ROAN RESOURCES, INC. - FORM 10-Q

Attached files

file	filename
EXCEL - IDEA: XBRL DOCUMENT - ROAN RESOURCES, INC.	Financial_Report.xls
EX-10.2 - FIFTH AMENDMENT TO SIXTH AMENDED AND RESTATED CREDIT AGREEMENT - ROAN RESOURCES, INC.	exhibit102fifthamendmentto.htm
EX-31.2 - CERTIFICATION OF CFO SECTION 302 - ROAN RESOURCES, INC.	exhibit312q32014.htm
EX-2.1 - EXXON MOBIL EXCHANGE AGREEMENT - ROAN RESOURCES, INC.	exhibit21exchangeagreement.htm
EX-10.1 - FOURTH AMENDMENT TO SIXTH AMENDED AND RESTATED CREDIT AGREEMENT - ROAN RESOURCES, INC.	exhibit101fourthamendsixth.htm
EX-2.2 - ENERVEST AND FOURPOINT PSA - ROAN RESOURCES, INC.	exhibit22fourpoint_enerves.htm
EX-32.1 - CERTIFICATION OF CEO SECTION 906 - ROAN RESOURCES, INC.	exhibit321q32014.htm
EX-31.1 - CERTIFICATION OF CEO SECTION 302 - ROAN RESOURCES, INC.	exhibit311q32014.htm
EX-32.2 - CERTIFICATION OF CFO SECTION 906 - ROAN RESOURCES, INC.	exhibit322q32014.htm

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 September 30, 2014



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

for the transition period from _______________ to _______________

Commission File Number: 000-51719

LINN ENERGY, LLC

(Exact name of registrant as specified in its charter)



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

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

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

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

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

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

As of October 31, 2014, there were 331,903,326 units outstanding.

TABLE OF CONTENTS



		Page

	Glossary of Terms	ii

	Part I – Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of September 30, 2014, and December 31, 2013	1
	Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2014, and September 30, 2013	2
	Condensed Consolidated Statement of Unitholders’ Capital for the nine months ended September 30, 2014	3
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2014, and September 30, 2013	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 4.	Controls and Procedures	60

	Part II – Other Information
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 3.	Defaults Upon Senior Securities	62
Item 4.	Mine Safety Disclosures	62
Item 5.	Other Information	63
Item 6.	Exhibits	64

	Signature	65

Table of Contents

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.

Table of Contents

PART I – FINANCIAL INFORMATION


Item 1.	Financial Statements

LINN ENERGY, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2014			December 31, 2013
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	59,161		$	52,171
Accounts receivable – trade, net	522,633			488,202
Derivative instruments	337,244			176,130
Assets held for sale	1,865,040			—
Other current assets	165,512			99,437
Total current assets	2,949,590			815,940

Noncurrent assets:
Oil and natural gas properties (successful efforts method)	18,136,485			17,888,559
Less accumulated depletion and amortization	(3,099,637		)	(3,546,284		)
	15,036,848			14,342,275

Other property and equipment	635,410			647,882
Less accumulated depreciation	(148,815		)	(110,939		)
	486,595			536,943

Derivative instruments	305,274			682,002
Other noncurrent assets	148,687			127,804
	453,961			809,806
Total noncurrent assets	15,977,404			15,689,024
Total assets	$	18,926,994		$	16,504,964

LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	826,976		$	849,624
Derivative instruments	2,597			28,176
Other accrued liabilities	327,449			163,375
Current portion of long-term debt	1,300,000			211,558
Total current liabilities	2,457,022			1,252,733

Noncurrent liabilities:
Credit facilities	3,683,175			2,733,175
Term loan	500,000			500,000
Senior notes, net	6,826,971			5,725,483
Derivative instruments	80			4,649
Other noncurrent liabilities	527,613			397,497
Total noncurrent liabilities	11,537,839			9,360,804

Commitments and contingencies (Note 10)

Unitholders’ capital:
331,820,379 units and 329,661,161 units issued and outstanding at September 30, 2014, and December 31, 2013, respectively	5,629,837			6,291,824
Accumulated deficit	(697,704		)	(400,397		)
	4,932,133			5,891,427
Total liabilities and unitholders’ capital	$	18,926,994		$	16,504,964

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands, except per unit amounts)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	937,458		$	537,671		$	2,844,185		$	1,488,610
Gains (losses) on oil and natural gas derivatives	451,702			(63,931		)	(198,579		)	154,432
Marketing revenues	39,836			13,484			100,655			40,558
Other revenues	6,119			7,338			19,392			18,847
	1,435,115			494,562			2,765,653			1,702,447
Expenses:
Lease operating expenses	191,630			87,076			570,564			259,381
Transportation expenses	53,412			35,637			143,896			92,118
Marketing expenses	31,574			9,962			75,920			26,696
General and administrative expenses	75,384			45,431			221,518			150,302
Exploration costs	7,850			1,588			10,492			4,632
Depreciation, depletion and amortization	290,287			208,892			832,523			604,962
Impairment of long-lived assets	603,250			(4,240		)	603,250			37,962
Taxes, other than income taxes	66,770			36,457			201,014			108,525
(Gains) losses on sale of assets and other, net	(35,803		)	827			(27,750		)	3,040
	1,284,354			421,630			2,631,427			1,287,618
Other income and (expenses):
Interest expense, net of amounts capitalized	(154,047		)	(103,806		)	(422,160		)	(308,012		)
Loss on extinguishment of debt	—			(1,117		)	—			(5,304		)
Other, net	(1,847		)	(2,475		)	(6,699		)	(6,300		)
	(155,894		)	(107,398		)	(428,859		)	(319,616		)
Income (loss) before income taxes	(5,133		)	(34,466		)	(294,633		)	95,213
Income tax expense (benefit)	(1,033		)	(4,406		)	2,674			2,001
Net income (loss)	$	(4,100	)	$	(30,060	)	$	(297,307	)	$	93,212

Net income (loss) per unit:
Basic	$	(0.02	)	$	(0.13	)	$	(0.92	)	$	0.38
Diluted	$	(0.02	)	$	(0.13	)	$	(0.92	)	$	0.38
Weighted average units outstanding:
Basic	329,168			233,552			328,783			233,393
Diluted	329,168			233,552			328,783			233,765

Distributions declared per unit	$	0.725		$	0.725		$	2.175		$	2.175

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

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LINN ENERGY, LLC

CONDENSED CONSOLIDATED STATEMENT OF UNITHOLDERS’ CAPITAL

(Unaudited)



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

December 31, 2013	329,661	$	6,291,824		$	(400,397	)	$	5,891,427
Issuance of units	2,159	11,789			—			11,789
Distributions to unitholders		(721,235		)	—			(721,235		)
Unit-based compensation expenses		43,692			—			43,692
Excess tax benefit from unit-based compensation and other		3,767			—			3,767
Net loss		—			(297,307		)	(297,307		)
September 30, 2014	331,820	$	5,629,837		$	(697,704	)	$	4,932,133

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)



	Nine Months Ended September 30,
	2014			2013
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(297,307	)	$	93,212
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	832,523			604,962
Impairment of long-lived assets	603,250			37,962
Unit-based compensation expenses	43,692			29,261
Loss on extinguishment of debt	—			5,304
Amortization and write-off of deferred financing fees	29,236			16,392
(Gains) losses on sale of assets and other, net	(33,135		)	18,744
Deferred income taxes	2,619			731
Derivatives activities:
Total (gains) losses	198,579			(154,432		)
Cash settlements	(12,507		)	190,368
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	(56,014		)	22,877
Decrease in other assets	3,284			9,177
Increase in accounts payable and accrued expenses	112,235			29,445
Increase in other liabilities	9,355			36,508
Net cash provided by operating activities	1,435,810			940,511

Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	(2,601,932		)	(192,871		)
Development of oil and natural gas properties	(1,176,478		)	(767,604		)
Purchases of other property and equipment	(50,138		)	(76,987		)
Proceeds from sale of properties and equipment and other	(7,485		)	210,297
Net cash used in investing activities	(3,836,033		)	(827,165		)

Cash flow from financing activities:
Proceeds from borrowings	5,300,024			1,260,000
Repayments of debt	(2,156,124		)	(789,898		)
Distributions to unitholders	(721,235		)	(511,686		)
Financing fees and other, net	(19,483		)	(45,685		)
Excess tax benefit from unit-based compensation	4,031			160
Net cash provided by (used in) financing activities	2,407,213			(87,109		)

Net increase in cash and cash equivalents	6,990			26,237
Cash and cash equivalents:
Beginning	52,171			1,243
Ending	$	59,161		$	27,480

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 Mid-Continent, California, the Hugoton Basin, the Permian Basin, TexLa, Michigan/Illinois and south Texas.

Principles of Consolidation and Reporting

The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission (“SEC”) rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013. The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. The condensed consolidated financial statements also include the accounts of a variable interest entity where the Company is the primary beneficiary of the arrangements. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. The Company’s other investment is accounted for at cost.

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

Use of Estimates

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

Recently Issued Accounting Standards

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

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

currently evaluating the impact, if any, of the adoption of this ASU on its consolidated financial statements and related disclosures.

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

Note 2 – Acquisitions, Divestitures and Joint-Venture Funding

Properties Exchange

On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., in exchange for properties in the Hugoton Basin. The noncash exchange was accounted for at fair value and the Company recognized a net gain of approximately $45 million, including costs to sell of approximately $3 million. The gain is equal to the difference between the carrying value and the fair value of the assets exchanged less costs to sell, which is included in “(gains) losses on sale of assets and other, net” in the condensed consolidated statements of operations. The fair value measurements were based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy.

Acquisitions – 2014

On September 11, 2014, the Company, through a variable interest entity (“VIE”) (see below), completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin from Pioneer Natural Resources (“Pioneer” and the acquisition, the “Pioneer Assets Acquisition”) for total consideration of approximately $328 million.

On August 29, 2014, the Company, through a VIE (see below), completed the acquisition of certain oil and natural gas properties located in five operating regions in the U.S. from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) for total consideration of approximately $2.2 billion.

The Pioneer Assets Acquisition was initially financed with borrowings under the LINN Credit Facility, and the Devon Assets Acquisition was initially financed with proceeds from the Bridge Loan and borrowings under the VIE Term Loan (see Note 6). The Company intends to use the net proceeds from the pending sales of its Granite Wash assets as well as certain of its Wolfberry properties (see below) to repay the VIE Term Loan in full as well as repay a portion of the borrowings outstanding under the LINN Credit Facility.

The Pioneer Assets Acquisition and the Devon Assets Acquisition were structured as reverse like-kind exchanges pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchanges”). In connection with the Reverse 1031 Exchanges, the Company, through a subsidiary, assigned the rights to acquire legal title to the oil and natural gas properties from Pioneer and Devon to a VIE formed by an exchange accommodation titleholder. A subsidiary of LINN Energy operates the properties pursuant to management agreements with the VIE. Because the Company is the primary beneficiary of the VIE, the VIE is included in the condensed consolidated financial statements.

Revenues less certain reimbursable expenses of the VIE are available to LINN Energy with respect to assets attributable to the Pioneer Assets Acquisition, but can only be used to service debt and other obligations of the VIE with respect to assets attributable to the Devon Assets Acquisition. All assets held by the VIE are separate from the collateral pool securing the LINN Credit Facility. Debt obligations of the VIE are nonrecourse to LINN Energy and neither LINN Energy nor the VIE guarantee obligations of the other. The assets currently held by the VIE attributable to the Pioneer Assets Acquisition and the Devon Assets Acquisition will be conveyed to LINN Energy and its subsidiaries, and the VIE structure will terminate, upon the earlier of (i) completion of the Reverse 1031 Exchanges (which the Company expects to occur upon closing of the pending sales of its Granite Wash assets and certain of its Wolfberry properties) or (ii) the expiration of the time allowed by IRS rules and regulations to complete the Reverse 1031 Exchanges.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

During the nine months ended September 30, 2014, the Company also completed other smaller acquisitions of oil and natural gas properties located in its various operating regions. The Company, in the aggregate, paid approximately $9 million in total consideration for these properties.

These acquisitions and exchange were accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition dates, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of all acquisitions have been included in the condensed consolidated financial statements since the acquisition dates.

The following presents the values assigned to the net assets acquired as of the acquisition dates (in thousands):



Assets:
Current	$	22,604
Oil and natural gas properties	2,637,856
Other property and equipment	83,151
Total assets acquired	2,743,611

Liabilities:
Current	16,074
Asset retirement obligations	144,645
Total liabilities assumed	160,719
Net assets acquired	$	2,582,892

Current assets include receivables and inventory. Current liabilities include payables and environmental liabilities.

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the three months and nine months ended September 30, 2014, and September 30, 2013, assuming the Devon Assets Acquisition and the 2013 acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”) (see below) had been completed as of January 1, 2013, 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 transactions 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 transactions and changes in commodity and share prices.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014			2013
	(in thousands, except per unit amounts)

Total revenues and other	1,509,498		902,733		3,117,792			2,978,108
Total operating expenses	1,331,861		717,032		2,852,327			2,150,170
Net income (loss)	3		25,262		(257,158		)	334,272

Net income (loss) per unit:
Basic	$	—	$	0.08	$	(0.80	)	$	1.01
Diluted	$	—	$	0.08	$	(0.80	)	$	1.01

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


•	Reflect the results of the Devon Assets Acquisition and the Berry acquisition for all periods presented.


•	Reflect incremental depreciation, depletion and amortization expense, using the units-of-production method, related to oil and natural gas properties acquired and using an estimated useful life of 10 years for the Devon Assets Acquisition and 20 years for the Berry acquisition for other property and equipment.


•	Reflect accretion expense related to asset retirement obligations on oil and natural gas properties acquired in the Devon Assets Acquisition.


•	Reflect an increase in interest expense related to incremental debt of $2.3 billion incurred to fund the purchase price of the Devon Assets Acquisition and a reduction in interest expense related to the amortization of the adjustment to fair value of Berry’s debt using the effective interest method.


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


•	Exclude transaction costs related to the Devon Assets Acquisition and the Berry acquisition included in the historical statements of operations as they reflect nonrecurring charges not expected to have a continuing impact on the combined results.


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

Properties Exchange – Pending

On September 18, 2014, the Company, through two of its wholly owned subsidiaries, entered into a definitive agreement to trade a portion of its Permian Basin properties to Exxon Mobil Corporation in exchange for properties in California’s South Belridge Field. The Company anticipates the transaction will close in the fourth quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied.

Divestiture – Subsequent Event

On October 30, 2014, the Company, through a VIE (see above), completed the sale of its interests in certain non-producing oil and natural gas properties located in the Mid-Continent region. Proceeds received for the Company’s interests in the properties were approximately $44 million. The Company intends to ultimately use the proceeds from the sale to repay a portion of the borrowings outstanding under the LINN Credit Facility.

