for the six months ended June 30, 2014. The decrease was primarily due to lower production related revenues principally due to lower commodity prices partially offset by higher cash settlements on derivatives.

Investing Activities

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



	Six Months Ended June 30,
	2015			2014
	(in thousands)
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	$	—		$	(25,891	)
Capital expenditures	(445,634		)	(837,028		)
Proceeds from sale of properties and equipment and other	58,714			(11,730		)
	$	(386,920	)	$	(874,649	)

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

Financing Activities

Cash used in financing activities for the six months ended June 30, 2015, was approximately $284 million, compared to approximately $55 million for the six months ended June 30, 2014. The decrease in financing cash flow needs was primarily attributable to decreased capital expenditures during the six months ended June 30, 2015, as compared to 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,
	2015			2014
	(in thousands)
Proceeds from borrowings:
LINN Credit Facility	$	645,000		$	1,095,000
Repayments of debt:
LINN Credit Facility	$	(685,000	)	$	(410,000	)
Senior notes	(165,051		)	(206,124		)
	$	(850,051	)	$	(616,124	)

In addition, in May 2015, LINN Energy borrowed $250 million under the LINN Credit Facility, which it contributed to Berry to post as restricted cash with Berry’s lenders (see Note 6).

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

Debt

The following summarizes the Company’s outstanding debt:



	June 30, 2015			December 31, 2014
	(in thousands, except percentages)

LINN credit facility	$	2,005,000		$	1,795,000
Berry credit facility	1,173,175			1,173,175
Term loan	500,000			500,000
6.50% senior notes due May 2019	1,200,000			1,200,000
6.25% senior notes due November 2019	1,800,000			1,800,000
8.625% senior notes due April 2020	1,173,619			1,300,000
6.75% Berry senior notes due November 2020	275,177			299,970
7.75% senior notes due February 2021	994,000			1,000,000
6.50% senior notes due September 2021	650,000			650,000
6.375% Berry senior notes due September 2022	572,700			599,163
Net unamortized discounts and premiums	(19,124		)	(21,499		)
Total debt, net	$	10,324,547		$	10,295,809

During the six months ended June 30, 2015, the Company repurchased on the open market approximately $184 million of its outstanding senior notes as follows:


•	8.625% senior notes due April 2020 – $127 million;


•	6.75% Berry senior notes due November 2020 – $25 million;


•	7.75% senior notes due February 2021 – $6 million; and


•	6.375% Berry senior notes due September 2022 – $26 million.

At June 30, 2015, there was approximately $1.5 billion of available borrowing capacity under the LINN Credit Facility but less than $1 million available under the Berry Credit Facility. For additional information related to the Company’s outstanding debt, see Note 6. The Company plans to file Berry’s stand-alone financial statements with the Securities and Exchange Commission at a later date.

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

Financial Covenants

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



	At or for the Quarter Ended
	September 30, 2014	December 31, 2014	March 31, 2015	June 30, 2015	Twelve Months Ended June 30, 2015
LINN Credit Facility:
Interest Coverage Ratio	3.4	2.7	2.9	3.0	3.0
Current Ratio	3.7	2.6	3.0	2.9	2.9
Berry Credit Facility:
Interest Coverage Ratio	9.4	6.7	1.9	2.7	5.2
Current Ratio ⁽¹⁾	2.0	0.6	0.6	0.5	0.5
Current Ratio (consolidated) ⁽¹⁾	3.3	2.9	3.2	2.9	2.9


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

The Company has included disclosure of the Interest Coverage Ratio for the twelve months ended June 30, 2015, and the Current Ratio as of June 30, 2015, to demonstrate its compliance for the three months ended June 30, 2015, as well as the Interest Coverage Ratio for each of the preceding four quarters on an individual basis (rather than on a last twelve months basis) and the Current Ratio as of the end of each of the preceding four quarters to provide investors with trend information about the Company’s ongoing compliance with these financial covenants. If the Company fails to demonstrate compliance with either or both of the Interest Coverage Ratio or the Current Ratio as of the end of the quarter and such failure continues beyond applicable cure periods, an event of default would occur and the Company would be unable to make additional borrowings and outstanding indebtedness may be accelerated. The Company depends, in part, on its Credit Facilities for future capital needs. In addition, the Company has drawn on the LINN Credit Facility to fund or partially fund cash distribution payments. Absent such borrowings, the Company would have at times experienced a shortfall in cash available to pay the declared cash distribution amount. For additional information, see “Distribution Practices” below.