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Divestitures – Pending

On October 2, 2014, the Company, through certain of its wholly owned subsidiaries, entered into a definitive purchase and sale agreement to sell its entire position in the Granite Wash and Cleveland plays located in the Texas Panhandle and western Oklahoma to privately held institutional affiliates of EnerVest, Ltd. (“EnerVest”) and its joint venture partner FourPoint Energy, LLC for a contract price of $1.95 billion, subject to closing adjustments.

On October 1, 2014, the Company, through two of its wholly owned subsidiaries, entered into a definitive purchase and sale agreement to sell certain of its Wolfberry properties in Ector and Midland counties in the Permian Basin to Fleur de Lis Energy, LLC (“Fleur de Lis”) for a contract price of $350 million, subject to closing adjustments.

The EnerVest and Fleur de Lis sales are anticipated to close in the fourth quarter of 2014, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. The Company intends to use the net proceeds from these sales to repay the VIE Term Loan in full as well as repay a portion of the borrowings outstanding under the LINN Credit Facility. At September 30, 2014, the Company’s condensed consolidated balance sheet included current assets of approximately $1.9 billion included in “assets held for sale” and current liabilities of approximately $110 million included in “other accrued liabilities” classified as “held for sale” related to these sales.

Berry Acquisition – 2013

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

Divestiture – 2013

On May 31, 2013, the Company, through one of its wholly owned subsidiaries, together with the Company’s partners, Panther Energy, LLC and Red Willow Mid-Continent, LLC, completed the sale of its interests in certain oil and natural gas properties located in the Mid-Continent region (“Panther Operated Cleveland Properties”) to Midstates Petroleum Company, Inc. At March 31, 2013, the carrying value of the Panther Operated Cleveland Properties was reduced to fair value less costs to sell resulting in an impairment charge of approximately $57 million. During the three months ended June 30, 2013, and September 30, 2013, the Company recorded adjustments of approximately $15 million and $4 million, respectively, to reduce the initial impairment charge recorded in March 2013 resulting in a total impairment charge of approximately $38 million for the nine months ended September 30, 2013. Proceeds received for the Company’s portion of its interests in the properties were approximately $218 million, net of costs to sell of approximately $2 million. The Company used the net proceeds from the sale to repay borrowings under the LINN Credit Facility.

Joint-Venture Funding

For the nine months ended September 30, 2014, the Company paid approximately $25 million, including interest, to fund the commitment related to the joint-venture agreement it entered into with an affiliate of Anadarko Petroleum Corporation (“Anadarko”) in April 2012. As of February 2014, the Company had fully funded the total commitment of $400 million.

Note 3 – Unitholders’ Capital

Distributions

Under the Company’s limited liability company agreement, unitholders are entitled to receive a distribution of available cash, which includes cash on hand plus borrowings less any reserves established by the Company’s Board of Directors to provide for the proper conduct of the Company’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions over the next four quarters. Distributions paid by the Company are presented on the condensed consolidated statement of unitholders’ capital and the condensed consolidated statements of cash flows. On October 1, 2014, the Company’s Board of Directors declared a cash distribution of $0.725 per unit with respect to the third quarter of 2014, to be paid in three equal installments of $0.2416 per unit. The first monthly distribution with respect to the third quarter of 2014, totaling approximately $80 million, was paid on October 16, 2014, to unitholders of record as of the close of business on October 13, 2014.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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:



	September 30, 2014			December 31, 2013
	(in thousands)
Proved properties:
Leasehold acquisition	$	13,045,461		$	12,277,089
Development	3,047,527			3,660,277
Unproved properties	2,043,497			1,951,193
	18,136,485			17,888,559
Less accumulated depletion and amortization	(3,099,637		)	(3,546,284		)
	$	15,036,848		$	14,342,275

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 are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

Based on the analysis described above, for the three months and nine months ended September 30, 2014, the Company recorded a noncash impairment charge, before and after tax, of approximately $603 million associated with proved oil and natural gas properties in the Permian Basin region. The impairment was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for the proved oil and natural gas properties. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair-value measurement. The charge is included in “impairment of long-lived assets” on the condensed consolidated statements of operations. The impairment charge recognized for the three months and nine months ended September 30, 2013, was associated with the write-down of the carrying value of the Panther Operated Cleveland Properties sold in May 2013. See Note 2 for additional information.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Note 5 – Unit-Based Compensation

During the nine months ended September 30, 2014, the Company granted 1,457,677 restricted units and 214,875 phantom units to employees, primarily as part of its annual review of its employees’ compensation, including executives, with an aggregate fair value of approximately $56 million. The restricted units and phantom units vest over three years. The Company also granted 212,524 performance units (the maximum number of units available to be earned) to certain executive officers, with an aggregate fair value of approximately $5 million. The initial 2014 performance unit awards vest 50% in two years and 50% in three years from the award date. A summary of unit-based compensation expenses included on the condensed consolidated statements of operations is presented below:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)

General and administrative expenses	$	9,445	$	8,407	$	37,164	$	25,408
Lease operating expenses	1,664		1,279		6,528		3,853
Total unit-based compensation expenses	$	11,109	$	9,686	$	43,692	$	29,261
Income tax benefit	$	4,105	$	3,579	$	16,144	$	10,812

Note 6 – Debt

The following summarizes the Company’s outstanding debt:



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

LINN credit facility ⁽¹⁾	$	2,510,000		$	1,560,000
Berry credit facility ⁽²⁾	1,173,175			1,173,175
LINN term loan ⁽²⁾	500,000			500,000
VIE term loan ⁽³⁾	1,300,000			—
10.25% Berry senior notes due June 2014	—			205,257
6.50% senior notes due May 2019 ⁽⁴⁾	1,200,000			750,000
6.25% senior notes due November 2019	1,800,000			1,800,000
8.625% senior notes due April 2020	1,300,000			1,300,000
6.75% Berry senior notes due November 2020	299,970			300,000
7.75% senior notes due February 2021	1,000,000			1,000,000
6.50% senior notes due September 2021 ⁽⁴⁾	650,000			—
6.375% Berry senior notes due September 2022	599,163			600,000
Net unamortized discounts and premiums	(22,162		)	(18,216		)
Total debt, net	12,310,146			9,170,216
Less current maturities	(1,300,000		)	(211,558		)
Total long-term debt, net	$	11,010,146		$	8,958,658


⁽¹⁾	Variable interest rates of 2.15% and 1.92% at September 30, 2014, and December 31, 2013, respectively.


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


⁽³⁾	Variable interest rate of 3.15% at September 30, 2014. Incurred on August 29, 2014.

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(Unaudited)


⁽⁴⁾	$450 million of senior notes due May 2019 and $650 million of senior notes due September 2021 were issued on September 9, 2014.

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 loans 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.



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

Credit facilities	$	3,683,175	$	3,683,175	$	2,733,175	$	2,733,175
Term loans	1,800,000		1,800,000		500,000		500,000
Senior notes, net	6,826,971		6,821,718		5,937,041		6,162,402
Total debt, net	$	12,310,146	$	12,304,893	$	9,170,216	$	9,395,577

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 $3.725 billion. At September 30, 2014, the borrowing base under the LINN Credit Facility was $4.225 billion and availability under the revolving credit facility was approximately $1.2 billion, which includes a $5 million reduction for outstanding letters of credit.

In April 2014, the Company entered into an amendment to the LINN Credit Facility to extend the maturity from April 2018 to April 2019, among other items, and in August 2014 and September 2014, the Company entered into amendments to the LINN Credit Facility to permit the Devon Assets Acquisition and the Pioneer Assets Acquisition, respectively, and the related Reverse 1031 Exchanges (see Note 2). As a result of the debt incurred under the Bridge Loan, as defined below, the borrowing base was reduced by 25% of the gross proceeds from the Bridge Loan, or $250 million, to $4.25 billion, resulting in a reduction of availability under the revolving credit facility of $250 million. Additionally, upon the issuance of an aggregate $1.1 billion of senior notes in the September 2014 offering (see below), the borrowing base was further reduced by $25 million to $4.225 billion, resulting in a further reduction of availability under the revolving credit facility of $25 million.

Redetermination of the borrowing base under the LINN Credit Facility, based primarily on reserve reports that reflect commodity prices at such time, occurs semi-annually, in April and October. The administrative agent, at the direction of certain of the lenders, has the right to request one interim borrowing base redetermination per year. The Company also has the right to request one interim borrowing base redetermination per year, as well as the right to an additional interim redetermination each year in connection with certain acquisitions. Significant declines in commodity prices may result in a decrease in the borrowing base. The Company’s obligations under the LINN Credit Facility are secured by mortgages on certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in the Company’s direct and indirect material subsidiaries. The Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on 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, 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

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

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 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”) has a borrowing base of $1.4 billion, subject to lender commitments. At September 30, 2014, lender commitments under the facility were $1.2 billion but there was less than $1 million of available borrowing capacity, including outstanding letters of credit. In February 2014, Berry entered into an amendment to the Berry Credit Facility to amend the terms of certain financial and reporting covenants, among other items, and in April 2014, Berry entered into an amendment to the Berry Credit Facility to extend the maturity from May 2016 to April 2019 and to amend the terms of certain financial covenants and definitions, among other items.

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

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

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

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(Unaudited)

rate per annum between 0.375% and 0.5% (depending on the then-current level of utilization under the Berry Credit Facility) on the average daily unused amount of the maximum commitment amount of the lenders.

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

Bridge Loan

On August 29, 2014, the Company entered into a bridge loan agreement (the “Bridge Loan”) pursuant to which the Company borrowed an aggregate principal amount of $1.0 billion under a term loan. The proceeds from the Bridge Loan were advanced to a VIE and used to partially fund the Devon Assets Acquisition (see Note 2). The Bridge Loan agreement was unsecured and was guaranteed by all of the Company’s material domestic subsidiaries which guarantee the LINN Credit Facility.

The Bridge Loan had an initial maturity date of August 29, 2015, with interest determined by reference to either (i) LIBOR plus 5.0% plus an applicable margin per annum or (ii) alternate base rate plus 4.0% plus an applicable margin per annum. The applicable margin would have been 0% for the first three months after the funding date and, thereafter, increased by 0.50% at the end of each subsequent three-month period.

On September 9, 2014, the Company paid in full the outstanding indebtedness under the Bridge Loan using proceeds from the issuance of the New May 2019 Senior Notes and the September 2021 Senior Notes, each as defined below.

VIE Term Loan

On August 29, 2014, a subsidiary of the VIE, formed to facilitate the Reverse 1031 Exchange for the Devon Assets Acquisition (see Note 2) entered into a 364-day term loan agreement (the “VIE Term Loan”) pursuant to which it borrowed an aggregate principal amount of $1.3 billion under a term loan. The proceeds from the VIE Term Loan were used to partially fund the Devon Assets Acquisition. The obligations under the VIE Term Loan are required to be secured by certain of the oil and natural gas properties and personal property of the VIE’s subsidiary and its material subsidiaries (if any), as well as a pledge of 100% of the equity interests in the subsidiary. Specifically, the VIE’s subsidiary is required to maintain mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report. Additionally, the obligations under the VIE Term Loan are to be guaranteed by all of the material subsidiaries of the VIE’s subsidiary (if any). As of September 30, 2014, there were no guarantors.

The VIE Term Loan may be repaid at the option of the VIE’s subsidiary without premium or penalty, subject to breakage costs. At the VIE subsidiary’s election, interest on the loans under the VIE Term Loan is determined by reference to either (i) LIBOR plus an applicable margin per annum which is 3.0% for the period beginning on the closing date of the term loan agreement and ending on the day that is 180 days thereafter (the “Initial Period”) or (ii) alternate base rate plus an applicable margin per annum which is 2.0% for the Initial Period; in each case, the applicable margin increases by 0.50% for the three-month period beginning after the Initial Period and, thereafter, increases by an additional 0.25% at the end of each subsequent three-month period. Interest is generally payable quarterly for loans bearing interest based on the alternate base rate and at the end of the applicable interest period for loans bearing interest at LIBOR. The VIE Term Loan is required to be prepaid with 100% of the net cash proceeds from nonordinary course asset sales (subject to certain baskets described in the VIE Term Loan) and 100% of the net cash proceeds from the issuance of nonpermitted indebtedness.

The VIE Term Loan contains various covenants, including covenants which limit the ability of the VIE’s subsidiary to: (i) incur indebtedness; (ii) enter into commodity and interest rate swaps; (iii) grant certain liens; (iv) make certain loans, acquisitions, capital contributions and other investments; (v) make distributions; and (vi) merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of assets. The VIE Term Loan also contains (i) a financial covenant which requires the VIE’s subsidiary to maintain a minimum ratio of adjusted earnings to interest expense and (ii) customary events of default.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Senior Notes Due May 2019 and Senior Notes Due September 2021

On September 9, 2014, the Company issued $1.1 billion in aggregate principal amount of senior notes consisting of $450 million aggregate principal amount of 6.50% senior notes due May 2019 (the “New May 2019 Senior Notes”) at a price of 102% of par and $650 million in aggregate principal amount of 6.50% senior notes due September 2021 (the “September 2021 Senior Notes”) at a price of 98.619% of par. The New May 2019 Senior Notes and the September 2021 Senior Notes were registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to a shelf registration statement on Form S-3 filed on September 4, 2014, which was automatically effective upon filing. The Company received net proceeds of approximately $450 million from the issuance of the New May 2019 Senior Notes (after adding the premium of $9 million and deducting offering expenses of approximately $9 million) and approximately $628 million from the issuance of the September 2021 Senior Notes (after deducting the discount of approximately $9 million and offering expenses of approximately $13 million). The Company used the net proceeds from the New May 2019 Senior Notes and the September 2021 Senior Notes to repay all indebtedness outstanding under the Company’s Bridge Loan (see above) and repay a portion of indebtedness outstanding under the LINN Credit Facility. The financing fees and expenses of approximately $22 million incurred in connection with the New May 2019 Senior Notes and the September 2021 Senior Notes will be amortized over the life of the notes. Such amortized expenses, premium and discount are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statements of operations.

The New May 2019 Senior Notes were issued as additional notes under an indenture (the “May 2019 Indenture”), dated as of May 13, 2011, mature May 15, 2019, and bear interest at 6.50%. Interest is payable in cash semi-annually in arrears on each May 15 and November 15, with the next interest payment due on November 15, 2014. Interest will be payable to holders of record on the May 1 and November 1 immediately preceding the related interest payment date, and will be computed on the basis of a 360-day year consisting of twelve 30-day months. The May 2019 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries, other than Berry, has guaranteed the May 2019 Senior Notes on a senior unsecured basis. The May 2019 Indenture provides that the Company may redeem: (i) prior to May 15, 2015, all or part of the May 2019 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the May 2019 Indenture) and accrued and unpaid interest; and (ii) on or after May 15, 2015, all or part of the May 2019 Senior Notes at a redemption price equal to 103.250%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The May 2019 Indenture also provides that, if a change of control (as defined in the May 2019 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the May 2019 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The September 2021 Senior Notes were issued under an indenture dated September 9, 2014 (the “September 2021 Indenture”), mature September 15, 2021, and bear interest at 6.50%. Interest is payable in cash semi-annually in arrears on each March 15 and September 15, commencing March 15, 2015. Interest will be payable to holders of record on the March 1 and September 1 immediately preceding the related interest payment date, and will be computed on the basis of a 360-day year consisting of twelve 30-day months. The September 2021 Senior Notes are general unsecured senior obligations of the Company and are effectively junior in right of payment to any secured indebtedness of the Company to the extent of the collateral securing such indebtedness. Each of the Company’s material subsidiaries, other than Berry, has guaranteed the September 2021 Senior Notes on a senior unsecured basis. The September 2021 Indenture provides that the Company may redeem: (i) prior to September 15, 2017, up to 35% of the aggregate principal amount of the September 2021 Senior Notes at a redemption price of 106.500% of the principal amount redeemed, plus accrued and unpaid interest, with the net cash proceeds of one or more equity offerings; (ii) prior to September 15, 2017, all or part of the September 2021 Senior Notes at a redemption price equal to the principal amount redeemed, plus a make-whole premium (as defined in the September 2021 Indenture) and accrued and unpaid interest; and (iii) on or after September 15, 2017, all or part of the September 2021 Senior Notes at a redemption price equal to 103.250%, and decreasing percentages thereafter, of the principal amount redeemed, plus accrued and unpaid interest. The September 2021 Indenture also provides that, if a change of control (as defined in the September 2021 Indenture) occurs, the holders have a right to require the Company to repurchase all or part of the September 2021 Senior Notes at a redemption price equal to 101%, plus accrued and unpaid interest.

The May 2019 Indenture and the September 2021 Indenture contain covenants that, among other things, limit the Company’s ability and the ability of the Company’s restricted subsidiaries to: (i) pay distributions on, purchase or redeem the Company’s

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(Unaudited)

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.

Senior Notes Due November 2019

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

The terms of the new November 2019 Senior Notes are substantially similar in all material respects to those of the outstanding November 2019 Senior Notes, except that the transfer restrictions, registration rights and additional interest provisions relating to the outstanding November 2019 Senior Notes do not apply to the new November 2019 Senior Notes. The exchange offer expired on June 28, 2014. The effective date of the registration statement was past the deadline in the registration rights agreement, and therefore, the Company paid additional interest of approximately $15 million since the deadline.

Senior Notes Due April 2020 and Senior Notes Due February 2021

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

Berry Senior Notes Due November 2020

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

Berry Senior Notes Due September 2022

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

Repurchases of Berry Senior Notes

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

Payment of Berry June 2014 Senior Notes

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

Senior Notes Covenants

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

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

Note 7 – Derivatives

Commodity Derivatives

The Company hedges a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company directly hedges only its oil and natural gas production. The Company has not entered into any new commodity derivative positions to date in 2014.

The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production to provide an economic hedge of the risk related to the future commodity prices received. The Company does not enter into derivative contracts for trading purposes. In connection with the Berry acquisition (see Note 2), the Company assumed certain derivative contracts that Berry had entered into prior to the acquisition date, including oil swaps, oil trade month roll swaps and oil collars through 2014, and oil basis swaps and oil three-way collars through 2015. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

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



	October 1 - December 31, 2014		2015		2016		2017		2018
Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMMBtu)	24,550		118,041		121,841		120,122		36,500
Average price ($/MMBtu)	$	5.25	$	5.19	$	4.20	$	4.26	$	5.00
Put options (NYMEX Henry Hub):
Hedged volume (MMMBtu)	20,071		71,854		76,269		66,886		—
Average price ($/MMBtu)	$	5.00	$	5.00	$	5.00	$	4.88	$	—

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	October 1 - December 31, 2014			2015			2016			2017			2018
Oil positions:
Fixed price swaps (NYMEX WTI): ⁽¹⁾
Hedged volume (MBbls)	4,242			11,599			11,465			4,755			—
Average price ($/Bbl)	$	92.44		$	96.23		$	90.56		$	89.02		$	—
Collars (NYMEX WTI):
Hedged volume (MBbls)	184			—			—			—			—
Average floor price ($/Bbl)	$	90.00		$	—		$	—		$	—		$	—
Average ceiling price ($/Bbl)	$	102.87		$	—		$	—		$	—		$	—
Three-way collars (NYMEX WTI):
Hedged volume (MBbls)	782			1,095			—			—			—
Short put ($/Bbl)	$	72.11		$	70.00		$	—		$	—		$	—
Long put ($/Bbl)	$	93.76		$	90.00		$	—		$	—		$	—
Short call ($/Bbl)	$	109.79		$	101.62		$	—		$	—		$	—
Put options (NYMEX WTI):
Hedged volume (MBbls)	998			3,426			3,271			384			—
Average price ($/Bbl)	$	91.30		$	90.00		$	90.00		$	90.00		$	—
Three-way collars (ICE Brent):
Hedged volume (MBbls)	92			—			—			—			—
Short put ($/Bbl)	$	80.00		$	—		$	—		$	—		$	—
Long put ($/Bbl)	$	100.00		$	—		$	—		$	—		$	—
Short call ($/Bbl)	$	114.05		$	—		$	—		$	—		$	—
Natural gas basis differential positions: ⁽²⁾
Panhandle basis swaps:
Hedged volume (MMMBtu)	20,010			87,162			59,954			59,138			16,425
Hedged differential ($/MMBtu)	$	(0.33	)	$	(0.33	)	$	(0.32	)	$	(0.33	)	$	(0.33	)
NWPL Rockies basis swaps:
Hedged volume (MMMBtu)	10,398			43,292			46,294			38,880			10,804
Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	(0.19	)	$	(0.19	)
MichCon basis swaps:
Hedged volume (MMMBtu)	2,392			9,344			7,768			7,437			2,044
Hedged differential ($/MMBtu)	$	0.08		$	0.06		$	0.05		$	0.05		$	0.05
Houston Ship Channel basis swaps:
Hedged volume (MMMBtu)	1,325			4,891			4,575			3,604			986
Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.08	)	$	(0.08	)
Permian basis swaps:
Hedged volume (MMMBtu)	1,233			5,074			4,219			4,819			1,314
Hedged differential ($/MMBtu)	$	(0.21	)	$	(0.21	)	$	(0.20	)	$	(0.20	)	$	(0.20	)
Oil basis differential positions:
ICE Brent - NYMEX WTI basis swaps:
Hedged volume (MBbls)	920			2,920			—			—			—
Hedged differential ($/Bbl)	$	11.60		$	11.60		$	—		$	—		$	—

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(Unaudited)



	October 1 - December 31, 2014		2015		2016		2017		2018
Oil timing differential positions:
Trade month roll swaps (NYMEX WTI): ⁽³⁾
Hedged volume (MBbls)	2,289		7,251		7,446		6,486		—
Hedged differential ($/Bbl)	$	0.24	$	0.24	$	0.25	$	0.25	$	—

⁽¹⁾

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


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

⁽³⁾

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

Settled derivatives on natural gas production for the three months and nine months ended September 30, 2014, included volumes of 44,621 MMMBtu and 132,408 MMMBtu, respectively, at an average contract price of $5.14 per MMBtu. Settled derivatives on oil production for the three months and nine months ended September 30, 2014, included volumes of 6,299 MBbls and 18,690 MBbls, respectively, at an average contract price of $92.39 per Bbl. Settled derivatives on natural gas production for the three months and nine months ended September 30, 2013, included volumes of 43,729 MMMBtu and 129,760 MMMBtu, respectively, at an average contract price of $5.29 per MMBtu. Settled derivatives on oil production for the three months and nine months ended September 30, 2013, included volumes of 3,775 MBbls and 11,201 MBbls, respectively, at an average contract price of $95.57 per Bbl. The natural gas derivatives are settled based on the closing price of NYMEX natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing prices of NYMEX WTI and ICE Brent crude oil for each day of the delivery month.

Balance Sheet Presentation

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



	September 30, 2014		December 31, 2013
	(in thousands)
Assets:
Commodity derivatives	$	783,056	$	1,048,212
Liabilities:
Commodity derivatives	$	143,215	$	222,905

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

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value of financial instruments, was approximately $783 million at September 30, 2014. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.

Gains (Losses) on Derivatives

Gains and losses on derivatives were net gains of approximately $452 million for the three months September 30, 2014, and net losses of approximately $199 million for the nine months ended September 30, 2014. Net gains and losses for the three months and nine months ended September 30, 2014, include cash settlement receipts of approximately $10 million and cash settlement payments of approximately $13 million, respectively. Gains and losses on derivatives were net losses of approximately $64 million for the three months ended September 30, 2013, and net gains of approximately $154 million for the nine months ended September 30, 2013. Net gains and losses for the three months and nine months ended September 30, 2013, include cash settlement receipts of approximately $45 million and $190 million, respectively. These amounts are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.”

Note 8 – Fair Value Measurements on a Recurring Basis

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

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



	September 30, 2014
	Level 2		Netting ⁽¹⁾			Total
	(in thousands)
Assets:
Commodity derivatives	$	783,056	$	(140,538	)	$	642,518
Liabilities:
Commodity derivatives	$	143,215	$	(140,538	)	$	2,677



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


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

Note 9 – Asset Retirement Obligations

Asset retirement obligations associated with retiring tangible long-lived assets are recognized as a liability in the period in which a legal obligation is incurred and becomes determinable and are included in “other accrued liabilities” and “other

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noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.0% for the nine months ended September 30, 2014); and (iv) a credit-adjusted risk-free interest rate (average of 5.3% for the nine months ended September 30, 2014). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

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



Asset retirement obligations at December 31, 2013	$	289,321
Liabilities added from acquisitions	146,775
Liabilities added from drilling	8,300
Liabilities reclassified as held for sale	(15,551		)
Liabilities associated with assets divested	(2,129		)
Current year accretion expense	15,203
Settlements	(10,753		)
Revision of estimates	9,130
Asset retirement obligations at September 30, 2014	$	440,296

Note 10 – Commitments and Contingencies

The Company has been named as a defendant in a number of lawsuits, including claims from royalty owners related to disputed royalty payments and royalty valuations. With respect to a certain statewide class action case, the parties in this case are currently engaged in settlement negotiations and based on the current status of those negotiations, the Company estimates a range of possible loss of $1 million to $4.5 million for which an appropriate reserve has been established. For a certain statewide class action royalty payment dispute where a reserve has not yet been established, the Company has denied that it has any liability on the claims and has raised arguments and defenses that, if accepted by the court, will result in no loss to the Company. Briefing and the hearing on class certification are currently scheduled for Summer 2015. The Company is unable to estimate a possible loss, or range of possible loss, if any. In addition, the Company is involved in various other disputes arising in the ordinary course of business. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

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

In 2013, several class action complaints were filed and ultimately consolidated in the United States District Court, Southern District of New York (the “Federal Actions”) against LINN Energy, LinnCo, certain of their officers and directors and the various underwriters for LinnCo’s initial public offering. These cases collectively asserted claims based on allegations that LINN Energy made false or misleading statements relating to its (i) hedging strategy, (ii) the cash flow available for distribution to unitholders, and (iii) LINN Energy’s energy production in its Exchange Act filings; and additional claims based on alleged misstatements relating to these issues in the prospectus and registration statement for LinnCo’s initial public offering. Several derivative actions were also filed in federal and state court in Texas, and in the Delaware Court of Chancery (the “Derivative Actions”) asserting derivative claims on behalf of LINN Energy against the individual officers and directors for alleged breaches of fiduciary duty, waste of corporate assets, mismanagement, abuse of control, and unjust enrichment based on factual allegations similar to those in the Federal Actions.

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plaintiffs in the Federal Action did not appeal the Court’s dismissal, and the appeals deadline has now passed. The plaintiffs in the Derivative Actions subsequently have dismissed their claims without prejudice.

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

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

Note 11 – Earnings Per Unit

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

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands, except per unit data)

Net income (loss)	$	(4,100	)	$	(30,060	)	$	(297,307	)	$	93,212
Allocated to participating securities	(2,097		)	(1,266		)	(6,289		)	(3,796		)
	$	(6,197	)	$	(31,326	)	$	(303,596	)	$	89,416

Basic net income (loss) per unit	$	(0.02	)	$	(0.13	)	$	(0.92	)	$	0.38
Diluted net income (loss) per unit	$	(0.02	)	$	(0.13	)	$	(0.92	)	$	0.38

Basic weighted average units outstanding	329,168			233,552			328,783			233,393
Dilutive effect of unit equivalents	—			—			—			372
Diluted weighted average units outstanding	329,168			233,552			328,783			233,765

Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 6 million unit options and warrants for both the three months and nine months ended September 30, 2014, and approximately 4 million and 3 million for the three months and nine months ended September 30, 2013, respectively. All equivalent units were antidilutive for the three months and nine months ended September 30, 2014, and for the three months ended September 30, 2013.

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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:



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

Accrued compensation	$	43,952	$	55,257
Accrued interest	150,676		93,998
Asset retirement obligations	12,616		6,270
Liabilities held for sale	110,241		—
Other	9,964		7,850
	$	327,449	$	163,375

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



	Nine Months Ended September 30,
	2014			2013
	(in thousands)

Cash payments for interest, net of amounts capitalized	$	345,687		$	240,261
Cash payments for income taxes	$	—		$	14

Noncash investing activities:
In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follows:
Fair value of assets acquired	$	2,743,611		$	47,901
Cash paid	(2,577,180		)	(28,524		)
Noncash gain on properties exchange	(48,333		)	—
Receivables from sellers	42,621			3,654
Payables to sellers	—			(6,854		)
Liabilities assumed	$	160,719		$	16,177

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(Unaudited)

Included in “acquisition of oil and natural gas properties and joint-venture funding” on the condensed consolidated statements of cash flows for the nine months ended September 30, 2014, and September 30, 2013, is approximately $25 million and $112 million, respectively, paid by the Company to fund the commitment related to the joint-venture agreement entered into with Anadarko in April 2012 (see Note 2).

On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed a noncash exchange of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., for properties in the Hugoton Basin.