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

Counterparty Credit Risk

The Company accounts for its commodity derivatives at fair value. The Company’s counterparties are current participants or affiliates of participants in its Credit Facilities or were participants or affiliates of participants in its Credit Facilities at the time it originally entered into the derivatives. The LINN Credit Facility is secured by LINN Energy’s oil, natural gas and NGL reserves and the Berry Credit Facility is secured by Berry’s oil, natural gas and NGL reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

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

At-the-Market Offering Program

Public Offering of Units

Distributions



Date Paid	Distributions Per Unit		Total Distributions
			(in millions)

June 2015	$	0.1042	$	37
May 2015	$	0.1042	$	35
April 2015	$	0.1042	$	35
March 2015	$	0.1042	$	35
February 2015	$	0.1042	$	35
January 2015	$	0.1042	$	35

On July 1, 2015, the Company’s Board of Directors declared a cash distribution of $0.3125 per unit with respect to the second quarter of 2015, to be paid in three equal monthly installments of $0.1042 per unit. The first monthly distribution with respect to the second quarter of 2015, totaling approximately $37 million, was paid on July 16, 2015, to unitholders of record as of the close of business on July 13, 2015.

In July 2015, the Company announced that management intends to recommend to the Board of Directors that it suspend payment of the Company’s distribution at the end of the third quarter of 2015.

Off-Balance Sheet Arrangements

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

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

Contingencies

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

Commitments and Contractual Obligations

The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in the table of contractual obligations in the 2014 Annual Report on Form 10-K. With the exception of the open market repurchases of approximately $184 million of its outstanding senior notes, there have been no significant changes to the Company’s contractual obligations since December 31, 2014. See Note 6 for additional information about the Company’s debt instruments.

Distribution Practices

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

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

In July 2015, the Company announced that management intends to recommend to the Board of Directors that it suspend payment of the Company’s distribution at the end of the third quarter of 2015 and reserve the approximately $450 million in cash from annualized distributions. Subject to declaration by the Board of Directors of the record and payment dates, the Company expects to pay the monthly distributions for August 2015 and September 2015. Management and the Board of Directors will continue to evaluate, on a quarterly basis, the appropriate level of cash reserves in determining a future distribution.

For 2015, the Company’s Board of Directors approved an oil and natural gas capital budget of approximately $530 million. At this level of capital investment, the Company forecasts a modest decline in production during 2015 while it focuses only on projects that generate an acceptable rate of return in the current low commodity price environment, and plans to balance cash flow and spending. As a result, for 2015, the Company intends to fund interest expense, its total oil and natural gas development costs and distributions to unitholders paid through September 2015 from net cash provided by operating activities, and will present “excess (shortfall) of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors” after deducting total oil and natural gas development costs. Previously, the Company intended to fund interest expense, a portion of its oil and natural gas development costs and distributions to unitholders from net cash provided by operating activities and presented “excess (shortfall) of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors” after deducting only a portion of oil and natural gas development costs.

The Company funds acquisitions and premiums paid for derivatives, if any, primarily with proceeds from debt or equity offerings, borrowings under the LINN Credit Facility or other external sources of funding. Although it is the Company’s

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

practice to acquire or modify derivative instruments with external sources of funding, any cash settlements on derivatives are reported as net cash provided by operating activities and may be used to fund distributions.

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,
	2015			2014			2015			2014
	(in thousands)

Net cash provided by operating activities	$	298,779		$	481,153		$	673,482		$	915,635
Distributions to unitholders	(107,816		)	(240,510		)	(212,631		)	(480,583		)
Excess of net cash provided by operating activities after distributions to unitholders	190,963			240,643			460,851			435,052
Discretionary adjustments considered by the Board of Directors:
Discretionary reductions for a portion of oil and natural gas development costs ⁽¹⁾	NM*			(199,448		)	NM*			(392,868		)
Development of oil and natural gas properties ⁽²⁾	(99,430		)	NM*			(282,403		)	NM*
Cash recoveries of bankruptcy claim ⁽³⁾	(2,877		)	(2,913		)	(2,877		)	(2,913		)
Cash received (paid) for acquisitions or divestitures – revenues less operating expenses ⁽⁴⁾	—			—			(2,712		)	—
Provision for legal matters ⁽⁵⁾	—			2,400			(1,000		)	1,598
Changes in operating assets and liabilities and other, net ⁽⁶⁾	(17,335		)	(8,626		)	(137,672		)	(11,806		)
Excess of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors, including a portion of oil and natural gas development costs ⁽⁷⁾	NM*			$	32,056		NM*			$	29,063
Excess of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors, including total development of oil and natural gas properties ⁽⁷⁾	$	71,321		NM*			$	34,187		NM*


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

⁽¹⁾

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

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

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

include reserve additions that may result from converting existing probable and possible resources to additional proved reserves, potential additional discoveries or technological advancements on the Company’s existing acreage position.