For purposes of the condensed consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $6 million is included in “other noncurrent assets” on the condensed consolidated balance sheets at September 30, 2014, and December 31, 2013, and primarily represents cash deposited by the Company into a separate account and designated for asset retirement obligations in accordance with contractual agreements.

The Company manages its working capital and cash requirements to borrow only as needed from its Credit Facilities. At September 30, 2014, and December 31, 2013, net outstanding checks of approximately $85 million and $48 million, respectively, were reclassified and included in “accounts payable and accrued expenses” on the condensed consolidated balance sheets. The Company presents net outstanding checks as cash flows from financing activities on the condensed consolidated statements of cash flows.

Note 14 – Related Party Transactions

LinnCo

LinnCo, an affiliate of LINN Energy, was formed on April 30, 2012. LinnCo’s initial sole purpose was to own units in LINN Energy. In connection with the acquisition of Berry, LinnCo amended its limited liability company agreement to permit, among other things, the acquisition and subsequent contribution of assets to LINN Energy. All of LinnCo’s common shares are held by the public. As of September 30, 2014, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy and owned approximately 39% of LINN Energy’s outstanding units.

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

For the three months and nine months ended September 30, 2014, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $644,000 and $2.1 million, respectively, of which approximately $1.9 million had been paid by LINN Energy on LinnCo’s behalf as of September 30, 2014. The expenses for the three months and nine months ended September 30, 2014, include approximately $470,000 and $1.4 million, 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 nine months ended September 30, 2014, LINN Energy paid approximately $11 million on LinnCo’s behalf for general and administrative expenses incurred by LinnCo in 2013.

For the three months and nine months ended September 30, 2013, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $1 million and $15 million, respectively, of which approximately $9 million had been paid by LINN Energy on LinnCo’s behalf as of September 30, 2013. The expenses for the three months and nine months ended September 30, 2013, included approximately $125,000 and $13 million, respectively, of transaction costs related to professional services rendered by third parties in connection with the Berry acquisition. The expenses for the three months and

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nine months ended September 30, 2013, also included approximately $403,000 and $1 million, respectively, related to services provided by LINN Energy necessary for the conduct of LinnCo’s business, such as accounting, legal, tax, information technology and other expenses.

During the three months and nine months ended September 30, 2014, the Company paid approximately $94 million and $280 million, respectively, in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy. During the three months and nine months ended September 30, 2013, the Company paid approximately $25 million and $76 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 nine months ended September 30, 2014, the Company paid approximately $5 million and $17 million, respectively, and for the three months and nine months ended September 30, 2013, the Company paid approximately $7 million and $20 million, respectively, to Superior and its subsidiaries for services rendered to the Company. The transactions associated with these payments were consummated on terms equivalent to those that prevail in arm’s-length transactions.

Note 15 – Subsidiary Guarantors

LINN Energy, LLC’s May 2019 Senior Notes, November 2019 Senior Notes, September 2021 Senior Notes and 2010 Issued Senior Notes are guaranteed by all of the Company’s material subsidiaries, other than Berry which is an indirect 100% wholly owned subsidiary of the Company. In addition, the Company’s consolidated variable interest entity (“VIE”) is not considered a subsidiary and has not guaranteed any of Linn Energy, LLC’s or Berry Petroleum Company, LLC’s indebtedness; therefore, it is presented separately from the other subsidiaries for these purposes.

The following condensed consolidating financial information presents the financial information of LINN Energy, LLC, the guarantor subsidiaries, the non-guarantor subsidiary and the non-guarantor VIE 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, non-guarantor subsidiary or non-guarantor VIE 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.

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CONDENSED CONSOLIDATING BALANCE SHEETS

September 30, 2014



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Non- Guarantor VIE			Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	48		$	11,858		$	6,576		$	40,679		$	—		$	59,161
Accounts receivable – trade, net	—			343,207			133,775			45,651			—			522,633
Accounts receivable – affiliates	3,805,769			16,451			—			—			(3,822,220		)	—
Derivative instruments	—			313,954			23,290			—			—			337,244
Assets held for sale	—			1,485,270			379,770			—			—			1,865,040
Other current assets	18			75,817			45,110			44,567			—			165,512
Total current assets	3,805,835			2,246,557			588,521			130,897			(3,822,220		)	2,949,590

Noncurrent assets:
Oil and natural gas properties (successful efforts method)	—			10,738,434			4,807,794			2,590,257			—			18,136,485
Less accumulated depletion and amortization	—			(2,880,850		)	(208,367		)	(10,420		)	—			(3,099,637		)
	—			7,857,584			4,599,427			2,579,837			—			15,036,848

Other property and equipment	—			508,485			102,496			24,429			—			635,410
Less accumulated depreciation	—			(142,511		)	(6,024		)	(280		)	—			(148,815		)
	—			365,974			96,472			24,149			—			486,595

Derivative instruments	—			302,959			2,315			—			—			305,274
Notes receivable – affiliates	121,500			—			—			—			(121,500		)	—
Advance to related party	1,285,000			1,285,000			—			—			(2,570,000		)	—
Investments in consolidated subsidiaries	8,654,255			—			—			—			(8,654,255		)	—
Other noncurrent assets, net	122,046			11,416			15,225			—			—			148,687
	10,182,801			1,599,375			17,540			—			(11,345,755		)	453,961
Total noncurrent assets	10,182,801			9,822,933			4,713,439			2,603,986			(11,345,755		)	15,977,404
Total assets	$	13,988,636		$	12,069,490		$	5,301,960		$	2,734,883		$	(15,167,975	)	$	18,926,994

LIABILITIES AND UNITHOLDERS’ CAPITAL
Current liabilities:
Accounts payable and accrued expenses	$	3,656		$	545,494		$	248,181		29,645			$	—		$	826,976
Accounts payable – affiliates	—			3,805,769			11,228			5,223			(3,822,220		)	—
Advance from related party	—			1,285,000			—			1,285,000			(2,570,000		)	—
Derivative instruments	—			1,686			911			—			—			2,597
Other accrued liabilities	138,877			171,314			17,031			227			—			327,449
Current portion of long-term debt	—			—			—			1,300,000			—			1,300,000
Total current liabilities	142,533			5,809,263			277,351			2,620,095			(6,392,220		)	2,457,022

Noncurrent liabilities:
Credit facilities	2,510,000			—			1,173,175			—			—			3,683,175
Term loan	500,000			—			—			—			—			500,000
Senior notes, net	5,912,739			—			914,232			—			—			6,826,971
Notes payable – affiliates	—			121,500			—			—			(121,500		)	—
Derivative instruments	—			80			—			—			—			80
Other noncurrent liabilities	—			207,082			200,123			120,408			—			527,613
Total noncurrent liabilities	8,922,739			328,662			2,287,530			120,408			(121,500		)	11,537,839

Unitholders’ capital:
Units issued and outstanding	5,621,068			4,833,046			2,483,181			—			(7,307,458		)	5,629,837
Accumulated income (deficit)	(697,704		)	1,098,519			253,898			(5,620		)	(1,346,797		)	(697,704		)
	4,923,364			5,931,565			2,737,079			(5,620		)	(8,654,255		)	4,932,133
Total liabilities and unitholders’ capital	$	13,988,636		$	12,069,490		$	5,301,960		$	2,734,883		$	(15,167,975	)	$	18,926,994

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2013



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

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

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

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

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

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

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

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended September 30, 2014



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Non- Guarantor VIE			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	542,535		$	350,863		$	44,060		$	—		$	937,458
Gains on oil and natural gas derivatives	—			406,712			44,990			—			—			451,702
Marketing revenues	—			26,518			13,318			—			—			39,836
Other revenues	—			5,874			245			—			—			6,119
	—			981,639			409,416			44,060			—			1,435,115
Expenses:
Lease operating expenses	—			97,613			83,684			10,333			—			191,630
Transportation expenses	—			36,531			13,326			3,555			—			53,412
Marketing expenses	—			23,871			7,703			—			—			31,574
General and administrative expenses	—			52,580			16,566			6,238			—			75,384
Exploration costs	—			7,850			—			—			—			7,850
Depreciation, depletion and amortization	—			199,360			79,725			11,202			—			290,287
Impairment of long-lived assets	—			603,250			—			—			—			603,250
Taxes, other than income taxes	40			38,598			24,830			3,302			—			66,770
(Gains) losses on sale of assets and other, net	—			(93,257		)	49,011			8,443			—			(35,803		)
	40			966,396			274,845			43,073			—			1,284,354
Other income and (expenses):
Interest expense, net of amounts capitalized	(129,129		)	757			(19,068		)	(6,607		)	—			(154,047		)
Interest expense – affiliates	—			(2,218		)	—			—			2,218			—
Interest income – affiliates	2,218			—			—			—			(2,218		)	—
Equity in earnings from consolidated subsidiaries	124,435			—			—			—			(124,435		)	—
Other, net	(1,584		)	(84		)	(179		)	—			—			(1,847		)
	(4,060		)	(1,545		)	(19,247		)	(6,607		)	(124,435		)	(155,894		)
Income (loss) before income taxes	(4,100		)	13,698			115,324			(5,620		)	(124,435		)	(5,133		)
Income tax expense (benefit)	—			(1,192		)	159			—			—			(1,033		)
Net income (loss)	$	(4,100	)	$	14,890		$	115,165		$	(5,620	)	$	(124,435	)	$	(4,100	)

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended September 30, 2013



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary		Non- Guarantor VIE		Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	537,671		$	—	$	—	$	—		$	537,671
Losses on oil and natural gas derivatives	—			(63,931		)	—		—		—			(63,931		)
Marketing revenues	—			13,484			—		—		—			13,484
Other revenues	—			7,338			—		—		—			7,338
	—			494,562			—		—		—			494,562
Expenses:
Lease operating expenses	—			87,076			—		—		—			87,076
Transportation expenses	—			35,637			—		—		—			35,637
Marketing expenses	—			9,962			—		—		—			9,962
General and administrative expenses	—			45,431			—		—		—			45,431
Exploration costs	—			1,588			—		—		—			1,588
Depreciation, depletion and amortization	—			208,892			—		—		—			208,892
Impairment of long-lived assets	—			(4,240		)	—		—		—			(4,240		)
Taxes, other than income taxes	—			36,457			—		—		—			36,457
Losses on sale of assets and other, net	—			827			—		—		—			827
	—			421,630			—		—		—			421,630
Other income and (expenses):
Interest expense, net of amounts capitalized	(103,252		)	(554		)	—		—		—			(103,806		)
Interest expense – affiliates	—			(1,588		)	—		—		1,588			—
Interest income – affiliates	1,588			—			—		—		(1,588		)	—
Loss on extinguishment of debt	(1,117		)	—			—		—		—			(1,117		)
Equity in earnings from consolidated subsidiaries	75,133			—			—		—		(75,133		)	—
Other, net	(2,412		)	(63		)	—		—		—			(2,475		)
	(30,060		)	(2,205		)	—		—		(75,133		)	(107,398		)
Income (loss) before income taxes	(30,060		)	70,727			—		—		(75,133		)	(34,466		)
Income tax benefit	—			(4,406		)	—		—		—			(4,406		)
Net income (loss)	$	(30,060	)	$	75,133		$	—	$	—	$	(75,133	)	$	(30,060	)

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Nine Months Ended September 30, 2014



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Non- Guarantor VIE			Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	1,755,766		$	1,044,359		$	44,060		$	—		$	2,844,185
Gains (losses) on oil and natural gas derivatives	—			(221,472		)	22,893			—			—			(198,579		)
Marketing revenues	—			60,088			40,567			—			—			100,655
Other revenues	—			19,154			238			—			—			19,392
	—			1,613,536			1,108,057			44,060			—			2,765,653
Expenses:
Lease operating expenses	—			293,162			267,069			10,333			—			570,564
Transportation expenses	—			111,539			28,802			3,555			—			143,896
Marketing expenses	—			47,511			28,409			—			—			75,920
General and administrative expenses	—			126,901			88,379			6,238			—			221,518
Exploration costs	—			10,492			—			—			—			10,492
Depreciation, depletion and amortization	—			595,212			226,109			11,202			—			832,523
Impairment of long-lived assets	—			603,250			—			—			—			603,250
Taxes, other than income taxes	40			126,334			71,338			3,302			—			201,014
(Gains) losses on sale of assets and other, net	—			(92,828		)	56,635			8,443			—			(27,750		)
	40			1,821,573			766,741			43,073			—			2,631,427
Other income and (expenses):
Interest expense, net of amounts capitalized	(350,382		)	1,384			(66,555		)	(6,607		)	—			(422,160		)
Interest expense – affiliates	—			(5,627		)	—			—			5,627			—
Interest income – affiliates	5,627			—			—			—			(5,627		)	—
Equity in earnings from consolidated subsidiaries	53,244			—			—			—			(53,244		)	—
Other, net	(5,756		)	(130		)	(813		)	—			—			(6,699		)
	(297,267		)	(4,373		)	(67,368		)	(6,607		)	(53,244		)	(428,859		)
Income (loss) before income taxes	(297,307		)	(212,410		)	273,948			(5,620		)	(53,244		)	(294,633		)
Income tax expense	—			2,597			77			—			—			2,674
Net income (loss)	$	(297,307	)	$	(215,007	)	$	273,871		$	(5,620	)	$	(53,244	)	$	(297,307	)

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Nine Months Ended September 30, 2013



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary		Non- Guarantor VIE		Eliminations			Consolidated
	(in thousands)
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	—		$	1,488,610		$	—	$	—	$	—		$	1,488,610
Gains on oil and natural gas derivatives	—			154,432			—		—		—			154,432
Marketing revenues	—			40,558			—		—		—			40,558
Other revenues	—			18,847			—		—		—			18,847
	—			1,702,447			—		—		—			1,702,447
Expenses:
Lease operating expenses	—			259,381			—		—		—			259,381
Transportation expenses	—			92,118			—		—		—			92,118
Marketing expenses	—			26,696			—		—		—			26,696
General and administrative expenses	—			150,302			—		—		—			150,302
Exploration costs	—			4,632			—		—		—			4,632
Depreciation, depletion and amortization	—			604,962			—		—		—			604,962
Impairment of long-lived assets	—			37,962			—		—		—			37,962
Taxes, other than income taxes	—			108,525			—		—		—			108,525
Losses on sale of assets and other, net	724			2,316			—		—		—			3,040
	724			1,286,894			—		—		—			1,287,618
Other income and (expenses):
Interest expense, net of amounts capitalized	(307,316		)	(696		)	—		—		—			(308,012		)
Interest expense – affiliates	—			(4,142		)	—		—		4,142			—
Interest income – affiliates	4,142			—			—		—		(4,142		)	—
Loss on extinguishment of debt	(5,304		)	—			—		—		—			(5,304		)
Equity in earnings from consolidated subsidiaries	408,602			—			—		—		(408,602		)	—
Other, net	(6,188		)	(112		)	—		—		—			(6,300		)
	93,936			(4,950		)	—		—		(408,602		)	(319,616		)
Income before income taxes	93,212			410,603			—		—		(408,602		)	95,213
Income tax expense	—			2,001			—		—		—			2,001
Net income	$	93,212		$	408,602		$	—	$	—	$	(408,602	)	$	93,212

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2014



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Non- Guarantor VIE			Eliminations			Consolidated
	(in thousands)
Cash flow from operating activities:
Net income (loss)	$	(297,307	)	$	(215,007	)	$	273,871		$	(5,620	)	$	(53,244	)	$	(297,307	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	—			595,212			226,109			11,202			—			832,523
Impairment of long-lived assets	—			603,250			—			—			—			603,250
Unit-based compensation expenses	—			43,692			—			—			—			43,692
Amortization and write-off of deferred financing fees	31,564			—			(5,174		)	2,846			—			29,236
(Gains) losses on sale of assets and other, net	—			(81,492		)	48,357			—			—			(33,135		)
Equity in earnings from consolidated subsidiaries	(53,244		)	—			—			—			53,244			—
Deferred income taxes	—			2,542			77			—			—			2,619
Derivatives activities:
Total (gains) losses	—			221,472			(22,893		)	—			—			198,579
Cash settlements	—			5,623			(18,130		)	—			—			(12,507		)
Changes in assets and liabilities:
Increase in accounts receivable – trade, net	—			(1,343		)	(10,611		)	(44,060		)	—			(56,014		)
Decrease in accounts receivable – affiliates	469,499			16,950			—			—			(486,449		)	—
(Increase) decrease in other assets	312			(10,723		)	4,551			9,144			—			3,284
(Increase) decrease in accounts payable and accrued expenses	18			107,673			(10,619		)	15,163			—			112,235
Decrease in accounts payable and accrued expenses – affiliates	—			(468,896		)	(5,722		)	(11,831		)	486,449			—
Increase (decrease) in other liabilities	63,806			(18,053		)	(36,626		)	228			—			9,355
Net cash provided by (used in) operating activities	214,648			800,900			443,190			(22,928		)	—			1,435,810

Table of Contents

LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary			Non- Guarantor VIE			Eliminations			Consolidated
	(in thousands)
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			(76,627		)	(3,912		)	(2,521,393		)	—			(2,601,932		)
Development of oil and natural gas properties	—			(750,450		)	(426,028		)	—			—			(1,176,478		)
Purchases of other property and equipment	—			(41,822		)	(8,316		)	—			—			(50,138		)
Investment in affiliates	(167,721		)	—			—			—			167,721			—
Change in notes receivable with affiliate	(35,300		)	—			—			—			35,300			—
Advance to related party	(1,285,000		)	(1,285,000		)	—			—			2,570,000			—
Proceeds from sale of properties and equipment and other	(13,188		)	5,447			256			—			—			(7,485		)
Net cash used in investing activities	(1,501,209		)	(2,148,452		)	(438,000		)	(2,521,393		)	2,773,021			(3,836,033		)

Cash flow from financing activities:
Proceeds from borrowings	4,000,024			—			—			1,300,000			—			5,300,024
Repayments of debt	(1,950,000		)	—			(206,124		)	—			—			(2,156,124		)
Distributions to unitholders	(721,235		)	—			—			—			—			(721,235		)
Financing fees and other, net	(46,263		)	38,032			(11,252		)	—			—			(19,483		)
Change in notes payable with affiliate	—			35,300			—			—			(35,300		)	—
Advance from related party	—			1,285,000			—			1,285,000			(2,570,000		)	—
Capital contributions – affiliates	—			—			167,721			—			(167,721		)	—
Excess tax benefit from unit-based compensation	4,031			—			—			—			—			4,031
Net cash provided by (used in) financing activities	1,286,557			1,358,332			(49,655		)	2,585,000			(2,773,021		)	2,407,213

Net increase (decrease) in cash and cash equivalents	(4		)	10,780			(44,465		)	40,679			—			6,990
Cash and cash equivalents:
Beginning	52			1,078			51,041			—			—			52,171
Ending	$	48		$	11,858		$	6,576		$	40,679		$	—		$	59,161

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2013



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary		Non- Guarantor VIE	Eliminations			Consolidated
	(in thousands)
Cash flow from operating activities:
Net income	$	93,212		$	408,602		$	—	—	$	(408,602	)	$	93,212
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	—			604,962			—		—	—			604,962
Impairment of long-lived assets	—			37,962			—		—	—			37,962
Unit-based compensation expenses	—			29,261			—		—	—			29,261
Loss on extinguishment of debt	5,304			—			—		—	—			5,304
Amortization and write-off of deferred financing fees	16,392			—			—		—	—			16,392
Losses on sale of assets and other, net	—			18,744			—		—	—			18,744
Equity in earnings from consolidated subsidiaries	(408,602		)	—			—		—	408,602			—
Deferred income taxes	—			731			—		—	—			731
Derivatives activities:
Total gains	—			(154,432		)	—		—	—			(154,432		)
Cash settlements	—			190,368			—		—	—			190,368
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net	—			22,877			—		—	—			22,877
Decrease in accounts receivable – affiliates	341,730			—			—		—	(341,730		)	—
(Increase) decrease in other assets	(330		)	9,507			—		—	—			9,177
Increase in accounts payable and accrued expenses	—			29,445			—		—	—			29,445
Decrease in accounts payable and accrued expenses – affiliates	—			(341,730		)	—		—	341,730			—
Increase (decrease) in other liabilities	51,069			(14,561		)	—		—	—			36,508
Net cash provided by operating activities	98,775			841,736			—		—	—			940,511

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LINN ENERGY, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – Continued

(Unaudited)



	LINN Energy, LLC			Guarantor Subsidiaries			Non- Guarantor Subsidiary		Non- Guarantor VIE		Eliminations			Consolidated
	(in thousands)
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	—			(192,871		)	—		—		—			(192,871		)
Development of oil and natural gas properties	—			(767,604		)	—		—		—			(767,604		)
Purchases of other property and equipment	—			(76,987		)	—		—		—			(76,987		)
Change in notes receivable with affiliate	(38,200		)	—			—		—		38,200			—
Proceeds from sale of properties and equipment and other	(9,044		)	219,341			—		—		—			210,297
Net cash used in investing activities	(47,244		)	(818,121		)	—		—		38,200			(827,165		)

Cash flow from financing activities:
Proceeds from borrowings	1,260,000			—			—		—		—			1,260,000
Repayments of debt	(789,898		)	—			—		—		—			(789,898		)
Distributions to unitholders	(511,686		)	—			—		—		—			(511,686		)
Financing fees and other, net	(13,490		)	(32,195		)	—		—		—			(45,685		)
Change in notes payable with affiliate	—			38,200			—		—		(38,200		)	—
Excess tax benefit from unit-based compensation	—			160			—		—		—			160
Net cash provided by (used in) financing activities	(55,074		)	6,165			—		—		(38,200		)	(87,109		)

Net increase (decrease) in cash and cash equivalents	(3,543		)	29,780			—		—		—			26,237
Cash and cash equivalents:
Beginning	107			1,136			—		—		—			1,243
Ending	$	(3,436	)	$	30,916		$	—	$	—	$	—		$	27,480

Note 16 – SEC Inquiry

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

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

The following discussion contains forward-looking statements that reflect the Company’s future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside the Company’s control. The Company’s actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement” below and in Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q and in the Annual Report on Form 10-K for the year ended December 31, 2013, and elsewhere in the Annual Report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

The following discussion and analysis should be read in conjunction with the financial statements and related notes included in this Quarterly Report on Form 10-Q and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013. The reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”

Executive Overview

LINN Energy’s mission is to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. LINN Energy is an independent oil and natural gas company that began operations in March 2003 and completed its initial public offering in January 2006. The Company’s properties 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);


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


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


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


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


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


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


•	South Texas.

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


•	oil, natural gas and NGL sales of approximately $937 million compared to $538 million for the third quarter of 2013;


•	average daily production of approximately 1,245 MMcfe/d compared to 823 MMcfe/d for the third quarter of 2013;


•	net loss of approximately $4 million compared to $30 million for the third quarter of 2013;


•	capital expenditures, excluding acquisitions, of approximately $369 million compared to $306 million for the third quarter of 2013; and


•	210 wells drilled (all successful) compared to 118 wells drilled (all successful) for the third quarter of 2013.

Results for the nine months ended September 30, 2014, included the following:


•	oil, natural gas and NGL sales of approximately $2.8 billion compared to $1.5 billion for the nine months ended September 30, 2013;


•	average daily production of approximately 1,160 MMcfe/d compared to 800 MMcfe/d for the nine months ended September 30, 2013;


•	net loss of approximately $297 million compared to net income of $93 million for the nine months ended September 30, 2013;


•	net cash provided by operating activities of approximately $1.4 billion compared to $941 million for the nine months ended September 30, 2013;


•	capital expenditures, excluding acquisitions, of approximately $1.2 billion compared to $912 million for the nine months ended September 30, 2013; and


•	678 wells drilled (677 successful) compared to 376 wells drilled (all successful) for the nine months ended September 30, 2013.

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

Properties Exchange

On August 15, 2014, the Company, through two of its wholly owned subsidiaries, completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc. (collectively, “ExxonMobil”), in exchange for properties in the Hugoton Basin. The Company received approximately 659 Bcfe of proved reserves, primarily natural gas, as of the exchange date, while ExxonMobil received approximately 25,000 net acres in the Midland Basin, which are located primarily in Midland, Martin, Upton and Glasscock counties, and approximately 168 Bcfe of proved reserves.

Acquisitions

The Pioneer Assets Acquisition and the Devon Assets Acquisition were structured as reverse like-kind exchanges pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchanges”). In connection with the Reverse 1031 Exchanges, the Company, through a subsidiary, assigned the rights to acquire legal title to the oil and natural gas properties from Pioneer and Devon to a VIE formed by an exchange accommodation titleholder. A subsidiary of LINN Energy operates the properties pursuant to a management agreement with the VIE. Because the Company is the primary beneficiary of the VIE, the VIE is included in the condensed consolidated financial statements.

The assets currently held by the VIE attributable to the Pioneer Assets Acquisition and the Devon Assets Acquisition will be conveyed to LINN Energy and its subsidiaries, and the VIE structure will terminate, upon the earlier of (i) completion of the Reverse 1031 Exchanges (which the Company expects to occur upon closing of the pending sales of its Granite Wash assets and certain of its Wolfberry properties) or (ii) the expiration of the time allowed by IRS rules and regulations to complete the Reverse 1031 Exchanges.

Properties Exchange – Pending

Divestiture

Divestitures – Pending

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

Oklahoma to privately held institutional affiliates of EnerVest, Ltd. (“EnerVest”) and its joint venture partner FourPoint Energy, LLC for a contract price of $1.95 billion, subject to closing adjustments.

Financing and Liquidity

In September 2014, the Company issued $450 million in aggregate principal amount of 6.50% senior notes due May 2019 (the “New May 2019 Senior Notes”) and $650 million in aggregate principal amount of 6.50% senior notes due September 2021 (the “September 2021 Senior Notes”) (see Note 6). The Company used the net proceeds of approximately $1.1 billion to repay all indebtedness outstanding under its Bridge Loan, as defined below, and repay a portion of indebtedness under the LINN Credit Facility.

In August 2014, the Company entered into a bridge loan agreement (the “Bridge Loan”) pursuant to which the Company borrowed an aggregate principal amount of $1.0 billion under a term loan. The proceeds from the Bridge Loan were advanced to a VIE and used to partially fund the Devon Assets Acquisition (see Note 2). In September 2014, the Company paid in full the outstanding indebtedness under the Bridge Loan using proceeds from the issuance of the New May 2019 Senior Notes and the September 2021 Senior Notes.

In August 2014, a subsidiary of the VIE formed to facilitate the Reverse 1031 Exchange for the Devon Assets Acquisition (see Note 2) entered into a 364-day term loan agreement (the “VIE Term Loan”) pursuant to which it borrowed an aggregate principal amount of $1.3 billion under a term loan. The proceeds from the VIE Term Loan were used to partially fund the Devon Assets Acquisition.

In April 2014, the Company entered into an amendment to the LINN Credit Facility to extend the maturity from April 2018 to April 2019, among other items, and in August 2014 and September 2014, the Company entered into amendments to the LINN Credit Facility to permit the Devon Assets Acquisition and the Pioneer Assets Acquisition, respectively, and the related Reverse 1031 Exchanges (see Note 2). As a result of the debt incurred under the Bridge Loan, the borrowing base was reduced by 25% of the gross proceeds from the Bridge Loan, or $250 million, to $4.25 billion, resulting in a reduction of availability under the revolving credit facility of $250 million. Additionally, upon the issuance of an aggregate $1.1 billion of senior notes in the September 2014 offering (see above), the borrowing base was further reduced by $25 million to $4.225 billion, resulting in a further reduction of availability under the revolving credit facility of $25 million.

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

On March 22, 2013, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the 6.25% senior notes due November 2019 (the “November 2019 Senior Notes”), except that the transfer restrictions, registration rights and additional interest provisions relating to the outstanding November 2019 Senior Notes do not apply to the new November 2019 Senior Notes. On June 2, 2014, the registration statement was declared effective and the

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

Company commenced an offer to exchange any and all of its $1.8 billion outstanding principal amount of November 2019 Senior Notes for an equal amount of new November 2019 Senior Notes. The exchange offer expired on June 28, 2014.