⁽²⁾

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


⁽³⁾	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.

⁽⁴⁾

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. Beginning with the three months ended June 30, 2015, the Board decided to no longer make this discretionary adjustment.


⁽⁵⁾	Represents reserves and settlements related to legal matters.

⁽⁶⁾

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.


⁽⁷⁾	Represents the excess (shortfall) of net operating cash flow after distributions to unitholders and discretionary adjustments. Any excess was retained by the Company for future operations, future capital expenditures, future debt service or other future obligations. Any shortfall was funded with cash on hand and/or borrowings under the LINN Credit Facility.

Any cash generated by Berry is currently being used by Berry to fund its activities. To the extent that Berry generates cash in excess of its needs, the indentures governing Berry’s senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and Berry may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Berry indentures. Berry’s restricted payments basket was approximately $431 million at June 30, 2015, and may be increased in accordance with the terms of the Berry indentures by, among other things, 50% of Berry’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(in thousands)

Net cash provided by operating activities	$	298,779		$	481,153		$	673,482		$	915,635
Distributions to unitholders	(107,816		)	(240,510		)	(212,631		)	(480,583		)
Excess of net cash provided by operating activities after distributions to unitholders	190,963			240,643			460,851			435,052
Plus (less):
Net cash provided by (used in) financing activities (excluding distributions to unitholders)	(98,131		)	163,006			(71,797		)	425,765
Acquisition of oil and natural gas properties and joint-venture funding	—			(546		)	—			(25,891		)
Development of oil and natural gas properties	(151,529		)	(410,774		)	(416,347		)	(805,617		)
Purchases of other property and equipment	(16,886		)	(21,260		)	(29,287		)	(31,411		)
Proceeds from sale of properties and equipment and other	31,214			(1,044		)	58,714			(11,730		)
Net increase (decrease) in cash and cash equivalents	$	(44,369	)	$	(29,975	)	$	2,134		$	(13,832	)

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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 on the condensed consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires management of the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors that are believed to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. Actual results may differ from these estimates and assumptions used in the preparation of the financial statements.

Recently Issued Accounting Standards

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

Cautionary Statement Regarding Forward-Looking Statements

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


•	business strategy;


•	acquisition strategy;


•	financial strategy;


•	effects of legal proceedings;


•	ability to maintain or grow distributions;


•	drilling locations;


•	oil, natural gas and NGL reserves;


•	realized oil, natural gas and NGL prices;


•	production volumes;


•	capital expenditures;


•	economic and competitive advantages;


•	credit and capital market conditions;


•	regulatory changes;


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


•	future operating results, including results of acquired properties;


•	plans, objectives, expectations and intentions; and


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

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

The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on Company expectations, which reflect estimates and assumptions made by Company management. These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors. Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control. In addition, management’s assumptions may prove to be inaccurate. The Company cautions that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors set forth in Item 1A. “Risk Factors” in this Quarterly

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

Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2014, and elsewhere in the Annual Report. The forward-looking statements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

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

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

Commodity Price Risk

As an important part of its business strategy, the Company seeks to hedge 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. Successful execution of that strategy depends on a number of factors including current and future expected commodity market prices, a liquid and actively traded market for hedging and availability and capacity of counterparties to enter into hedges. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company directly hedges only its oil and natural gas production. The Company also hedges its exposure to natural gas differentials in certain operating areas but does not currently hedge exposure to oil differentials. By removing a portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices.

Commodity hedging transactions are entered into with respect to a portion of the Company’s projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date.

In addition, as part of the 2013 acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including swap contracts, collars and three-way collars. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if the market price drops below the lower price.

The Company maintains a substantial portion of its hedges in the form of swap contracts. From time to time, the Company has chosen to purchase put option contracts primarily in connection with acquisition activity to hedge volumes in excess of those already hedged with swap contracts. The appropriate level of production to be hedged is an ongoing consideration and is based on a variety of factors, including current and future expected commodity market prices, cost and availability of put option contracts, the level of acquisition activity and the Company’s overall risk profile, including leverage and size and scale considerations. As a result, the appropriate percentage of production volumes to be hedged may change over time. There have

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

been no significant changes to the Company’s objectives, general strategies or instruments used to manage the Company’s commodity price risk exposures from the year ended December 31, 2014.