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



	Three Months Ended September 30,
	2014			2013			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	221,374		$	148,614		$	72,760
Oil sales	614,407			307,209			307,198
NGL sales	101,677			81,848			19,829
Total oil, natural gas and NGL sales	937,458			537,671			399,787
Gains (losses) on oil and natural gas derivatives	451,702			(63,931		)	515,633
Marketing and other revenues	45,955			20,822			25,133
	1,435,115			494,562			940,553
Expenses:
Lease operating expenses	191,630			87,076			104,554
Transportation expenses	53,412			35,637			17,775
Marketing expenses	31,574			9,962			21,612
General and administrative expenses ⁽¹⁾	75,384			45,431			29,953
Exploration costs	7,850			1,588			6,262
Depreciation, depletion and amortization	290,287			208,892			81,395
Impairment of long-lived assets	603,250			(4,240		)	607,490
Taxes, other than income taxes	66,770			36,457			30,313
(Gains) losses on sale of assets and other, net	(35,803		)	827			(36,630		)
	1,284,354			421,630			862,724
Other income and (expenses)	(155,894		)	(107,398		)	(48,496		)
Loss before income taxes	(5,133		)	(34,466		)	29,333
Income tax benefit	(1,033		)	(4,406		)	3,373
Net loss	$	(4,100	)	$	(30,060	)	$	25,960


⁽¹⁾	General and administrative expenses for the three months ended September 30, 2014, and September 30, 2013, include approximately $9 million and $8 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 September 30,
	2014		2013		Variance
Average daily production:
Natural gas (MMcf/d)	600		458		31	%
Oil (MBbls/d)	74.0		32.4		128	%
NGL (MBbls/d)	33.5		28.4		18	%
Total (MMcfe/d)	1,245		823		51	%

Weighted average prices: ⁽¹⁾
Natural gas (Mcf)	$	4.01	$	3.53	14	%
Oil (Bbl)	$	90.31	$	103.07	(12	)%
NGL (Bbl)	$	33.01	$	31.35	5	%

Average NYMEX prices:
Natural gas (MMBtu)	$	4.06	$	3.58	13	%
Oil (Bbl)	$	97.17	$	105.82	(8	)%

Costs per Mcfe of production:
Lease operating expenses	$	1.67	$	1.15	45	%
Transportation expenses	$	0.47	$	0.47	—
General and administrative expenses ⁽²⁾	$	0.66	$	0.60	10	%
Depreciation, depletion and amortization	$	2.54	$	2.76	(8	)%
Taxes, other than income taxes	$	0.58	$	0.48	21	%


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


⁽²⁾	General and administrative expenses for the three months ended September 30, 2014, and September 30, 2013, include approximately $9 million and $8 million, respectively, of noncash unit-based compensation expenses.

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

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales increased by approximately $399 million or 74% to approximately $937 million for the three months ended September 30, 2014, from approximately $538 million for the three months ended September 30, 2013, due to higher production volumes and higher natural gas and NGL prices partially offset by lower oil prices. Higher natural gas and NGL prices resulted in an increase in revenues of approximately $27 million and $5 million, respectively. Lower oil prices resulted in a decrease in revenues of approximately $87 million.

Average daily production volumes increased to approximately 1,245 MMcfe/d for the three months ended September 30, 2014, from 823 MMcfe/d for the three months ended September 30, 2013. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $393 million, $46 million and $15 million, respectively.

The following table sets forth average daily production by region:



	Three Months Ended September 30,
	2014	2013	Variance
Average daily production (MMcfe/d):
Rockies	333	186	147		79	%
Mid-Continent	289	344	(55	)	(16	)%
California	172	13	159		1,225	%
Hugoton Basin	201	146	55		38	%
Permian Basin	154	78	76		98	%
TexLa	51	22	29		128	%
Michigan/Illinois	33	34	(1	)	(2	)%
South Texas	12	—	12		—	%
	1,245	823	422		51	%

The increase in average daily production volumes in the Rockies region primarily reflects the impact of the Berry acquisition in December 2013, the Devon Assets Acquisition on August 29, 2014, and development capital spending. The decrease in average daily production volumes in the Mid-Continent region primarily reflects decreased development capital spending in the Granite Wash partially offset by the impact of the Devon Assets Acquisition. The increase in average daily production volumes in the California region primarily reflects the impact of the Berry acquisition. The increase in average daily production volumes in the Hugoton Basin region primarily reflects the impact of the properties received in the exchange with ExxonMobil on August 15, 2014, the Pioneer Assets Acquisition on September 11, 2014, and development capital spending. The increase in average daily production volumes in the Permian Basin region primarily reflects the impact of an acquisition in October 2013, the Berry acquisition and development capital spending, partially offset by decreased production volumes related to the properties relinquished in the exchange with ExxonMobil. The increase in average daily production volumes in the TexLa region primarily reflects the impact of the Berry acquisition and the Devon Assets Acquisition. The Michigan/Illinois region consists of a low-decline asset base and continues to produce at consistent levels. Average daily production volumes in the South Texas region reflect the impact of the Devon Assets Acquisition.

Gains (Losses) on Oil and Natural Gas Derivatives

Gains on oil and natural gas derivatives were approximately $452 million for the three months ended September 30, 2014, compared to losses of approximately $64 million for the three months ended September 30, 2013, representing a variance of approximately $516 million. Gains on oil and natural gas derivatives were primarily due to changes in fair value on unsettled 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 September 30, 2014, the Company had commodity derivative contracts for approximately 81% of its natural gas production and 93% of its oil production. During the three months ended September 30, 2013, the Company had commodity derivative contracts for approximately 104% of its natural gas production and 127% of its oil production.

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

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

Marketing and Other Revenues

Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing and other revenues increased by approximately $25 million or 121% to approximately $46 million for the three months ended September 30, 2014, from approximately $21 million for the three months ended September 30, 2013. The increase was primarily due to electricity sales revenues generated by the Company’s California cogeneration facilities acquired and certain contracts assumed in the Berry acquisition in December 2013, as well as higher revenues generated from the Jayhawk natural gas processing plant.

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $105 million or 120% to approximately $192 million for the three months ended September 30, 2014, from approximately $87 million for the three months ended September 30, 2013. Lease operating expenses increased primarily due to costs associated with properties acquired in the Berry acquisition and acquisitions during the third quarter of 2014 (see Note 2). Lease operating expenses per Mcfe also increased to $1.67 per Mcfe for the three months ended September 30, 2014, from $1.15 per Mcfe for the three months ended September 30, 2013, primarily due to higher unit rates on newly acquired oil properties.

Transportation Expenses

Transportation expenses increased by approximately $17 million or 50% to approximately $53 million for the three months ended September 30, 2014, from approximately $36 million for the three months ended September 30, 2013, primarily due to the Berry acquisition and acquisitions during the third quarter of 2014. Transportation expenses were $0.47 per Mcfe for both the three months ended September 30, 2014, and September 30, 2013.

Marketing Expenses

Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $22 million or 217% to approximately $32 million for the three months ended September 30, 2014, from approximately $10 million for the three months ended September 30, 2013. The increase was primarily due to electricity generation expenses incurred by the Company’s California cogeneration facilities acquired and certain contracts assumed in the Berry acquisition, as well as higher expenses associated with the Jayhawk natural gas processing plant.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. General and administrative expenses increased by approximately $30 million or 66% to approximately $75 million for the three months ended September 30, 2014, from approximately $45 million for the three months ended September 30, 2013. The increase was primarily due to higher salaries and benefits related expenses, primarily driven by increased employee headcount and unit-based compensation, higher non-payroll related acquisition expenses, higher professional services expenses and higher various other administrative expenses. General and administrative expenses per Mcfe also increased to $0.66 per Mcfe for the three months ended September 30, 2014, from $0.60 per Mcfe for the three months ended September 30, 2013.

Exploration Costs

Exploration costs increased by approximately $6 million or 394% to approximately $8 million for the three months ended September 30, 2014, from approximately $2 million for the three months ended September 30, 2013. The increase was primarily due to higher leasehold impairment expenses on unproved properties.

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

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $81 million or 39% to approximately $290 million for the three months ended September 30, 2014, from approximately $209 million for the three months ended September 30, 2013. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per Mcfe decreased to $2.54 per Mcfe for the three months ended September 30, 2014, from $2.76 per Mcfe for the three months ended September 30, 2013, primarily due to a lower rate in the Granite Wash formation as a result of the impairment recorded in the prior year.

Impairment of Long-Lived Assets

During the three months ended September 30, 2014, the Company recorded a noncash impairment charge, before and after tax, of approximately $603 million associated with proved oil and natural gas properties in the Permian Basin region. The impairment was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for the proved oil and natural gas properties. During the three months ended September 30, 2013, the Company recorded an adjustment of approximately $4 million to reflect the fair value less costs to sell the Panther Operated Cleveland Properties sold in May 2013 (see Note 2). An initial adjustment of approximately $15 million was recorded during the second quarter of 2013.

(Gains) Losses on Sale of Assets and Other, Net

During the three months ended September 30, 2014, the Company recorded a net gain of approximately $45 million, including costs to sell of approximately $3 million, on the noncash exchange of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., for properties in the Hugoton Basin (see Note 2).

Taxes, Other Than Income Taxes



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

Severance taxes	$	37,986	$	26,075	$	11,911
Ad valorem taxes	24,513		10,212		14,301
California carbon allowances	4,202		89		4,113
Other	69		81		(12		)
	$	66,770	$	36,457	$	30,313

Taxes, other than income taxes increased by approximately $30 million or 83% for the three months ended September 30, 2014, compared to the three months ended September 30, 2013. Severance taxes, which are a function of revenues generated from production, increased primarily due to higher production volumes and higher natural gas and NGL prices partially offset by lower oil prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to the Berry acquisition and acquisitions during the third quarter of 2014. California carbon allowances increased primarily due to the Berry acquisition.

Other Income and (Expenses)



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

Interest expense, net of amounts capitalized	$	(154,047	)	$	(103,806	)	$	(50,241	)
Loss on extinguishment of debt	—			(1,117		)	1,117
Other, net	(1,847		)	(2,475		)	628
	$	(155,894	)	$	(107,398	)	$	(48,496	)

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

Other income and (expenses) increased by approximately $48 million for the three months ended September 30, 2014, compared to the three months ended September 30, 2013. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with the Bridge Loan, the VIE Term Loan, the senior notes issued in September 2014 and amendments made to the Company’s Credit Facilities during 2013 and 2014. In addition, for the three months ended September 30, 2013, the Company recorded a loss on extinguishment of debt of approximately $1 million as a result of the redemption of the remaining outstanding 2018 Senior Notes. See “Debt” in “Liquidity and Capital Resources” below for additional details.

Income Tax Expense (Benefit)

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized an income tax benefit of approximately $1 million and $4 million for the three months ended September 30, 2014, and September 30, 2013, respectively. Income tax benefit decreased primarily due to higher income from the Company’s taxable subsidiaries during the three months ended September 30, 2014, compared to the same period in 2013.

Net Income (Loss)

Net loss decreased by approximately $26 million to approximately $4 million for the three months ended September 30, 2014, from approximately $30 million for the three months ended September 30, 2013. The decrease was primarily due to higher production revenues and higher gains on oil and natural gas derivatives, partially offset by higher impairment charges and other expenses, including interest. 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

Nine Months Ended September 30, 2014, Compared to Nine Months Ended September 30, 2013



	Nine Months Ended September 30,
	2014			2013			Variance
	(in thousands)
Revenues and other:
Natural gas sales	$	653,113		$	444,124		$	208,989
Oil sales	1,861,561			810,919			1,050,642
NGL sales	329,511			233,567			95,944
Total oil, natural gas and NGL sales	2,844,185			1,488,610			1,355,575
Gains (losses) on oil and natural gas derivatives	(198,579		)	154,432			(353,011		)
Marketing and other revenues	120,047			59,405			60,642
	2,765,653			1,702,447			1,063,206
Expenses:
Lease operating expenses	570,564			259,381			311,183
Transportation expenses	143,896			92,118			51,778
Marketing expenses	75,920			26,696			49,224
General and administrative expenses ⁽¹⁾	221,518			150,302			71,216
Exploration costs	10,492			4,632			5,860
Depreciation, depletion and amortization	832,523			604,962			227,561
Impairment of long-lived assets	603,250			37,962			565,288
Taxes, other than income taxes	201,014			108,525			92,489
(Gains) losses on sale of assets and other, net	(27,750		)	3,040			(30,790		)
	2,631,427			1,287,618			1,343,809
Other income and (expenses)	(428,859		)	(319,616		)	(109,243		)
Income (loss) before income taxes	(294,633		)	95,213			(389,846		)
Income tax expense	2,674			2,001			673
Net income (loss)	$	(297,307	)	$	93,212		$	(390,519	)


⁽¹⁾	General and administrative expenses for the nine months ended September 30, 2014, and September 30, 2013, include approximately $37 million and $25 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



	Nine Months Ended September 30,
	2014		2013		Variance
Average daily production:
Natural gas (MMcf/d)	525		443		19	%
Oil (MBbls/d)	73.2		31.4		133	%
NGL (MBbls/d)	32.6		28.0		16	%
Total (MMcfe/d)	1,160		800		45	%

Weighted average prices: ⁽¹⁾
Natural gas (Mcf)	$	4.56	$	3.67	24	%
Oil (Bbl)	$	93.10	$	94.70	(2	)%
NGL (Bbl)	$	37.01	$	30.54	21	%

Average NYMEX prices:
Natural gas (MMBtu)	$	4.55	$	3.67	24	%
Oil (Bbl)	$	99.61	$	98.14	1	%

Costs per Mcfe of production:
Lease operating expenses	$	1.80	$	1.19	51	%
Transportation expenses	$	0.45	$	0.42	7	%
General and administrative expenses ⁽²⁾	$	0.70	$	0.69	1	%
Depreciation, depletion and amortization	$	2.63	$	2.77	(5	)%
Taxes, other than income taxes	$	0.63	$	0.50	26	%


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


⁽²⁾	General and administrative expenses for the nine months ended September 30, 2014, and September 30, 2013, include approximately $37 million and $25 million, respectively, of noncash unit-based compensation expenses.

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

Revenues and Other

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales increased by approximately $1.3 billion or 91% to approximately $2.8 billion for the nine months ended September 30, 2014, from approximately $1.5 billion for the nine months ended September 30, 2013, due to higher production volumes and higher natural gas and NGL prices partially offset by lower oil prices. Higher natural gas and NGL prices resulted in an increase in revenues of approximately $127 million and $58 million, respectively. Lower oil prices resulted in a decrease in revenues of approximately $32 million.

Average daily production volumes increased to approximately 1,160 MMcfe/d for the nine months ended September 30, 2014, from 800 MMcfe/d for the nine months ended September 30, 2013. Higher oil, natural gas and NGL production volumes resulted in an increase in revenues of approximately $1.1 billion, $82 million and $38 million, respectively.

The following sets forth average daily production by region:



	Nine Months Ended September 30,
	2014	2013	Variance
Average daily production (MMcfe/d):
Rockies	295	180	115		64	%
Mid-Continent	295	327	(32	)	(10	)%
California	167	13	154		1,215	%
Hugoton Basin	165	143	22		16	%
Permian Basin	163	81	82		102	%
TexLa	38	22	16		74	%
Michigan/Illinois	33	34	(1	)	(2	)%
South Texas	4	—	4		—	%
	1,160	800	360		45	%

Gains (Losses) on Oil and Natural Gas Derivatives

Losses on oil and natural gas derivatives were approximately $199 million for the nine months ended September 30, 2014, compared to gains of approximately $154 million for the nine months ended September 30, 2013, representing a variance of approximately $353 million. Losses on oil and natural gas derivatives were primarily due to changes in fair value on unsettled derivatives contracts and lower cash settlements during the period. The results for 2014 and 2013 also include gains of approximately $3 million and $5 million, respectively, related to the recoveries of a bankruptcy claim (see Note 10). The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.

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

During the nine months ended September 30, 2014, the Company had commodity derivative contracts for approximately 92% of its natural gas production and 93% of its oil production. During the nine months ended September 30, 2013, the Company had commodity derivative contracts for approximately 107% of its natural gas production and 131% of its oil production.

Marketing and Other Revenues

Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing and other revenues increased by approximately $61 million or 102% to approximately $120 million for the nine months ended September 30, 2014, from approximately $59 million for the nine months ended September 30, 2013. The increase was primarily due to electricity sales revenues generated by the Company’s California cogeneration facilities acquired and certain contracts assumed in the Berry acquisition in December 2013, as well as higher revenues generated from the Jayhawk natural gas processing plant.

Expenses

Lease Operating Expenses

Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses. Lease operating expenses increased by approximately $312 million or 120% to approximately $571 million for the nine months ended September 30, 2014, from approximately $259 million for the nine months ended September 30, 2013. Lease operating expenses increased primarily due to costs associated with properties acquired in the Berry acquisition and acquisitions during the third quarter of 2014 (see Note 2). Lease operating expenses per Mcfe also increased to $1.80 per Mcfe for the nine months ended September 30, 2014, from $1.19 per Mcfe for the nine months ended September 30, 2013, primarily due to higher unit rates on newly acquired oil properties.

Transportation Expenses

Transportation expenses increased by approximately $52 million or 56% to approximately $144 million for the nine months ended September 30, 2014, from approximately $92 million for the nine months ended September 30, 2013, primarily due to the Berry acquisition and acquisitions during the third quarter of 2014. Transportation expenses per Mcfe also increased to $0.45 per Mcfe for the nine months ended September 30, 2014, from $0.42 per Mcfe for the nine months ended September 30, 2013, primarily due to higher rates on Berry properties acquired in the Rockies region.

Marketing Expenses

Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses increased by approximately $49 million or 184% to approximately $76 million for the nine months ended September 30, 2014, from approximately $27 million for the nine months ended September 30, 2013. The increase was primarily due to electricity generation expenses incurred by the Company’s California cogeneration facilities acquired and certain contracts assumed in the Berry acquisition, as well as higher expenses associated with the Jayhawk natural gas processing plant.

General and Administrative Expenses

General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. General and administrative expenses increased by approximately $72 million or 47% to approximately $222 million for the nine months ended September 30, 2014, from approximately $150 million for the nine months ended September 30, 2013. The increase was primarily due to higher salaries and benefits related expenses, primarily driven by increased employee headcount and unit-based compensation, higher professional services expenses, higher various other administrative expenses and higher non-payroll related acquisition expenses. General and administrative expenses per Mcfe also increased slightly to $0.70 per Mcfe for the nine months ended September 30, 2014, from $0.69 per Mcfe for the nine months ended September 30, 2013.

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

Exploration Costs

Exploration costs increased by approximately $5 million or 127% to approximately $10 million for the nine months ended September 30, 2014, from approximately $5 million for the nine months ended September 30, 2013. The increase was primarily due to higher leasehold impairment expenses on unproved properties.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization increased by approximately $228 million or 38% to approximately $833 million for the nine months ended September 30, 2014, from approximately $605 million for the nine months ended September 30, 2013. Higher total production volumes were the primary reason for the increased expense. Depreciation, depletion and amortization per Mcfe decreased to $2.63 per Mcfe for the nine months ended September 30, 2014, from $2.77 per Mcfe for the nine months ended September 30, 2013, primarily due to a lower rate in the Granite Wash formation as a result of the impairment recorded in the prior year.

Impairment of Long-Lived Assets

During the nine months ended September 30, 2014, the Company recorded a noncash impairment charge, before and after tax, of approximately $603 million associated with proved oil and natural gas properties in the Permian Basin region. The impairment was due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for the proved oil and natural gas properties. During the nine months ended September 30, 2013, the Company recorded a noncash impairment charge, before and after tax, of approximately $38 million associated with the write-down of the carrying value of the Panther Operated Cleveland Properties sold in May 2013 (see Note 2).

(Gains) Losses on Sale of Assets and Other, Net

During the nine months ended September 30, 2014, the Company recorded a net gain of approximately $45 million, including costs to sell of approximately $3 million, on the noncash exchange of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc., for properties in the Hugoton Basin (see Note 2).

Taxes, Other Than Income Taxes



	Nine Months Ended September 30,
	2014		2013		Variance
	(in thousands)

Severance taxes	$	105,867	$	69,463	$	36,404
Ad valorem taxes	81,635		38,696		42,939
California carbon allowances	13,328		266		13,062
Other	184		100		84
	$	201,014	$	108,525	$	92,489

Taxes, other than income taxes increased by approximately $92 million or 85% for the nine months ended September 30, 2014, compared to the nine months ended September 30, 2013. Severance taxes, which are a function of revenues generated from production, increased primarily due to higher production volumes and higher natural gas and NGL prices partially offset by lower oil prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, increased primarily due to the Berry acquisition and acquisitions during the third quarter of 2014. California carbon allowances increased primarily due to the Berry acquisition.

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

Other Income and (Expenses)



	Nine Months Ended September 30,
	2014			2013			Variance
	(in thousands)

Interest expense, net of amounts capitalized	$	(422,160	)	$	(308,012	)	$	(114,148	)
Loss on extinguishment of debt	—			(5,304		)	5,304
Other, net	(6,699		)	(6,300		)	(399		)
	$	(428,859	)	$	(319,616	)	$	(109,243	)

Other income and (expenses) increased by approximately $109 million for the nine months ended September 30, 2014, compared to the nine months ended September 30, 2013. Interest expense increased primarily due to higher outstanding debt during the period and higher amortization of financing fees and expenses associated with the Bridge Loan, the VIE Term Loan, the senior notes issued in September 2014 and amendments made to the Company’s Credit Facilities during 2013 and 2014. In addition, for the nine months ended September 30, 2013, the Company recorded a loss on extinguishment of debt of approximately $5 million as a result of the redemption of the remaining outstanding 2017 and 2018 Senior Notes. See “Debt” in “Liquidity and Capital Resources” below for additional details.

Income Tax Expense (Benefit)

The Company is a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized income tax expense of approximately $3 million and $2 million for the nine months ended September 30, 2014, and September 30, 2013, respectively. Income tax expense increased primarily due to higher income from the Company’s taxable subsidiaries during the nine months ended September 30, 2014, compared to the same period in 2013.

Net Income (Loss)

Net income decreased by approximately $390 million to a net loss of approximately $297 million for the nine months ended September 30, 2014, from net income of approximately $93 million for the nine months ended September 30, 2013. The decrease was primarily due to higher losses on oil and natural gas derivatives and higher impairment charges and other expenses, including interest, partially offset by higher production revenues. 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 nine months ended September 30, 2014, the Company’s total capital expenditures, excluding acquisitions, were approximately $1.2 billion. For 2014, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $1.6 billion, including approximately $1.55 billion related to its oil and natural gas capital program and approximately $35 million related to its plant and pipeline capital. This estimate reflects amounts for the development of properties associated with acquisitions (see Note 2), is under continuous review and subject to ongoing adjustments. The Company expects to fund these capital expenditures primarily with net cash provided by operating activities and bank borrowings. At September 30, 2014, there was approximately $1.2 billion of available borrowing capacity under the Company’s Credit Facilities but less than $1 million available under the Berry Credit Facility.

As the Company pursues growth, it continually monitors the capital resources available to meet future financial obligations and planned capital expenditures. The Company’s future success in growing reserves and production volumes will be highly dependent on the capital resources available and its success in drilling for or acquiring additional reserves. The Company actively reviews acquisition opportunities on an ongoing basis. If the Company were to make significant additional

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

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:



	Nine Months Ended September 30,
	2014			2013			Variance
	(in thousands)
Net cash:
Provided by operating activities	$	1,435,810		$	940,511		$	495,299
Used in investing activities	(3,836,033		)	(827,165		)	(3,008,868		)
Provided by (used in) financing activities	2,407,213			(87,109		)	2,494,322
Net increase in cash and cash equivalents	$	6,990		$	26,237		$	(19,247	)

Operating Activities

Cash provided by operating activities for the nine months ended September 30, 2014, was approximately $1.4 billion, compared to approximately $941 million for the nine months ended September 30, 2013. The increase was primarily due to higher production related revenues principally due to increased production volumes and higher natural gas and NGL prices, partially offset by higher expenses and lower cash settlements on derivatives.

Investing Activities

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



	Nine Months Ended September 30,
	2014			2013
	(in thousands)
Cash flow from investing activities:
Acquisition of oil and natural gas properties and joint-venture funding	$	(2,601,932	)	$	(192,871	)
Capital expenditures	(1,226,616		)	(844,591		)
Proceeds from sale of properties and equipment and other	(7,485		)	210,297
	$	(3,836,033	)	$	(827,165	)

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. The increase was primarily due to the Devon Assets Acquisition and Pioneer Assets Acquisition consummated during the nine months ended September 30, 2014, compared to no significant acquisitions of properties during the nine months ended September 30, 2013. See Note 2 for additional details of acquisitions. Capital expenditures increased primarily due to development activities of properties in the Rockies, California and Permian Basin regions. Proceeds from sale of properties and equipment and other for the nine months ended September 30, 2013, include approximately $218 million in net proceeds received for the sale of the Panther Operated Cleveland Properties in May 2013 (see Note 2).

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

Financing Activities

Cash provided by financing activities for the nine months ended September 30, 2014, was approximately $2.4 billion, compared to cash used in financing activities of approximately $87 million for the nine months ended September 30, 2013. The increase in financing cash flow needs was primarily attributable to increased acquisition activity during the nine months ended September 30, 2014. The following provides a comparative summary of proceeds from borrowings and repayments of debt:



	Nine Months Ended September 30,
	2014			2013
	(in thousands)
Proceeds from borrowings:
LINN Credit Facility	$	1,900,000		$	1,260,000
Senior notes	1,100,024			—
Bridge Loan and VIE Term Loan	2,300,000			—
	$	5,300,024		$	1,260,000
Repayments of debt:
LINN Credit Facility	$	(950,000	)	$	(735,000	)
Senior notes	(206,124		)	(54,898		)
Bridge Loan	(1,000,000		)	—
	$	(2,156,124	)	$	(789,898	)

Debt

In September 2014, the Company issued $1.1 billion in aggregate principal amount of senior notes consisting of $450 million in aggregate principal amount of 6.50% New May 2019 Senior Notes and $650 million in aggregate principal amount of 6.50% September 2021 Senior Notes (see Note 6). The Company used the net proceeds of approximately $1.1 billion to repay all indebtedness outstanding under its Bridge Loan and repay a portion of indebtedness under the LINN Credit Facility.

In August 2014, the Company entered into the Bridge Loan pursuant to which the Company borrowed an aggregate principal amount of $1.0 billion under a term loan. The proceeds from the Bridge Loan were advanced to a VIE and used to partially fund the Devon Assets Acquisition (see Note 2). In September 2014, the Company paid in full the outstanding indebtedness under the Bridge Loan using proceeds from the issuance of the New May 2019 Senior Notes and the September 2021 Senior Notes.

In August 2014, a subsidiary of the VIE formed to facilitate the Reverse 1031 Exchange for the Devon Assets Acquisition (see Note 2) entered into the VIE Term Loan pursuant to which it borrowed an aggregate principal amount of $1.3 billion under a term loan. The proceeds from the VIE Term Loan were used to partially fund the Devon Assets Acquisition.

The 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 $3.725 billion. At September 30, 2014, the borrowing base under the LINN Credit Facility was $4.225 billion and availability under the revolving credit facility was approximately $1.2 billion, which includes a $5 million reduction for outstanding letters of credit.

In April 2014, the Company entered into an amendment to the LINN Credit Facility to extend the maturity from April 2018 to April 2019, among other items, and in August 2014 and September 2014, the Company entered into amendments to the LINN Credit Facility to permit the Devon Assets Acquisition and the Pioneer Assets Acquisition, respectively, and the related Reverse 1031 Exchanges (see Note 2). As a result of the debt incurred under the Bridge Loan, the borrowing base was reduced by 25% of the gross proceeds from the Bridge Loan, or $250 million, to $4.25 billion, resulting in a reduction of availability under the revolving credit facility of $250 million. Additionally, upon the issuance of an aggregate $1.1 billion of senior notes in the September 2014 offering (see above), the borrowing base was further reduced by $25 million to $4.225 billion, resulting in a further reduction of availability under the revolving credit facility of $25 million.

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

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

The Company depends, in part, on its Credit Facilities for future capital needs. At September 30, 2014, there was approximately $1.2 billion of available borrowing capacity under the Company’s Credit Facilities but less than $1 million available under the Berry Credit Facility. In addition, the Company has drawn on the LINN Credit Facility to fund or partially fund cash distribution payments. Absent such borrowings, the Company would have at times experienced a shortfall in cash available to pay the declared cash distribution amount. If an event of default occurs and is continuing under the Credit Facilities, the Company would be unable to make borrowings to fund distributions. For additional information, see “Distribution Practices” below.

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

In February 2014, in accordance with the indentures related to Berry’s senior notes, the Company repurchased through cash tender offers $321,000, $30,000 and $837,000 of Berry’s June 2014 Senior Notes, November 2020 Senior Notes and September 2022 Senior Notes, respectively. On May 30, 2014, in accordance with the provisions of the indenture related to the Berry June 2014 Senior Notes, the Company paid in full the remaining outstanding principal amount of approximately $205 million.

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

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

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.

Distributions

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

acquisitions and anticipated future credit needs) or to fund distributions over the next four quarters. The following provides a summary of distributions paid by the Company during the nine months ended September 30, 2014:



Date Paid	Distributions Per Unit		Total Distributions
			(in millions)

September 2014	$	0.2416	$	80
August 2014	$	0.2416	$	80
July 2014	$	0.2416	$	80
June 2014	$	0.2416	$	80
May 2014	$	0.2416	$	80
April 2014	$	0.2416	$	80
March 2014	$	0.2416	$	80
February 2014	$	0.2416	$	80
January 2014	$	0.2416	$	80

On October 1, 2014, the Company’s Board of Directors declared a cash distribution of $0.725 per unit with respect to the third quarter of 2014, to be paid in three equal installments of $0.2416 per unit. The first monthly distribution with respect to the third quarter of 2014, totaling approximately $80 million, was paid on October 16, 2014, to unitholders of record as of the close of business on October 13, 2014.