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

At June 30, 2015, the fair value of fixed price swaps, put option contracts and three-way collars was a net asset of approximately $1.5 billion. A 10% increase in the index oil and natural gas prices above the June 30, 2015, prices would result in a net asset of approximately $1.2 billion, which represents a decrease in the fair value of approximately $340 million; conversely, a 10% decrease in the index oil and natural gas prices below the June 30, 2015, prices would result in a net asset of approximately $1.8 billion, which represents an increase in the fair value of approximately $338 million.

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

The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.

The prices of oil, natural gas and NGL have been extremely volatile, and the Company expects this volatility to continue. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for such commodities, market uncertainty and a variety of additional factors that are beyond its control. Actual gains or losses recognized related to the Company’s derivative contracts will likely differ from those estimated at June 30, 2015, and December 31, 2014, and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

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

Interest Rate Risk

At June 30, 2015, the Company had long-term debt outstanding under its credit facilities and term loan of approximately $3.7 billion which incurred interest at floating rates (see Note 6). A 1% increase in the LIBOR would result in an estimated $37 million increase in annual interest expense.

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

Counterparty Credit Risk

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

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

At June 30, 2015, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 1.78%. A 1% increase in the average public bond yield spread would result in an estimated $40,000 increase in net income for the six months ended June 30, 2015. At June 30, 2015, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 2.35%. 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 six months ended June 30, 2015.

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2015.

Changes in the Company’s Internal Control Over Financial Reporting

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

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

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

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Part II – Other Information


Item 1.	Legal Proceedings


Item 1A.	Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our units are described in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014. 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.

Our Board of Directors has the ability to reserve any or all of our cash on hand at the end of a quarter for purposes other than distribution to unitholders, including reduction of indebtedness.

Although we may have generated sufficient net cash provided by operating activities during any particular quarter, our Board of Directors has the ability under our limited liability company agreement to establish a cash reserve, which could encompass all of the cash otherwise available for distribution, to provide for the proper conduct of our business in both the short and long term. To provide for the proper conduct of our business, the Board of Directors can determine to reserve cash to reduce indebtedness, among other things.

Any decision to reserve some or all of our cash on hand for such purposes and not distribute it may significantly impact our unitholders, as well as our business and operations. The market value of our units may decrease in response to or in anticipation of a decrease or suspension of a distribution. Suspension of the distribution may have a tax impact on our unitholders. Please see the risk factor in our 2014 Annual Report on Form 10-K entitled “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” for more information. External perceptions of the health of our business and our liquidity may also be impacted, which could further limit our ability to access capital markets, cause our vendors to tighten our credit terms and cause a strain in our relationship with landowners and other business partners. Further, our employees may become distracted from our day to day operations due to concern about our business and unit price.

We are currently dependent on our Credit Facilities, as defined in Note 6, for liquidity. Any further reduction of the borrowing bases under our Credit Facilities could reduce or eliminate our ability to borrow under the Credit Facilities and may require us to repay indebtedness under our Credit Facilities earlier than anticipated, which would adversely impact our liquidity.

Subject to amounts reserved in the discretion of our Board of Directors to provide for the proper conduct of our business, our limited liability company agreement provides that we make distributions to our unitholders of available cash. Therefore, we have not historically accumulated cash to preserve liquidity and have been dependent on the capital markets and our Credit Facilities for liquidity. Due to low commodity prices and other factors, the capital markets have been constrained. If these constraints continue, we will be primarily reliant on our Credit Facilities for liquidity.

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Item 1A. Risk Factors - Continued

scheduled redeterminations, semi-annually in April and October, of its borrowing base, based primarily on reserve reports using lender commodity price expectations at such time. As a result of lower commodity prices, in May 2015 the borrowing base under the LINN Credit Facility decreased from $4.5 billion to $4.05 billion and the borrowing base under the Berry Credit Facility decreased from $1.4 billion to $1.2 billion. Continued low or further declining commodity prices, reductions in our capital budget and the resulting reserve write-downs, along with the maturity schedule of our hedges, are expected to result in further decreases in both borrowing bases at the October 2015 redetermination and may also impact future redeterminations.

To the extent our borrowing bases are reduced to or below the amount of borrowings outstanding, we would be unable to continue to borrow and any excess borrowings may become due within a short time span. We may not have the financial resources to make mandatory prepayments and our liquidity would be significantly impacted.

We may experience difficulties in fully utilizing our alliances with GSO and Quantum, which could cause us to fail to realize many of the anticipated potential benefits of those alliances.

As part of our plan to i) create new sources of capital to allow us to acquire and develop assets without increasing capital intensity, ii) enhance our long-term ability to live within cash flow and iii) provide opportunities for dropdowns of stable production over time, we entered into strategic alliances with GSO Capital Partners LP (“GSO”), the credit platform of The Blackstone Group L.P., to fund oil and natural gas development (“DrillCo”) and Quantum Energy Partners (“Quantum”) to fund selected future oil and natural gas acquisitions and the development of those acquired assets through a new entity (“AcqCo”).

Achieving the anticipated benefits of DrillCo will depend in part on whether we and GSO are able to agree on a drilling plan during any of the five years of the term of DrillCo, as well as our ability to execute on that drilling plan. Achieving the anticipated benefits of the alliance with Quantum will depend in part on whether we are able to come to an agreement with Quantum and AcqCo regarding identification and acquisition of suitable assets for AcqCo, whether we are able to fund the acquisition of our required minimum working interest in such assets and ultimately whether we are able to purchase back assets from AcqCo after they have matured into conventional MLP assets. An inability to realize the full extent of the anticipated benefits of these alliances may affect our ability to accomplish the objectives identified above.


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

Issuer Purchases of Equity Securities

The Company’s Board of Directors has authorized the repurchase of up to $250 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. The timing and amounts of any such repurchases are at the discretion of management, subject to market conditions and other factors, and in accordance with applicable securities laws and other legal requirements. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. The Company did not repurchase any units during the six months ended June 30, 2015, and as of June 30, 2015, the entire amount remained available for unit repurchase under the program.


Item 3.	Defaults Upon Senior Securities

None


Item 4.	Mine Safety Disclosures

Not applicable


Item 5.	Other Information

None

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Item 6.	Exhibits



Exhibit Number		Description

2.1*	—	Purchase and Sale Agreement by and between Linn Energy Holdings, LLC and Linn Operating, Inc., as seller, and Rock Oil Holdings LLC, as buyer, executed on July 2, 2015
3.1	—	Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-125501) filed on June 3, 2005)
3.2	—	Certificate of Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated herein by reference to Exhibit 3.2 to Registration Statement on Form S‑1 (File No. 333-125501) filed on June 3, 2005)
3.3	—	Third Amended and Restated Limited Liability Company Agreement of Linn Energy, LLC dated September 3, 2010 (incorporated herein by reference to Exhibit 3.1 to Current Report on Form 8-K filed on September 7, 2010)
3.4	—	Amendment No. 1, dated April 23, 2013, to Third Amended and Restated LLC Agreement of Linn Energy, LLC, dated September 3, 2010 (incorporated herein by reference to Exhibit 3.1 to Quarterly Report on Form 10-Q filed on April 25, 2013)
10.1	—	Limited Liability Company Agreement of QL Energy I, LLC, dated as of June 30, 2015 (incorporated herein by reference to Exhibit 10.1 to Current Report on Form 8-K filed on July 7, 2015)
10.2	—	Development Agreement, by and between Linn Energy, LLC and QL Energy I, LLC, dated as of June 30, 2015 (incorporated herein by reference to Exhibit 10.2 to Current Report on Form 8-K filed on July 7, 2015)
10.3	—	Sixth Amendment to Sixth Amended and Restated Credit Agreement, dated as of May 12, 2015, among Linn Energy, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders and agents party thereto (incorporated herein by reference to Exhibit 10.1 to Current Report on Form 8-K filed on May 15, 2015)
10.4	—	Tenth Amendment and Borrowing Base Agreement to Second Amended and Restated Credit Agreement of Berry Petroleum Company, LLC, dated as of May 12, 2015, among Berry Petroleum Company, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders and agents party thereto (incorporated herein by reference to Exhibit 10.2 to Current Report on Form 8-K filed on May 15, 2015)
10.5*	—	Form of Executive Phantom Performance Unit Grant Agreement (2015-2017 Performance Period)
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.

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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: July 30, 2015	/s/ David B. Rottino
	David B. Rottino
	Executive Vice President, Business Development and Chief Accounting Officer
	(As Duly Authorized Officer and Chief Accounting Officer)