Off-Balance Sheet Arrangements

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

Contingencies

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

Commitments and Contractual Obligations

The Company has contractual obligations for long-term debt, operating leases and other long-term liabilities that were summarized in the table of contractual obligations in the 2013 Annual Report on Form 10-K. With the exceptions of: (i) the Company’s payment of the remaining outstanding principal amount of the Berry June 2014 Senior Notes; (ii) an amendment to the LINN Credit Facility and term loan that extended the maturity dates from April 2018 to April 2019; (iii) an amendment to the Berry Credit Facility that extended the maturity date from May 2016 to April 2019; (iv) the issuance of $1.1 billion aggregate principal amount of senior notes consisting of $450 million in aggregate principal amount of 6.50% New May 2019 Senior Notes and $650 million in aggregate principal amount of 6.50% September 2021 Senior Notes; and (v) the incurrence by a subsidiary of the consolidated VIE of $1.3 billion in aggregate principal amount under a term loan, there have been no significant changes to the Company’s contractual obligations from December 31, 2013. See Note 6 for additional information about the Company’s debt instruments.

Distribution Practices

The Company’s Board of Directors determines the appropriate level of distributions on a periodic basis in accordance with the provisions of the Company’s limited liability company agreement. Management considers the timing and size of planned capital expenditures and long-term views about expected results in determining the amount of its distributions. Capital spending and resulting production and net cash provided by operating activities do not typically occur evenly throughout the year due to a variety of factors which are difficult to predict, including rig availability, weather, well performance, the timing of completions and the commodity price environment. Consistent with practices common to publicly traded partnerships, the Company’s Board of Directors historically has not varied the distribution it declares from period to period based on uneven net cash provided by operating activities. The Company’s Board of Directors reviews historical financial results and forecasts for future periods, including development activities, as well as considers the impact of significant acquisitions in making a determination to increase, decrease or maintain the current level of distribution. To date in 2014, the Company’s Board of

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

Directors has considered past shortfalls and the current excess of net cash provided by operating activities after distributions and discretionary adjustments as well as forecasts of expected future net cash provided by operating activities and has decided to maintain the distribution at its current level. If shortfalls are sustained over time and forecasts demonstrate expectations for continued future shortfalls, the Company’s Board of Directors may determine to reduce, suspend or discontinue paying distributions.

The Company intends to fund interest expense, a portion of its oil and natural gas development costs and distributions to unitholders from net cash provided by operating activities. The Company funds premiums paid for derivatives, acquisitions and other capital expenditures primarily with proceeds from debt or equity offerings, borrowings under the LINN Credit Facility or other external sources of funding. Although it is the Company’s practice to acquire or modify derivative instruments with external sources of funding, any cash settlements on derivatives are reported as operating cash flows and may be used to fund distributions. See below for details regarding the discretionary adjustments considered by the Company’s Board of Directors in assessing the appropriate distribution amount for each period, as well as the extent to which sources of funding have been sufficient for the periods presented:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)

Net cash provided by operating activities	$	520,175		$	379,155		$	1,435,810		$	940,511
Distributions to unitholders	(240,652		)	(170,569		)	(721,235		)	(511,686		)
Excess of net cash provided by operating activities after distributions to unitholders	279,523			208,586			714,575			428,825
Discretionary adjustments considered by the Board of Directors:
Discretionary reductions for a portion of oil and natural gas development costs ⁽¹⁾	(213,252		)	(115,659		)	(606,120		)	(337,869		)
Cash recoveries of bankruptcy claim ⁽²⁾	—			—			(2,913		)	(5,073		)
Cash received (paid) for acquisitions or divestitures – revenues less operating expenses ⁽³⁾	79,555			(233		)	79,555			(7,023		)
Provision for legal matters ⁽⁴⁾	—			1,000			1,598			1,000
Changes in operating assets and liabilities and other, net ⁽⁵⁾	(57,443		)	(91,401		)	(69,249		)	(116,031		)
Excess (shortfall) of net cash provided by operating activities after distributions to unitholders and discretionary adjustments considered by the Board of Directors ⁽⁶⁾	$	88,383		$	2,293		$	117,446		$	(36,171	)

⁽¹⁾

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

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

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)

Total development of oil and natural gas properties	$	370,861	$	271,705	$	1,176,478	$	767,604


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

⁽³⁾

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


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

⁽⁵⁾

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


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

Any cash generated by Berry is currently being used by Berry to fund its activities and is not currently being distributed to LINN Energy for further distribution to its unitholders. To the extent that Berry generates cash in excess of its needs, the indentures governing Berry’s senior notes limit the amount it may distribute to LINN Energy to the amount available under a “restricted payments basket,” and Berry may not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Berry indentures. Berry’s restricted payments basket was approximately $314 million at September 30, 2014, and may be increased in accordance with the terms of the Berry indentures by, among other things, 50% of Berry’s future net income, reductions in its indebtedness and restricted investments, and future capital contributions.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)

Net cash provided by operating activities	$	520,175		$	379,155		$	1,435,810		$	940,511
Distributions to unitholders	(240,652		)	(170,569		)	(721,235		)	(511,686		)
Excess of net operating cash flow after distributions to unitholders	279,523			208,586			714,575			428,825
Plus (less):
Net cash provided by financing activities (excluding distributions to unitholders)	2,702,683			240,379			3,128,448			424,577
Acquisition of oil and natural gas properties and joint-venture funding	(2,576,041		)	(128,490		)	(2,601,932		)	(192,871		)
Development of oil and natural gas properties	(370,861		)	(271,705		)	(1,176,478		)	(767,604		)
Purchases of other property and equipment	(18,727		)	(21,840		)	(50,138		)	(76,987		)
Proceeds from sale of properties and equipment and other	4,245			(602		)	(7,485		)	210,297
Net increase in cash and cash equivalents	$	20,822		$	26,328		$	6,990		$	26,237

Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

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

Cautionary Statement

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


•	business strategy;


•	acquisition strategy;


•	financial strategy;


•	effects of the pending SEC inquiry and other legal proceedings;


•	ability to maintain or grow distributions;


•	drilling locations;


•	oil, natural gas and NGL reserves;


•	realized oil, natural gas and NGL prices;


•	production volumes;


•	capital expenditures;


•	economic and competitive advantages;


•	credit and capital market conditions;


•	regulatory changes;


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


•	future operating results, including results of acquired properties;


•	plans, objectives, expectations and intentions; and


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

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

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

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

December 31, 2013, 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 2013 Annual Report on Form 10-K. The reference to a “Note” herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1. “Financial Statements.”

Commodity Price Risk

An important part of the Company’s business strategy includes hedging a significant portion of its forecasted production to reduce exposure to fluctuations in the prices of oil and natural gas and provide long-term cash flow predictability to manage its business, service debt and pay distributions. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. As a result, currently, the Company directly hedges only its oil and natural gas production. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in net cash provided by operating activities due to fluctuations in commodity prices.

The Company enters into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production to provide an economic hedge of the risk related to the future commodity prices received. As part of the acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC (“Berry”) (see Note 2), 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. The Company did not purchase any put options in 2013 or to date in 2014. The Company has not entered into any new commodity derivative positions to date in 2014.

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

The Company does not enter into derivative contracts for trading purposes. There have been no significant changes to the Company’s objectives, general strategies or instruments used to manage the Company’s commodity price risk exposures from the year ended December 31, 2013.

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

At September 30, 2014, the fair value of fixed price swaps, put option contracts, collars and three-way collars was a net asset of approximately $619 million. A 10% increase in the index oil and natural gas prices above the September 30, 2014, prices would result in a net asset of approximately $27 million, which represents a decrease in the fair value of approximately $592 million; conversely, a 10% decrease in the index oil and natural gas prices below September 30, 2014, prices would result in a net asset of approximately $1.2 billion, which represents an increase in the fair value of approximately $608 million.

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

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 September 30, 2014, and December 31, 2013, and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

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

Interest Rate Risk

At September 30, 2014, the Company had long-term debt outstanding under its credit facilities and term loans of approximately $5.5 billion which incurred interest at floating rates (see Note 6). A 1% increase in the London Interbank Offered Rate (“LIBOR”) would result in an estimated $55 million increase in annual interest expense.

At December 31, 2013, the Company had long-term debt outstanding under its credit facilities and term loans of approximately $3.2 billion which incurred interest at floating rates. A 1% increase in the LIBOR would result in an estimated $32 million increase in annual interest expense.

Counterparty Credit Risk

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

At September 30, 2014, the average public bond yield spread utilized to estimate the impact of the Company’s credit risk on derivative liabilities was approximately 2.05%. A 1% increase in the average public bond yield spread would result in an estimated $1 million increase in net income for the nine months ended September 30, 2014. At September 30, 2014, the credit default swap spreads utilized to estimate the impact of counterparties’ credit risk on derivative assets ranged between 0% and 2.06%. A 1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $7 million decrease in net income for the nine months ended September 30, 2014.

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

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

1% increase in each of the counterparties’ credit default swap spreads would result in an estimated $16 million decrease in net income for the year ended December 31, 2013.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, and the Company’s Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the 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 September 30, 2014.

Changes in the Company’s Internal Control Over Financial Reporting

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

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

There were no changes in the Company’s internal controls over financial reporting during the third quarter of 2014 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting. The Company continues to integrate certain business operations, information systems, processes and related internal control over financial reporting as a result of the acquisition of Berry Petroleum Company, now Berry Petroleum Company, LLC. The Company will continue to assess the effectiveness of its internal control over financial reporting as integration activities continue.

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Part II - Other Information


Item 1.	Legal Proceedings

In July 2014, the Court dismissed the claims of the plaintiffs in the Federal Actions with prejudice, concluding that the plaintiffs failed to demonstrate any material misstatement or omission by LINN Energy or LinnCo, or their officers and directors. The plaintiffs in the Federal Action did not appeal the Court’s dismissal, and the appeals deadline has now passed. The plaintiffs in the Derivative Actions subsequently have dismissed their claims without prejudice.


Item 1A.	Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, results of operations, liquidity or the trading price of our units are described in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013. Except as set forth below, as of the date of this report, these risk factors have not changed materially. This information should be considered carefully, together with other information in this report and other reports and materials we file with the United States Securities and Exchange Commission.

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

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

For example, we may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the proceeds to our unitholders, and some or all of our unitholders may be allocated substantial taxable income

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Item 1A. Risk Factors - Continued

with respect to that sale. A unitholder’s share of our taxable income upon a disposition of property by us may be ordinary income or capital gain or some combination thereof. Even where we dispose of properties that are capital assets, what otherwise would be capital gains may be recharacterized as ordinary income in order to “recapture” ordinary deductions that were previously allocated to that unitholder related to the same property.

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

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


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

Issuer Purchases of Equity Securities

In August 2014, the Board of Directors of the Company authorized the repurchase of up to $250 million of the Company’s outstanding units. The repurchase plan does not obligate the Company to acquire any specific number of units and may be discontinued at any time. The Company did not repurchase any units during the quarter ended September 30, 2014, and at September 30, 2014, 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

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Item 5.	Other Information

None

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Item 6.	Exhibits



Exhibit Number		Description

2.1*†	—	Exchange Agreement by and among Linn Energy Holdings, LLC, Berry Petroleum Company, LLC and Exxon Mobil Corporation, dated as of September 18, 2014
2.2*†	—	Purchase and Sale Agreement by and between Linn Energy Holdings, LLC, Linn Operating, Inc., Linn Exploration Mid-Continent, LLC, Mid-Continent II, LLC and Linn Midstream, LLC as Seller, and EnerVest Energy Institutional Fund XIII-A, L.P., EnerVest Energy Institutional Fund XIII-WIB, L.P., EnerVest Energy Institutional Fund XIII-WIC, L.P., and FourPoint Energy, LLC as Buyer, executed on October 2, 2014
4.1	—	First Supplemental Indenture relating to 6.500% senior notes due 2019, dated September 9, 2014, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U. S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on September 9, 2014)
4.2	—	Senior Indenture, dated September 9, 2014, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U. S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to Current Report on Form 8-K filed on September 9, 2014)
4.3	—	First Supplemental Indenture relating to 6.500% senior notes due 2021, dated September 9, 2014, among Linn Energy, LLC, Linn Energy Finance Corp., the Subsidiary Guarantors named therein and U. S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to Current Report on Form 8-K filed on September 9, 2014)
10.1*	—	Fourth Amendment to Sixth Amended and Restated Credit Agreement, dated as of August 6, 2014, among Linn Energy, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders and agents party thereto
10.2*	—	Fifth Amendment to Sixth Amended and Restated Credit Agreement, dated as of September 10, 2014, among Linn Energy, LLC as Borrower, Wells Fargo Bank, National Association as Administrative Agent, and the Lenders and agents party thereto
10.3	—	Bridge Loan Agreement, dated August 29, 2014, by and among Linn Energy, LLC, certain subsidiary guarantors party thereto, each of the other lenders party thereto and The Bank of Nova Scotia, as administrative agent (incorporated herein by reference to Exhibit 10.1 to Post-Effective Amendment No. 1 to Registration Statement on Form S-3 (File No. 333-184647) filed by Linn Energy, LLC on September 4, 2014)
10.4	—	Term Loan Agreement, dated August 29, 2014, by and among Linn Exchange Properties, LLC, each of the other lenders party thereto, and The Bank of Nova Scotia, as administrative agent (incorporated herein by reference to Exhibit 10.2 to Post-Effective Amendment No. 1 to Registration Statement on Form S-3 (File No. 333-184647) filed by Linn Energy, LLC on September 4, 2014)
31.1*	—	Section 302 Certification of Mark E. Ellis, Chairman, President and Chief Executive Officer of Linn Energy, LLC
31.2*	—	Section 302 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
32.1*	—	Section 906 Certification of Mark E. Ellis, Chairman, President and Chief Executive Officer of Linn Energy, LLC
32.2*	—	Section 906 Certification of Kolja Rockov, Executive Vice President and Chief Financial Officer of Linn Energy, LLC
101.INS**	—	XBRL Instance Document
101.SCH**	—	XBRL Taxonomy Extension Schema Document
101.CAL**	—	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	—	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	—	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	—	XBRL Taxonomy Extension Presentation Linkbase Document


*	Filed herewith.


**	Furnished herewith.


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

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SIGNATURE

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



	LINN ENERGY, LLC
	(Registrant)

Date: November 4, 2014	/s/ David B. Rottino
	David B. Rottino
	Executive Vice President, Business Development and Chief Accounting Officer
	(As Duly Authorized Officer and Chief Accounting Officer)

ROAN RESOURCES, INC. - FORM 10-Q - November 4, 2014

Attached files

ROAN RESOURCES, INC. Reports